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, 2020
	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)

918-573-2000

(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. ☑

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 $23,078,419,375.

The number of shares outstanding of the registrant’s common stock outstanding at February 19, 2021 was 1,213,790,391.

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 27, 2021, 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	4
	General	4
	Service Assets, Customers, and Contracts	5
	Business Segments	7
	Transmission & Gulf of Mexico	8
	Northeast G&P	11
	West	13
	Other	15
	Regulatory Matters	15
	Environmental Matters	18
	Competition	18
	Human Capital Resources	19
	Website Access to Reports and Other Information	21
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	36
Item 2.	Properties	37
Item 3.	Legal Proceedings	37
Item 4.	Mine Safety Disclosures	37
	Information About Our Executive Officers	38
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	40
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 8.	Financial Statements and Supplementary Data	66
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	138
Item 9A.	Controls and Procedures	138
Item 9B.	Other Information	141
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	141
Item 11.	Executive Compensation	141
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	141
Item 13.	Certain Relationships and Related Transactions, and Director Independence	142
Item 14.	Principal Accountant Fees and Services	142
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	143
Item 16.	Form 10-K Summary	152

1

DEFINITIONS

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

Measurements:

Barrel: 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

Tbtu: One trillion 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:

Caiman II: Caiman Energy II, LLC, (renamed Blue Racer Midstream Holdings, LLC, effective February 2, 2021) a former equity-method investment which is a consolidated entity following our November 2020 acquisition of an additional ownership interest

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

Gulfstar One: Gulfstar One LLC

Northwest Pipeline: Northwest Pipeline LLC

Transco: Transcontinental Gas Pipe Line Company, LLC

UEOM: Utica East Ohio Midstream LLC, previously a Partially Owned Entity until acquiring remaining interest in March 2019

Northeast JV: Ohio Valley Midstream LLC, a partially owned venture that includes our Ohio Valley assets and UEOM

WPZ: Williams Partners L.P. Effective August 10, 2018, we completed our merger with WPZ, pursuant to which we acquired all outstanding common units of WPZ held by others and Williams continued as the surviving entity.

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of December 31, 2020, we account for as equity-method investments, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

Blue Racer: Blue Racer Midstream LLC

Constitution: Constitution Pipeline Company, LLC

Discovery: Discovery Producer Services LLC

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

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Jackalope: Jackalope Gas Gathering Services, L.L.C., which was sold in April 2019

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

FERC: Federal Energy Regulatory Commission

IRS: Internal Revenue Service

SEC: Securities and Exchange Commission

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

WPZ Merger: The August 10, 2018, merger transactions pursuant to which we acquired all outstanding common units of WPZ held by others, merged WPZ into Williams, and Williams continued as the surviving entity.

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.

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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 infrastructure company committed to be the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy. We have operations in 15 supply areas that provide natural gas gathering, processing, and transmission services and natural gas liquids fractionation, transportation, and storage services to more than 600 customers. We own an interest in and operate over 30,000 miles of pipelines, 34 processing facilities, 9 fractionation facilities, and approximately 23 million barrels of NGL storage capacity, handling approximately 30 percent of the nation’s natural gas volumes.

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 Salt Lake City, Utah; Houston, Texas; and Pittsburgh, Pennsylvania. Our telephone number is 918-573-2000.

4

Service Assets, Customers, and Contracts

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 through the FERC’s ratemaking process.

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. 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, and are not exposed to crude oil prices. Additionally, we offer storage services and interruptible transportation services under shorter-term agreements. Transco’s and Northwest Pipeline’s three largest customers in 2020 accounted for approximately 28 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

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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, 2020, approximately 80 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, 2020, approximately 20 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 2020, our facilities gathered and processed gas and crude oil for approximately 230 customers. Our top ten customers accounted for approximately 73 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.

Crude Oil Transportation and Production Handling Assets

Our crude oil transportation operations, which are presented in our Transmission & Gulf of Mexico segment as described under the heading “Business Segments,” earn revenues typically by volumetric-based fee arrangements. Revenue sources have historically included a combination of fixed-fee, volumetric-based fee, and cost reimbursement arrangements. Generally, fixed fees associated with the production at our Gulf Coast production handling facilities are recognized on a units-of-production basis. Certain fixed fees associated with the production at our Gulfstar One facility are recognized based on contractually determined maximum daily quantities. Our crude oil transportation business is supported mostly by major oil producers with long-cycle perspectives.

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Key variables for all of 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.

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, and West.

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, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated variable interest entity), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.

•Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 99 percent interest in Caiman II (a former equity-method investment which is a consolidated entity following our November 2020 acquisition of an additional ownership interest) which owns a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.

•West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, and Permian basins. This segment also includes our NGL and natural gas marketing business, 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, and a 20 percent equity-method investment in Targa Train 7.

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

Detailed discussion of each of our reporting 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.

7

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, 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 Texas, Louisiana, Mississippi, and Alabama. This segment also includes various petrochemical and feedstock pipelines in the Gulf Coast region.

Transco

Transco is an interstate natural gas transmission company that owns and operates a 9,800-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, 2020, Transco’s system had a system-wide delivery capacity totaling approximately 17.9 MMdth/d. During 2020, Transco completed one fully-contracted expansion and began partial early service on two additional fully-contracted expansions, which added more than 0.5 MMdth of firm transportation capacity per day to our pipeline. Transco’s system includes 57 compressor stations, four underground storage fields, and one LNG storage facility. Compression facilities at sea level-rated capacity total approximately 2.3 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 194 MMdth of natural gas. At December 31, 2020, Transco’s customers had stored in its facilities approximately 148 MMdth 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, 2020, Northwest Pipeline’s system had long-term firm transportation and storage redelivery agreements with aggregate capacity reservations of approximately 3.8 MMdth/d. Northwest Pipeline’s system includes 42 transmission compressor stations having a combined sea level-rated capacity of approximately 473,000 horsepower.

Northwest Pipeline owns a one-third undivided interest in the Jackson Prairie underground storage facility in Washington and contracts with a third party for natural gas storage services in the Clay basin underground field in Utah. Northwest Pipeline also owns and operates an LNG storage facility in Washington. These storage facilities have an aggregate working natural gas storage capacity of 14.2 MMdth, 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.

8

Gas Transportation, Processing, and Treating Assets

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

	Offshore Natural Gas Pipelines
			Inlet
		Pipeline	Capacity	Ownership
	Location	Miles	(Bcf/d)	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	103	0.4	100%	Western Gulf of Mexico
Non-consolidated: (1)
Discovery	Central Gulf of Mexico	594	0.6	60%	Western Gulf of Mexico

	Natural Gas Processing Facilities
			NGL
		Inlet	Production
		Capacity	Capacity	Ownership
	Location	(Bcf/d)	(Mbbls/d)	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
Non-consolidated: (1)
Discovery	Larose, LA	0.6	32	60%	Western 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.

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

	Crude Oil Pipelines
	Pipeline	Capacity	Ownership
	Miles	(Mbbls/d)	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

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	Production Handling Platforms
			Crude/NGL
		Gas Inlet	Handling
		Capacity	Capacity	Ownership
		(MMcf/d)	(Mbbls/d)	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%	Western 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

	2020	2019	2018
Consolidated:
Interstate natural gas pipeline throughput (Tbtu/d)	15.1	15.3	14.0
Gathering volumes (Bcf/d)	0.25	0.25	0.26
Plant inlet natural gas volumes (Bcf/d)	0.48	0.54	0.50
NGL production (Mbbls/d) (2)	29	32	32
NGL equity sales (Mbbls/d) (2)	5	7	6
Crude oil transportation (Mbbls/d) (2)	121	136	140
Non-consolidated: (1)
Interstate natural gas pipeline throughput (Tbtu/d)	1.2	1.2	1.3
Gathering volumes (Bcf/d)	0.30	0.36	0.26
Plant inlet natural gas volumes (Bcf/d)	0.30	0.36	0.27
NGL production (Mbbls/d) (2)	21	25	20
NGL equity sales (Mbbls/d) (2)	6	6	4

_____________

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

(2)Annual average Mbbls/d.

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 1.3 Bcf/d. We own, through a subsidiary, 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.

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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:

	Natural Gas Gathering Assets
			Inlet
		Pipeline	Capacity	Ownership
	Location	Miles	(Bcf/d)	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	0.5	65%	Appalachian
Susquehanna Supply Hub	Pennsylvania & New York	462	4.3	100%	Appalachian
Cardinal (1)	Ohio	378	0.8	66%	Appalachian
Flint	Ohio	95	0.5	100%	Appalachian
Non-consolidated: (3)
Bradford Supply Hub	Pennsylvania	733	4.0	66%	Appalachian
Marcellus South	Pennsylvania & West Virginia	325	1.0	68%	Appalachian
Laurel Mountain	Pennsylvania	1,145	0.9	69%	Appalachian
Blue Racer	West Virginia & Ohio	723	1.5	50%	Appalachian

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

(2)UEOM inlet capacity consists of 1.3 Bcf/d of a high pressure gathering pipeline that delivers Cardinal gathering volumes to UEOM processing facilities. The listed inlet capacity of 0.5 Bcf/d is incremental capacity to the Cardinal gathering capacity of 0.8 Bcf/d.

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

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, and an ethane transportation 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

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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 pipeline and fractionated at either our Moundsville or Harrison County, Ohio, fractionation facility. The resulting products are then transported on truck or rail. 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

	2020	2019	2018
Consolidated:
Gathering volumes (Bcf/d)	4.31	4.24	3.63
Plant inlet natural gas volumes (Bcf/d)	1.32	1.04	0.52
NGL production (Mbbls/d) (1)	101	76	46
NGL equity sales (Mbbls/d) (1)	2	3	4
Non-consolidated: (2)
Gathering volumes (Bcf/d)	4.78	4.29	3.76

__________

(1)    Annual average Mbbls/d.

(2)    Includes 100 percent of the volumes associated with operated equity-method investments, including the Laurel Mountain Midstream partnership; and the Bradford Supply Hub and a portion of the Marcellus South Supply Hub within Appalachia Midstream Investments. Beginning November 18, 2020, we operate Blue Racer. Blue Racer gathering volumes of 1.38 Bcf/d, plant inlet natural gas volumes of 0.95 Bcf/d, NGL production of 65 Mbbls/d, and NGL equity sales of 6 Mbbls/d have been excluded.

Acquisition of UEOM and formation of Northeast JV

As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM. As a result of acquiring this additional interest, we obtained control of and now consolidate UEOM. (See Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

In June 2019, we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership, and we retained 65 percent ownership of, as well as operate and consolidate, the Northeast JV business.

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 1,058 miles of gathering pipeline in the Marcellus Shale region with the capacity to gather 5,031 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.

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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.

Blue Racer

As of December 31, 2019, we effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent interest in Caiman II, whose primary asset is a 50 percent interest in Blue Racer. On November 18, 2020, we paid $157 million, net of cash acquired, to acquire an additional 41 percent ownership interest in Caiman II. We now control and consolidate Caiman II, reporting the 50 percent interest in Blue Racer 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 723 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 service primarily under percentage 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	(1)	Piceance
Barnett Shale	Texas	840	0.5	100%	Barnett Shale
Eagle Ford Shale	Texas	1,280	0.5	100%	Eagle Ford Shale
Haynesville Shale	Louisiana	629	1.8	100%	Haynesville Shale
Permian	Texas	103	0.1	100%	Permian
Mid-Continent	Oklahoma & Texas	2,248	0.9	100%	Miss-Lime, Granite Wash, Colony Wash, Arkoma
Non-consolidated: (2)
Rocky Mountain Midstream	Colorado	200	0.6	50%	Denver-Julesburg

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	Natural Gas Processing Facilities
			NGL
		Inlet	Production
		Capacity	Capacity	Ownership
	Location	(Bcf/d)	(Mbbls/d)	Interest	Supply Basins
Consolidated:
Echo Springs	Echo Springs, WY	0.7	58	100%	Wamsutter
Opal	Opal, WY	1.1	47	100%	Southwest Wyoming
Willow Creek	Rio Blanco County, CO	0.5	30	100%	Piceance
Parachute	Garfield County, CO	1.1	6	100%	Piceance
Non-consolidated: (2)
Fort Lupton	Colorado	0.3	50	50%	Denver-Julesburg
Keenesburg I	Colorado	0.2	40	50%	Denver-Julesburg

_______________

(1)Includes our 60 percent ownership of a gathering system in the Ryan Gulch area with 140 miles of pipeline and 0.2 Bcf/d of inlet capacity, and our 67 percent ownership of a gathering system at Allen Point with 8 miles of pipeline and 0.1 Bcf/d of inlet capacity. We operate both systems. We own and operate 100 percent of the balance of the Piceance gathering assets.

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

Marketing Services

We market gas and NGL products to a wide range of users in the energy and petrochemical industries. The NGL marketing business transports and markets our equity NGLs from the production at our processing plants, and also markets NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, and the NGL volumes owned by Discovery and RMM. 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.

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 20 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

	2020	2019	2018
Consolidated: (1)
Gathering volumes (Bcf/d)	3.33	3.52	4.27
Plant inlet natural gas volumes (Bcf/d)	1.25	1.48	2.01
NGL production (Mbbls/d) (2)	49	54	84
NGL equity sales (Mbbls/d) (2)	22	22	33
Non-Consolidated: (3)
Gathering volumes (Bcf/d)	0.25	0.20	0.08
Plant inlet natural gas volumes (Bcf/d)	0.25	0.20	0.08
NGL production (Mbbls/d) (2)	23	12	3

________________

(1)    2020 and 2019 volumes reflect the absence of Four Corners assets due to the sale in October 2018.

(2)    Annual average Mbbls/d.

(3)    Includes 100 percent of the volumes associated with operated equity-method investments, including RMM and Jackalope. Jackalope was a consolidated entity in first- and second-quarter 2018, an equity-method investment during third- and fourth-quarter 2018 as well as first-quarter 2019, and sold effective with second-quarter 2019.

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Sale of Four Corners Assets

In October 2018, we completed the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado. The system was comprised of 3,742 miles of gathering pipeline with 1.8 Bcf/d of gas gathering inlet capacity and two processing facilities with a combined 0.7 Bcf/d of natural gas processing inlet capacity and 41 Mbbls/d of NGL production capacity.

Certain Equity-Method Investments

Overland Pass Pipeline

We also 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

During the third quarter of 2018, our joint venture, RMM, purchased a natural gas and crude oil gathering and natural gas processing business in Colorado’s Denver-Julesburg basin. As of December 31, 2020, we operate and own 50 percent of RMM. RMM includes a natural gas gathering pipeline and an approximate 80-mile crude oil transportation pipeline. It also includes crude oil storage assets.

Targa Train 7

We own a 20 percent interest in Targa Train 7, a Mt. Belvieu fractionation train, which was placed into service in the first quarter of 2020.

Other

Other includes certain previously owned operations, minor business activities that are not reportable segments, as well as corporate operations.

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 do business with gas marketing employees. Among other things, the Standards of Conduct require that interstate gas pipelines not operate their systems to preferentially benefit gas marketing functions.

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;

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•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.

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 (Pipeline Safety Act), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016, 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.

In 2016, PHMSA published a proposed rulemaking that would impose new or more stringent requirements for certain natural gas pipelines including, expanding certain of PHMSA’s current regulatory safety programs for natural gas lines in high-population areas (also known as moderate consequence areas (MCAs)) that do not qualify as high-consequence areas (HCAs) and requiring maximum allowable operating pressure (MAOP) validation through re-verification of all historical records for pipelines in service, which may require natural gas pipelines installed before 1970 (previously excluded from certain pressure testing obligations) to be pressure tested. However, PHMSA has since decided to split this proposed rule (Mega Rule), into three separate rulemaking proceedings. The first of these three rulemakings, relating to onshore gas transmission pipelines, was published as a final rule on October 1, 2019, and imposes numerous requirements, including MAOP reconfirmation, the periodic assessment of additional pipeline mileage outside of HCAs, the reporting of exceedances of MAOP, and the consideration of seismicity as a risk factor in integrity management. In accordance with the final rule, we have developed new procedures and updated our existing pipeline safety program to facilitate meeting all requirements within the time frames stated. The remaining rulemakings comprising the Mega Rule are expected to be issued in 2021 and will include revised pipeline repair criteria as well as more stringent corrosion control requirements.

PHMSA also published new or more stringent rules for onshore hazardous liquids transportation lines in October 2019 requiring integrity assessments on all onshore pipe that accommodate inline inspection tools.

We are also expecting additional regulations due to new pipeline safety legislation finalized in December 2020 that reauthorized PHMSA pipeline safety programs. The new legislation includes mandates for PHMSA to publish final rules for advanced leak detection for gas pipelines, additional repair criteria for gas and hazardous liquids pipelines, updated operating and maintenance standards requirements applicable to large-scale liquefied natural gas facilities, certain Coastal Waters and Coastal Beaches to be designated as USA ecological resources for purposes of

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determining whether a hazardous liquid pipeline is in a high consequence area, and the gas gathering portion of the proposed Mega Rule.

New regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.

Pipeline Integrity Regulations

We have an enterprise-wide Gas 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 gas pipeline operators to develop an integrity management program for gas 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 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. We estimate that the cost to be incurred in 2021 associated with this program to be approximately $105 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 2021 associated with this program will be approximately $3 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.

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, 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 Public Service Commission, 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 II, Item 8. Financial Statements and Supplementary Data — Note 19 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements for further details on our regulatory matters. For additional information regarding regulatory matters, please also refer to Part 1, Item 1A. “Risk Factors” — “The

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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.”

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 19 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.

COMPETITION

Gas Pipeline Business

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 rates, reliability, quality of customer service, diversity of supply, and proximity to customers and market hubs.

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

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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.

Midstream Business

Competition for natural gas gathering, processing, treating, transporting, and storing natural gas 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.

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 an 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, 2021, we had 4,739 full-time employees located throughout the United States. Of this total, approximately 21 percent are women and more than 14 percent are ethnically diverse. During 2020, our voluntary turnover rate was 4.6 percent.

We encourage you to review our 2019 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 references into this Annual Report on Form 10-K.

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 achieve better performance than the industry benchmark. When a safety hazard is recognized, every employee is empowered to stop work activities and make it right. Safety and environmental-focused goals and related metrics comprise 10 percent of our annual incentive program for employees, providing an increased focus on activities that help us meet enterprise safety commitments.

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For 2019, these metrics included our Near Miss to Incident Ratio, emphasizing our safety focus on hazard recognition and reinforcing the importance of incident prevention, and our Late Post Startup Deliverables metric, emphasizing the importance of completing all post startup deliverables associated with newly completed projects. As disclosed in our 2020 Proxy Statement, we exceeded our targets for these safety metrics in 2019, achieving a Near Miss to Incident ratio of 13.98:1, versus a target between 9:1 and 10:1, and less than 1 percent of Late Post Startup Deliverables, versus a target between 3 percent and 4 percent. For 2020, these metrics include our High Potential Near Miss to Incident Ratio, again emphasizing our safety focus on high potential hazard recognition and reinforcing the importance of incident prevention, and our environmental metric Loss of Primary Containment, focused on reducing greenhouse gases and considered a leading indicator to more significant process safety incidents.

Workforce Health & Development

Our employees are our most valued resource and 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 a wellness program. We provide employees with company-paid life insurance, disability coverage, and paid parental leave for both birth and non-birth parents. 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 an environment where employees feel fulfilled and supported in their personal and professional development. We offer robust corporate and technical training programs to support the professional development of our employees and add long-term value to our business. Additionally, we support strong employee engagement by encouraging open dialogue regarding professional 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.

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.

In response to the ongoing impact of COVID-19, we took action to safeguard the health and safety of our employees, including allowing our employees to work remotely where possible, while implementing safety guidance and best practices designed to protect the health of those entering our facilities.

Diversity & Inclusion

We encourage a diverse and inclusive workforce, helping our employees reach their full potential and promoting innovation. By embracing differences—whether race, gender, nationality, ability, orientation, or generation—we bring the best out of our people to drive business growth and long-term success.

To support networking and professional development opportunities, we endorse employee resource groups, which allow more inclusivity by offering an opportunity for employees to network, gain development, and provide input to leaders on specific needs. We strive for diverse representation at all levels through our talent management practices and employee development programs as we are committed to helping all employees develop. Diversity metrics are reported monthly to our management team.

We also have a Diversity and Inclusion Council, chaired by our chief executive officer and including members of the executive officer team, organizational and operational leaders, and individual employees, to promote 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.

Our Board of Directors includes 12 independent members, one-third of which are women. As part of the director selection and nominating process, the Governance and Sustainability Committee annually assesses the

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Board’s diversity in such areas as geography, race, gender, 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.

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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 of 1933, as amended (Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended. 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;

•The impact of the coronavirus (COVID-19) pandemic.

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 liabilities, 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;

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•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 to 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;

•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 Securities and Exchange Commission.

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.

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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 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 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.

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 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;

•Turmoil in the Middle East and other producing regions;

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

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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 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 Partially Owned Entities, which may limit our ability to operate and control these subsidiaries. Certain operations, including the Partially Owned 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 Partially Owned Entities, are conducted in accordance with their organizational documents. We anticipate that we will enter into more such arrangements, including through new joint venture structures or new Partially Owned Entities. We may have limited

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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.

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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, certain 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 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

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ESG procedures or standards do not meet the standards set by certain constituencies. We have adopted certain practices as highlighted in our 2019 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 environment, 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;

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•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.

We face risks related to the COVID-19 pandemic and other health epidemics

The global outbreak of the coronavirus (COVID-19) is currently impacting countries, communities, supply chains, and markets. We provide a critical service to our customers, which means that it is paramount that we keep our employees safe. We cannot predict whether, and the extent to which, COVID-19 will have a material impact on our business, including our liquidity, financial condition, and results of operations. COVID-19 poses a risk to our employees, our customers, our suppliers, and the communities in which we operate, which could negatively impact our business. To the extent that our access to the capital markets is adversely affected by COVID-19, we may need to consider alternative sources of funding for our operations and for working capital, any of which could increase our cost of capital. Measures to try to contain the virus, such as travel bans and restrictions, quarantines, shelter in place orders, and shutdowns, may cause us to experience operational delays or to delay plans for growth. The extent to which COVID-19 may impact our business will depend on future developments, which are highly uncertain and cannot be predicted, including new information concerning the severity of COVID-19 and the actions taken to contain it or treat its impact, among others. To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other factors described in this report.

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. 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

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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 facilities, or other disruptions including those arising from theft, vandalism, fraud, or unethical conduct, 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

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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 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. 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, 2020, was $22.3 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.

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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;

•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 14 – 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.

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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 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;

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•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.

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”)

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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 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, 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.

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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.

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 are exploring global resolution of the claims at these facilities, as well as alleged violations at certain other facilities, with the DOJ. Global resolution would include both payment of a civil penalty and an injunctive relief component. We continue to work with the DOJ and the other agencies to resolve these claims, whether individually or globally, and negotiations are ongoing.

Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 19 – 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 16 – Stockholders' Equity and Note 19 – 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.

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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 24, 2021, are listed below.

Name and Position	Age	Business Experience in Past Five Years
Alan S. Armstrong	58	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, WPZ
		2014 to 2018	Chief Executive Officer, WPZ
		2012 to 2018	Director of the general partner, WPZ
Walter J. Bennett	51	2020 to present	Senior Vice President Gathering & Processing, The Williams Companies, Inc.
Senior Vice President Gathering & Processing		2015 to 2019	Senior Vice President – West, The Williams Companies, Inc.
		2013 to 2018	Senior Vice President – West of the general partner, WPZ
		2017	Director of the general partner, WPZ
John D. Chandler	51	2017 to present	Senior Vice President and Chief Financial Officer, The Williams Companies, Inc.
Senior Vice President and Chief Financial Officer		2017 to 2018	Director of the general partner, WPZ
Debbie Cowan	43	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	55	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, WPZ
		2015 to 2016	President / Executive Vice President, Questar Pipeline / Questar Corporation
Scott A. Hallam	44	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.
John D. Porter	51	2020 to present	Vice President, Chief Accounting Officer, Controller and Financial Planning & Analysis, The Williams Companies, Inc.
Vice President, Chief Accounting Officer, Controller and Financial Planning & Analysis		2017 to 2019	Vice President Enterprise Financial Planning & Analysis and Investor Relations, The Williams Companies
		2013 to 2017	Director of Investor Relations & Enterprise Planning

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Name and Position	Age	Business Experience in Past Five Years
Chad A. Teply	49	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
		2009 to 2017	Vice President – Resource Development and Construction, PacifiCorp
T. Lane Wilson	54	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	44	2017 to present	Senior Vice President – Corporate Strategic Development, The Williams Companies, Inc.
Senior Vice President – Corporate Strategic Development		2017 to 2018	Director of the general partner, WPZ
		2014 to 2017	President – Pipeline and Midstream, Cheniere Energy

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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 19, 2021, we had 6,353 holders of record of our common stock.

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, 2016. The Bloomberg Americas Pipelines Index is composed of Enbridge Inc., TC Energy Corporation, Kinder Morgan, Inc., ONEOK, Inc., Cheniere Energy, Inc., Pembina Pipeline Corporation, New Fortress Energy Inc., Inter Pipeline Ltd., Hess Midstream LP, 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.

	2015	2016	2017	2018	2019	2020
The Williams Companies, Inc.	100.0	131.4	134.1	102.0	116.6	107.7
S&P 500 Index	100.0	112.0	136.4	130.4	171.4	203.0
Bloomberg Americas Pipelines Index	100.0	146.8	146.4	125.6	169.8	134.4
Arca Natural Gas Index	100.0	146.6	125.1	85.4	84.4	73.0

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

General

We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs through our gas pipeline and midstream business. 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. Rates are established in accordance with the FERC’s ratemaking process. 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, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities.

Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities as well as corporate activities are included in Other. Our reportable segments are comprised of the following businesses:

•Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated variable interest entity), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.

•Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 99 percent interest in Caiman II (a former equity-method investment which is a consolidated entity following our November 2020 acquisition of an additional ownership interest) which owns a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.

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

•Other includes certain previously owned operations, minor business activities that are not reportable segments, as well as corporate operations.

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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 2020, we paid a regular quarterly dividend of $0.40 per share. On January 26, 2021, our board of directors approved a regular quarterly dividend of $0.41 per share payable on March 29, 2021.

Overview

Net income (loss) attributable to The Williams Companies, Inc., for the year ended December 31, 2020, decreased $639 million compared to the year ended December 31, 2019, reflecting:

•An $860 million increase in Impairment of equity-method investments;

•A $187 million Impairment of goodwill in 2020;

•A $123 million unfavorable change in Net income (loss) attributable to noncontrolling interests primarily driven by a reduced share of certain impairment charges attributable to noncontrolling interests;

•The absence of a $122 million gain recognized on the sale of our interest in an equity-method investment in 2019;

•A $76 million unfavorable change in Other income (expense) – net.

These unfavorable changes were partially offset by:

•A $282 million decrease in Impairment of certain assets;

•A $234 million favorable change in Operating and maintenance expenses and Selling, general, and administrative expenses, driven by lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020 as well as the benefit of a change in an employee benefit policy;

•A $256 million favorable change in Provision (benefit) for income taxes.

Acquisition of Caiman II (Blue Racer)

As of December 31, 2019, we effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent interest in Caiman II, whose primary asset is a 50 percent interest in Blue Racer. On November 18, 2020, we paid $157 million, net of cash acquired, to acquire an additional 41 percent ownership interest in Caiman II. We now control and consolidate Caiman II, reporting the 50 percent interest in Blue Racer as an equity-method investment.

Expansion Project Updates

Significant expansion project updates for the period, including projects placed into service are described below. Ongoing major expansion projects are discussed later in Company Outlook.

Transmission & Gulf of Mexico

Hillabee

In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to an interconnection with the Sabal Trail pipeline in east central Alabama. The project is being constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. Phase I was completed in 2017 and it increased capacity by

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818 Mdth/d. We placed Phase II into service on May 1, 2020. Together, the first two phases of the project increased capacity by 1,025 Mdth/d.

Southeastern Trail

In October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We placed 230 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and the project was fully in service on January 1, 2021. In total, the project increased capacity by 296 Mdth/d.

West

Project Bluestem

We expanded our presence in the Mid-Continent region through building a 189-mile NGL pipeline from our fractionator and NGL storage facilities near Conway, Kansas, to an interconnection with a third-party NGL pipeline system in Oklahoma, providing us with firm access to Mt. Belvieu pricing. As part of the project, the third party constructed a 110-mile pipeline extension of its existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d. The pipeline and extension projects were placed into service on December 1, 2020. Further, during the first quarter of 2019, we exercised an option to purchase a 20 percent equity interest in Targa Train 7, a Mt. Belvieu fractionation train developed by the third party, which was placed into service in the first quarter of 2020.

COVID-19

The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We are monitoring the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees, and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. We are continuing to monitor developments with respect to the outbreak and note the following:

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

•We believe we have the ability to access the debt market, if necessary, as evidenced by the successful completion of debt offerings during second-quarter 2020, and continue to have significant levels of unused capacity on our revolving credit facility.

•We continue to monitor and adapt our remote working arrangements and limit business-related travel. Implementation of these measures has not required material expenditures or significantly impacted our ability to operate our business.

•Our remote working arrangements have not significantly impacted our internal controls over financial reporting and disclosure controls and procedures.

Customer Bankruptcy

In June 2020, our customer, Chesapeake Energy Corporation (Chesapeake), announced that it had voluntarily filed for relief under Chapter 11 of the U.S. Bankruptcy Code. We provide midstream services, including wellhead gathering, for the natural gas that Chesapeake and its joint interest owners produce, primarily in the Eagle Ford Shale, Haynesville Shale, and Marcellus Shale regions (through Appalachia Midstream Investments).

In November 2020, we reached a global resolution with Chesapeake as part of Chesapeake’s restructuring process. The resolution was approved by the bankruptcy court in December 2020 and per the terms, Chesapeake paid all outstanding pre-petition amounts due to us. Additional terms include reduced gathering fees in the Haynesville Shale region, continuation of the gathering agreements in the Eagle Ford Shale and Marcellus Shale

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regions, a long-term gas supply commitment for Transco’s Regional Energy Access pipeline currently under development, and transferring certain natural gas properties in Louisiana to us.

Company Outlook

Our strategy is to provide large-scale 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, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders. Our business plan for 2021 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs.

The credit profiles of certain of our producer customers continue to be challenged, including some that have filed for bankruptcy protection. However, we note that the physical nature of services we provide supports the success of these customers. In many cases, we have long-term acreage dedications with strong historical contractual conveyances that create real estate interests in unproduced gas. 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.

In 2021, our operating results are expected to benefit from growth in our Northeast G&P gathering and processing volumes. We also anticipate increases from Transco expansion projects and higher Gulf of Mexico results primarily due to lower anticipated hurricane impacts. These increases will be partially offset by a decrease in West results, including a reduction in NGL transportation volumes on OPPL and certain fee reductions in the Haynesville area in exchange for upstream value in natural gas properties. We also expect a modest increase in expenses, including higher operating taxes.

Our growth capital and investment expenditures in 2021 are expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and projects supporting the Northeast G&P business and opportunities in the Haynesville area. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.

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

•Continued negative impacts of COVID-19 driving a global recession, which could result in further downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;

•Opposition to, and legal 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, including unexpected developments in customer bankruptcy proceedings;

•Unexpected significant increases in capital expenditures or delays in capital project execution;

•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;

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•General economic, financial markets, or further industry downturns, including increased 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.

We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets that continue to serve key growth markets and supply basins in the United States.

Expansion Projects

Our ongoing major expansion projects include the following:

Transmission & Gulf of Mexico

Northeast Supply Enhancement

In May 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. However, approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection were denied in May 2020. We have not refiled our applications for those approvals. 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, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now require impairment. See further discussion in Critical Accounting Estimates.

Leidy South

In July 2020, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We placed 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and we plan to place the remainder of the project into service as early as the fourth quarter of 2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582 Mdth/d.

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 employee benefit plans that include pension and other postretirement benefits. Net periodic benefit cost and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions 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 cost and the benefit obligations are shown in Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements.

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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	$	2	$	3	$	(101)	$	119
Expected long-term rate of return on plan assets	(12)		12		—		—
Cash balance interest crediting rate	9		(4)		67		(57)
Other postretirement benefits:
Discount rate	—		1		(24)		30
Expected long-term rate of return on plan assets	(3)		3		—		—

Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rates of return on plan assets using our expectations of capital market results, which include an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a period of at least 10 years and take into account our investment strategy and mix of assets. We develop our expectations using input from our third-party independent investment consultant. The forward-looking capital market projections start with current conditions of interest rates, equity pricing, economic growth, and inflation and those are overlaid with forward looking projections of normal inflation, growth, and interest rates to determine expected returns. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual results.

Our expected long-term rate of return on plan assets used for our pension plans was 4.67 percent in 2020. The 2020 actual return on plan assets for our pension plans was approximately 17.9 percent. The 10-year average rate of return on pension plan assets through December 2020 was approximately 8.6 percent. The expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation also impact the expected rates of return.

The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our plans’ liabilities.

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 and is credited to the accounts quarterly. An increase in this rate causes the pension obligation and cost to increase.

Equity-Method Investments

We monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value.

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In the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock (NYSE: WMB) as well as other industry peers and increases in equity yields within the midstream and overall energy industry, which served to increase our estimates of discount rates and weighted-average cost of capital. These changes were attributed to the swift, world-wide economic declines associated with actions to address the spread of COVID-19, coupled with the energy industry impact of significantly reduced energy commodity prices, which were further impacted by crude oil price declines associated with geopolitical actions during the quarter. These significant macroeconomic changes served as indications that the carrying amount of certain of our equity-method investments may have experienced an other-than temporary decline in fair value, determined in accordance with Accounting Standards Codification (ASC) Topic 323, “Investments - Equity Method and Joint Ventures.”

As a result, we estimated the fair value of these equity-method investments in accordance with ASC Topic 820, “Fair Value Measurement,” as of the March 31, 2020, measurement date. In assessing the fair value, 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. As a result, we determined that there were other-than-temporary declines in the fair value of certain of our equity-method investments, resulting in recognized impairments during the first quarter of 2020 totaling $938 million. (See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.) This included impairments of certain of our equity-method investments in our Northeast G&P segment totaling $405 million, primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices, which historically trend with crude oil prices. This total was primarily comprised of impairments of our investment in Caiman II and predominantly wet-gas gathering systems that are part of Appalachia Midstream Investments. We also recognized an impairment of $97 million related to Discovery within the Transmission & Gulf of Mexico segment. We estimated the fair value of these investments as of the March 31, 2020, measurement date utilizing income and market approaches, which were impacted by assumptions reflecting the significant recent market declines previously discussed, such as higher discount rates, ranging from 9.7 percent to 13.5 percent, and lower EBITDA multiples ranging from 5.0x to 6.2x. We also considered any debt held at the investee level, and its impact to fair value. At that time we estimated that a one percentage point increase or decrease in the discount rates used would increase these recognized impairments by approximately $197 million or decrease the level of these recognized impairments by approximately $121 million and a 0.5x increase or decrease in the EBITDA multiples assumed would decrease or increase the level of impairments recognized by approximately $48 million.

During the first quarter of 2020 we also recognized $436 million of impairments within our West segment related to our investments in RMM and Brazos Permian II, measured using an income approach. Both investees operate in primarily crude oil-driven basins where our gathering volumes are driven by crude oil drilling. Our expectation of continued lower crude oil prices and related expectation of significant reductions in current and future producer activities in these areas led to reduced estimates of expected future cash flows. Our fair value estimates also reflected increases in the discount rates to approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. At that time we estimated that a one percentage point increase in the discount rate would increase these recognized impairments by approximately $32 million, while a one percentage point decrease would decrease these impairments by approximately $43 million.

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 recognized an additional $108 million impairment of our investment in RMM, measured using an income approach. Our estimate of fair value reflects a discount rate of 18 percent. We estimate that a one percentage point increase in the discount rate would increase the recognized impairment by approximately $24 million, while a one percentage point decrease would decrease these impairments by approximately $26 million.

Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements, potentially including impairments for investments that were evaluated but for which no impairments were recognized.

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Property, Plant, and Equipment and Other Identifiable Intangible Assets

As a result of the previously described significant macroeconomic changes during the first quarter of 2020, we also evaluated certain of our property, plant, and equipment and other identifiable intangible assets for indicators of impairment as of March 31, 2020. In our assessments, we considered the impact of the then current market conditions on certain of our assets and did not identify any indicators that the carrying amounts of those assets may not be recoverable. The use of alternate judgments or changes in future conditions could result in a different conclusion regarding the occurrence and measurement of impairments affecting the consolidated financial statements.

We also evaluated $212 million of capitalized project development costs for the Northeast Supply Enhancement project for impairment as of December 31, 2020. As previously discussed, 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, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now require impairment. The estimated fair value of the materials within capitalized project costs was determined to be $42 million and considered other internal uses and estimated salvage values. The remaining capitalized costs were determined to have no fair value. As a result, we recognized an impairment charge of $170 million within our Transmission & Gulf of Mexico segment during the fourth quarter of 2020. Our assumption regarding the probability of completing the project is subjective and required management to exercise significant judgment. The use of an alternate judgment could have resulted in a different conclusion regarding the need to evaluate the project for impairment.

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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, 2020. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Year Ended December 31,
	2020		$ Change from 2019*	% Change from 2019*		2019		$ Change from 2018*	% Change from 2018*		2018
	(Millions)
Revenues:
Service revenues	$	5,924	-9	—	%	$	5,933	+431	+8	%	$	5,502
Service revenues – commodity consideration	129		-74	-36	%	203		-197	-49	%	400
Product sales	1,666		-399	-19	%	2,065		-719	-26	%	2,784
Total revenues	7,719					8,201					8,686
Costs and expenses:
Product costs	1,545		+416	+21	%	1,961		+746	+28	%	2,707
Processing commodity expenses	68		+37	+35	%	105		+32	+23	%	137
Operating and maintenance expenses	1,326		+142	+10	%	1,468		+39	+3	%	1,507
Depreciation and amortization expenses	1,721		-7	—	%	1,714		+11	+1	%	1,725
Selling, general, and administrative expenses	466		+92	+16	%	558		+11	+2	%	569
Impairment of certain assets	182		+282	+61	%	464		+1,451	+76	%	1,915
Impairment of goodwill	187		-187	NM		—		—	—		—
Gain on sale of certain assets and businesses	—		+2	+100	%	2		-694	NM		(692)
Other (income) expense – net	22		-14	-175	%	8		+42	+84	%	50
Total costs and expenses	5,517					6,280					7,918
Operating income (loss)	2,202					1,921					768
Equity earnings (losses)	328		-47	-13	%	375		-21	-5	%	396
Impairment of equity-method investments	(1,046)		-860	NM		(186)		-154	NM		(32)
Other investing income (loss) – net	8		-99	-93	%	107		-112	-51	%	219
Interest expense	(1,172)		+14	+1	%	(1,186)		-74	-7	%	(1,112)
Other income (expense) – net	(43)		-76	NM		33		-59	-64	%	92
Income (loss) from continuing operations before income taxes	277					1,064					331
Less: Provision (benefit) for income taxes	79		+256	+76	%	335		-197	-143	%	138
Income (loss) from continuing operations	198					729					193
Income (loss) from discontinued operations	—		+15	+100	%	(15)		-15	NM		—
Net income (loss)	198					714					193
Less: Net income (loss) attributable to noncontrolling interests	(13)		-123	-90	%	(136)		+484	NM		348
Net income (loss) attributable to The Williams Companies, Inc.	$	211				$	850				$	(155)

_______

*    + = 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.

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2020 vs. 2019

Service revenues decreased primarily due to lower volumes in our West segment, lower deferred revenue amortization at Gulfstar One, the expiration of an MVC agreement in the Barnett Shale region, and temporary shut-ins at certain offshore Gulf of Mexico operations. This decrease was partially offset by higher Northeast G&P revenues driven by higher volumes and the March 2019 consolidation of UEOM (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), higher MVC revenue in our West segment, as well as higher transportation fee revenues at Transco and Northwest Pipeline associated with expansion projects placed in service in 2019 and 2020, increased volumes in the Eastern Gulf region, and higher deficiency fee revenue associated with lower volumes at OPPL.

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

Product sales decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities, as well as lower volumes associated with our equity NGL sales activities, partially offset by higher marketing volumes. This decrease also includes lower system management gas sales. Marketing sales and system management gas sales are substantially offset within Product costs.

Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services and lower system management gas purchases, partially offset by higher volumes for marketing activities.

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

Operating and maintenance expenses decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a change in an employee benefit policy (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements), and lower maintenance and operating costs primarily due to timing and scope of activities. These decreases are partially offset by higher expenses related to the consolidation of UEOM.

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

Selling, general, and administrative expenses decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a change in an employee benefit policy (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements), and the absence of transaction costs associated with our 2019 acquisition of UEOM and the formation of the Northeast JV.

Impairment of certain assets includes the 2019 impairments of our Constitution development project, certain Eagle Ford Shale gathering assets, and certain idle gathering assets. The asset impairments in 2020 included our Northeast Supply Enhancement development project and certain gathering assets in the Marcellus Shale region (see Note 18 – 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 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

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Equity earnings (losses) changed unfavorably primarily due to our share of 2020 impairments at equity-method investments (see Note 7 – Investing Activities of Notes to Consolidated Financial Statements), and lower volumes at OPPL and Discovery. These decreases were partially offset by favorable amortization of basis differences related to impairments of several of our equity-method investments which were recognized in first quarter 2020, as well as higher volumes at Appalachia Midstream Investments, increased results at Blue Racer/Caiman II driven by higher volumes and a higher ownership interest, and the absence of 2019 losses at Brazos Permian II.

Impairment of equity-method investments includes impairments of various equity-method investments in 2020 and 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

The unfavorable change in Other investing income (loss) – net is primarily due to the absence of a 2019 gain on the sale of our equity-method investment in Jackalope, partially offset by the absence of a 2019 loss on the deconsolidation of Constitution (see Note 7 – Investing Activities of Notes to Consolidated Financial Statements).

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

Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the absence of the 2019 impairment of our Constitution development project and the impact from the formation of the Northeast JV in June 2019, partially offset by the first-quarter 2020 goodwill impairment charge at the Northeast reporting unit, and lower Gulfstar One results.

2019 vs. 2018

Service revenues increased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in service in 2018 and 2019, as well as the impact of the consolidation of UEOM, higher Northeast volumes at the Susquehanna Supply Hub and Ohio Valley Midstream regions, and higher gathering rates and volumes at the Utica Shale region. These increases are partially offset by the absence of revenues associated with asset divestitures and deconsolidations during 2018, including our former Four Corners area operations (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), as well as lower revenue in the Barnett Shale associated with the end of a contractual MVC period and lower revenue at Gulfstar One primarily associated with producer operational issues.

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

Product sales decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities, lower volumes from our equity NGL sales primarily reflecting the absence of our former Four Corners area operations, and lower system management gas sales, partially offset by higher marketing volumes. Marketing sales and system management gas sales are substantially offset in Product costs.

Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services reflecting the absence of our former Four Corners area operations and lower system management gas purchases, partially offset by higher volumes for marketing activities.

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Processing commodity expenses decreased primarily due to lower production of equity NGLs primarily related to ethane rejection and the absence of our former Four Corners area operations, and lower prices for natural gas purchases associated with our NGL production.

Operating and maintenance expenses decreased primarily due to the absence of our former Four Corners area operations and lower contracted services at Transco primarily due to the timing of required engine overhauls and integrity testing. These decreases are partially offset by the impact of the consolidation of UEOM and by a $32 million charge for severance and related costs primarily associated with a voluntary separation program (VSP) in 2019.

Depreciation and amortization expenses decreased primarily due to the 2018 impairment of certain assets in the Barnett Shale region, which serves to reduce depreciation prospectively, and the absence of assets disposed including our former Four Corners area operations, partially offset by new assets placed in service and by the impact of the consolidation of UEOM.

Selling, general, and administrative expenses decreased primarily due to the absences of a charitable contribution of preferred stock to the Williams Foundation, Inc. (see Note 16 – Stockholders' Equity of Notes to Consolidated Financial Statements) and fees associated with the WPZ Merger, partially offset by a $25 million charge for severance and related costs primarily associated with our 2019 VSP, and transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV.

Impairment of certain assets includes 2019 impairments of our Constitution development project, certain Eagle Ford Shale gathering assets, and certain idle gathering assets. Asset impairments in 2018 included certain assets in the Barnett Shale region and certain idle pipelines (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Gain on sale of certain assets and businesses includes gains recognized on the sales of our Four Corners area and our Gulf Coast pipeline systems in 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

The favorable change in Other (income) expense – net within Operating income (loss) includes net favorable changes to charges and credits to regulatory assets and liabilities, partially offset by the absence of a 2018 gain on asset retirement.

The unfavorable change in Equity earnings (losses) is primarily due to 2019 losses from our Brazos Permian II investment acquired in December 2018 of $14 million, the impact of the consolidation of UEOM during the first quarter of 2019 which reduced equity earnings by $9 million, and a $7 million unfavorable impact related to the April 2019 sale of our Jackalope investment. Additionally, equity earnings at Aux Sable decreased $9 million related to lower rates reflecting lower NGL prices. These decreases are partially offset by improved results at our Appalachia Midstream Investments of $20 million.

The unfavorable change in Impairment of equity-method investments includes 2019 noncash impairments, partially offset by the absence of a 2018 impairment of UEOM (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

The unfavorable change in Other investing income (loss) – net includes the absence of 2018 gains on the deconsolidations of our Delaware basin assets and Jackalope, and a 2019 loss on the deconsolidation of Constitution. These were partially offset by a 2019 gain on the disposition of Jackalope (see Note 7 – Investing Activities of Notes to Consolidated Financial Statements).

Interest expense increased primarily due to an increase in financing obligations associated with Transco’s Atlantic Sunrise project and lower Interest capitalized related to construction projects that have been placed into service.

The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a decrease in equity AFUDC associated with reduced capital expenditures on projects (see Note 6 – Other Income and

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Expenses of Notes to Consolidated Financial Statements), partially offset by the absence of 2018 unfavorable settlement charges from our pension early payout program.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income attributable to The Williams Companies, Inc, partially offset by the absence of a charge to establish $105 million valuation allowance, recorded in 2018, on certain deferred tax assets that may not be realized following the WPZ merger. See Note 8 – 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 favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to our third- quarter 2018 acquisition of the publicly held interests in WPZ associated with the WPZ Merger, the impairment of Constitution project costs, and lower results at Gulfstar One.

Year-Over-Year Operating Results – Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 20 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

Transmission & Gulf of Mexico

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Service revenues	$	3,257	$	3,311	$	2,953
Service revenues – commodity consideration	21		41		59
Product sales	191		288		435
Segment revenues	3,469		3,640		3,447
Product costs	(193)		(288)		(438)
Processing commodity expenses	(7)		(16)		(16)
Other segment costs and expenses	(886)		(984)		(964)
Impairment of certain assets	(170)		(354)		—
Gain on sale of certain assets and businesses	—		—		81
Proportional Modified EBITDA of equity-method investments	166		177		183
Transmission & Gulf of Mexico Modified EBITDA	$	2,379	$	2,175	$	2,293
Commodity margins	$	12	$	25	$	40

2020 vs. 2019

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

Service revenues decreased primarily due to:

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

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

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

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

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

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

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins. Our commodity margins associated with our equity NGLs decreased $11 million driven by lower commodity prices and volumes. Additionally, the decrease in Product sales includes a $47 million decrease in commodity marketing sales due to lower NGL prices and volumes and $27 million lower system management gas sales. Marketing sales and system management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.

Other segment costs and expenses decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a change in an employee benefit policy (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements), lower maintenance costs primarily due to a decrease in contracted services related to general maintenance and other testing at Transco, the absence of a 2019 charge for reversal of costs capitalized in previous periods and net favorable changes to charges and credits associated with a regulatory asset related to Transco’s asset retirement obligations, partially offset by lower equity AFUDC and higher operating taxes.

Impairment of certain assets includes the absence of the impairment of our Constitution development project in 2019, partially offset by the impairment of our Northeast Supply Enhancement development project in 2020 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

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

2019 vs. 2018

Transmission & Gulf of Mexico Modified EBITDA decreased primarily due to the impairment of Constitution, the absence of a 2018 Gain on sale of certain assets and businesses, and higher Other segment costs and expenses, partially offset by increased Service revenues related to expansion projects placed into service during 2018 and 2019.

Service revenues increased primarily due to a $403 million increase in Transco’s natural gas transportation revenues primarily driven by a $358 million increase related to expansion projects placed in service in 2018 and 2019, as well as higher revenue associated with Transco’s general rate case settlement and increased amounts for reimbursable power and storage expenses. Partially offsetting these increases were lower fee revenues of $62 million primarily due to producer operational issues and lower deferred revenue amortization at Gulfstar One, as well as the sale of certain Gulf Coast pipeline assets in fourth-quarter 2018.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins. Our commodity margins associated with our equity NGLs decreased $16 million, consisting of a $26 million decrease associated with unfavorable net realized NGL sales prices, partially offset by a $10 million increase associated with higher sales volumes. The higher NGL volumes were primarily related to the absence of 2018 downtime to modify the Mobile Bay processing plant for the Norphlet project. Additionally, the decrease in Product sales includes a $93 million decrease in commodity marketing sales due to lower NGL prices and volumes and a $39 million decrease in system management gas sales. Marketing sales

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and system management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.

Other segment costs and expenses increased primarily due a $56 million unfavorable change in Transco’s equity AFUDC due to lower construction activity, a $39 million charge in 2019 for severance and related costs primarily associated with our 2019 VSP, a $21 million increase in reimbursable power and storage expenses, $16 million of expense in 2019 related to the reversal of expenditures previously capitalized, and the absence of a $12 million 2018 gain on asset retirements. These unfavorable changes were partially offset by $77 million of net favorable changes to charges and credits associated with regulatory assets and liabilities, which were significantly driven by the previously mentioned settlement in Transco’s general rate case, a $46 million decrease in Transco’s contracted services compared to 2018 mainly due to the timing of required engine overhauls and integrity testing, and the absence of a 2018 unfavorable charge of $12 million for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger.

Impairment of certain assets includes the 2019 impairment of our Constitution development project (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Gain on sale of certain assets and businesses reflects an $81 million gain from the sale of our Gulf Coast pipeline system assets in fourth-quarter 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

Northeast G&P

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Service revenues	$	1,465	$	1,338	$	976
Service revenues – commodity consideration	7		12		20
Product sales	57		150		287
Segment revenues	1,529		1,500		1,283
Product costs	(57)		(152)		(289)
Processing commodity expenses	(3)		(8)		(9)
Other segment costs and expenses	(441)		(470)		(392)
Impairment of certain assets	(12)		(10)		—
Proportional Modified EBITDA of equity-method investments	473		454		493
Northeast G&P Modified EBITDA	$	1,489	$	1,314	$	1,086
Commodity margins	$	4	$	2	$	9

2020 vs. 2019

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

Service revenues increased primarily due to:

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

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

•A $13 million increase in revenues associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in Other segment costs and expenses.

Product sales decreased primarily due to lower NGL volumes and prices within our marketing activities, and lower system management gas sales. Marketing sales and system management gas sales are offset by similar changes in marketing purchases and system management gas purchases, reflected above as Product costs, and therefore have little impact to Modified EBITDA.

Other segment costs and expenses decreased due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a change in an employee benefit policy (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements), and lower maintenance and operating expenses primarily due to timing and scope of activities. Additionally, expenses changed favorably due to the absence of transaction costs associated with our 2019 acquisition of UEOM and the formation of the Northeast JV. These decreases were partially offset by higher reimbursable electricity expenses, increased expenses associated with the consolidation of UEOM, and the absence of a favorable customer settlement in 2019.

Impairment of certain assets includes a $12 million impairment of certain gathering assets in the Marcellus Shale region in 2020 and a $10 million write-down of other certain assets that were no longer in use or were surplus in nature in 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments driven by higher volumes, partially offset by a $26 million decrease for our share of an impairment of certain assets. Additionally, there was an increase at Blue Racer/Caiman II primarily due to higher volumes and the favorable impact of increased ownership, partially offset by a $10 million decrease for our share of an impairment of certain assets. These increases were partially offset by a $16 million decrease as a result of the consolidation of UEOM in 2019, as previously discussed, as well as a decrease at Laurel Mountain primarily due to $11 million for our share of an impairment of certain assets that were subsequently sold, partially offset by higher volumes, and a decrease at Aux Sable.

2019 vs. 2018

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues due to increased gathering volumes, as well as the $38 million favorable impact of acquiring the additional interest in UEOM, partially offset by 2019 impairments.

Service revenues increased primarily due to:

•A $158 million increase associated with the consolidation of UEOM, as previously discussed;

•A $102 million increase associated with higher gathering revenues at Susquehanna Supply Hub reflecting 18 percent higher gathering volumes due to increased production from customers and higher rates;

•A $49 million increase at Ohio Valley Midstream primarily due to higher gathering, processing, and transportation volumes;

•A $36 million increase in gathering revenues in the Utica Shale region due to higher rates and volumes from new wells;

•A $14 million increase in compression revenues for services charged to an affiliate driven by higher volumes.

Product sales decreased primarily due to lower non-ethane volumes and prices within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.

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Other segment costs and expenses increased primarily due to:

•A $53 million increase associated with the consolidation of UEOM;

•A $10 million increase related to transaction expenses associated with the acquisition of UEOM and the formation of the Northeast JV;

•A $7 million charge in 2019 for severance and related costs primarily associated with our VSP.

Impairment of certain assets increased due to a $10 million write-down of other certain assets that are no longer in use or are surplus in nature in 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments decreased $59 million as a result of the consolidation of UEOM and $10 million due to unfavorable rates reflecting lower NGL prices at Aux Sable. This decrease was partially offset by a $29 million increase at Appalachia Midstream Investments, reflecting higher volumes due to increased customer production.

West

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Service revenues	$	1,280	$	1,364	$	1,641
Service revenues – commodity consideration	101		150		321
Product sales	1,562		1,797		2,448
Segment revenues	2,943		3,311		4,410
Product costs	(1,520)		(1,774)		(2,448)
Processing commodity expenses	(58)		(79)		(116)
Other segment costs and expenses	(477)		(519)		(644)
Impairment of certain assets	—		(100)		(1,849)
Gain on sale of certain assets and businesses	—		(2)		591
Proportional Modified EBITDA of equity-method investments	110		115		94
West Modified EBITDA	$	998	$	952	$	38
Commodity margins	$	85	$	94	$	205

2020 vs. 2019

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

Service revenues decreased primarily due to:

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

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

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

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

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

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

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

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

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins, which we further segregate into product margins associated with our equity NGLs and marketing margins. Product margins from our equity NGLs decreased $29 million primarily due to:

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

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

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

Additionally, marketing margins increased by $23 million primarily due to favorable changes in net commodity prices. The decrease in Product sales includes a $168 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher marketing sales volumes. An $18 million decrease in other product sales also contributed to the overall decrease. These decreases are substantially offset in Product costs.

Other segment costs and expenses decreased primarily due to lower employee-related expenses driven by the absence of 2019 severance and related costs and the associated reduced costs in 2020, and the favorable impact of a change in an employee benefit policy (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements), as well as lower operating costs due to fewer leased compressors and lower maintenance costs primarily due to timing and scope of activities. These favorable changes are partially offset by the absence of $12 million in favorable settlements in 2019.

Impairment of certain assets decreased primarily due to the absence of a $79 million impairment of certain Eagle Ford Shale gathering assets and a $12 million impairment of certain idle gathering assets in 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

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

2019 vs. 2018

West Modified EBITDA increased primarily due to lower Impairment of certain assets and lower Other segment costs and expenses, partially offset by a lower gain on sale of certain assets in 2019, lower Service revenues, and lower commodity margins.

Service revenues decreased primarily due to:

•A $218 million decrease associated with asset divestitures and deconsolidations during 2018 and 2019, including our former Four Corners area assets, certain Delaware basin assets that were contributed to our

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Brazos Permian II equity-method investment, and our Jackalope assets which were deconsolidated in second-quarter 2018 and subsequently sold in second-quarter 2019;

•A $57 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues in the Barnett Shale region primarily associated with the expiration of a certain MVC agreement;

•A $17 million decrease driven by lower gathering volumes primarily in the Mid-Continent, Barnett Shale, and Wamsutter regions, partially offset by higher gathering volumes primarily in the Haynesville Shale and Eagle Ford regions;

•A $15 million decrease associated with lower processing rates primarily driven by lower commodity pricing in the Piceance region;

•A $15 million decrease associated with lower gathering rates primarily in the Mid-Continent and Haynesville Shale regions; partially offset by

•A $17 million increase related to other MVC deficiency fee revenues;

•A $13 million increase related to higher fractionation and storage fees;

•An $8 million increase associated with the resolution of a prior period performance obligation.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins. Our commodity margins associated with our equity NGLs decreased by $127 million primarily due to:

•A $98 million decrease associated with lower sales volumes, consisting of $54 million related to the absence of our former Four Corners area assets and $44 million due to 12 percent lower non-ethane volumes and 33 percent lower ethane sales volumes primarily due to higher ethane rejection in 2019, natural declines, less producer drilling activity, and more severe weather conditions in first-quarter 2019;

•A $66 million decrease associated with lower sales prices primarily due to 29 percent and 48 percent lower average net realized per-unit non-ethane and ethane sales prices, respectively; partially offset by

•A $37 million increase related to lower natural gas purchases associated with lower equity NGL production volumes and lower natural gas prices, including $9 million related to the absence of our former Four Corners area assets.

Additionally, the decrease in Product sales includes a $447 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher sales volumes, and a $36 million decrease related to the sale of other products. These decreases are substantially offset in Product costs. Marketing margins increased by $27 million primarily due to favorable changes in prices.

Other segment costs and expenses decreased primarily due to a $127 million reduction associated with the absence of our former Four Corners area assets and from the Jackalope deconsolidation in second-quarter 2018, $12 million favorable settlements in 2019, as well as $7 million lower ad valorem taxes. These decreases were partially offset by an unfavorable charge in 2019 for severance and related costs primarily associated with our VSP of $10 million.

Impairment of certain assets decreased primarily due to the absence of the $1.849 billion Barnett impairment in in 2018, partially offset by small impairment charges in 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

The decrease in Gain on sale of certain assets and businesses reflects the absence of the gain from the sale of our Four Corners area assets recorded in the fourth quarter of 2018 (see Note 3 – Acquisitions and Divestitures of Notes to the Consolidated Financial Statements).

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Proportional Modified EBITDA of equity-method investments increased primarily due to the additions of the RMM and Brazos Permian II equity-method investments in the second half of 2018, partially offset by the sale of our Jackalope investment in second-quarter 2019.

Other

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Other Modified EBITDA	$	(15)	$	6	$	(29)

2020 vs. 2019

Other Modified EBITDA decreased primarily due to:

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

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

•The absence of a $12 million unfavorable adjustment to a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger.

2019 vs. 2018

Other Modified EBITDA increased primarily due to:

•The absence of the $66 million impairment of certain idle pipelines in the second quarter of 2018 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);

•The absence of a $35 million charge in 2018 associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation) (see Note 16 – Stockholders' Equity of Notes to Consolidated Financial Statements);

•The absence of $20 million in costs in 2018 associated with the WPZ Merger (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements);

•An $8 million increase related to the absence of 2018 unfavorable Modified EBITDA associated with the results of certain of our former Gulf Coast area operations sold in 2018;

•The absence of a $7 million loss on early retirement of debt in 2018.

These increases were partially offset by:

•The absence of a $37 million benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger in 2018 and a subsequent unfavorable $12 million adjustment in the first quarter of 2019;

•A $26 million decrease in income associated with a regulatory asset related to deferred taxes on equity funds used during construction;

•The absence of a $20 million gain on the sale of certain assets and operations located in the Gulf Coast area in 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

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Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

As previously discussed, we have continued to focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs. During 2020, we retired approximately $2.1 billion of long-term debt and issued approximately $2.2 billion of new long-term debt. In July 2020, we paid $284 million for rate refunds related to Transco’s increased rates collected since the new rates became effective in March 2019. In 2020, we acquired substantially all of the remaining outstanding ownership interests in Caiman II for approximately $157 million, net of cash acquired. See also the section titled Sources (Uses) of Cash.

Outlook

As previously discussed in Company Outlook, our growth capital and investment expenditures in 2021 are currently expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and projects supporting the Northeast G&P business and opportunities in the Haynesville area. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all of our planned 2021 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.

As of December 31, 2020, we have $893 million of long-term debt due within one year. Our potential sources of liquidity available to address these maturities include proceeds from refinancing at attractive long-term rates or from our credit facility, 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 2021. 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
	Other operating costs including human capital expenses
	Quarterly dividends to our shareholders
	Debt service payments, including payments of long-term debt
	Distributions to noncontrolling interests

As of December 31, 2020, we have approximately $21.5 billion of long-term debt due after one year. See Note 14 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for the aggregate maturities over the next five years. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.

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Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.

As of December 31, 2020, we had a working capital deficit of $890 million, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:

Available Liquidity	December 31, 2020
	(Millions)
Cash and cash equivalents	$	142
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)	4,500
	$	4,642

__________

(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of December 31, 2020. The highest amount outstanding under our commercial paper program and credit facility during 2020 was $1.7 billion. At December 31, 2020, we were in compliance with the financial covenants associated with our credit facility. See Note 14 – 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 5 percent from the $0.38 per share paid in each quarter of 2019, to $0.40 per share paid in each quarter of 2020.

Registrations

To replace our recently expired shelf registration statement, we anticipate filing a new 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 7 – 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	Positive	Baa3
Fitch Ratings	Stable	BBB

In November 2020, Fitch Ratings upgraded our credit rating from BBB- to BBB. In January 2021, Moody’s changed our Outlook from Stable to Positive.

These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current

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criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and would 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	2020		2019		2018
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	3,496	$	3,693	$	3,293
Proceeds from long-term debt (see Note 14)	Financing	2,199		67		2,086
Proceeds from credit-facility borrowings	Financing	1,700		700		1,840
Contributions in aid of construction	Investing	37		52		411
Proceeds from sale of partial interest in consolidated subsidiary (see Note 3)	Financing	—		1,334		—
Proceeds from dispositions of equity-method investments (see Note 7)	Investing	—		485		—
Proceeds from sale of businesses, net of cash divested (see Note 3)	Investing	—		(2)		1,296
Uses of cash and cash equivalents:
Payments of long-term debt (see Note 14)	Financing	(2,141)		(49)		(1,254)
Common dividends paid	Financing	(1,941)		(1,842)		(1,386)
Payments on credit-facility borrowings	Financing	(1,700)		(860)		(1,950)
Capital expenditures	Investing	(1,239)		(2,109)		(3,256)
Purchases of and contributions to equity-method investments (see Note 7)	Investing	(325)		(453)		(1,132)
Dividends and distributions paid to noncontrolling interests	Financing	(185)		(124)		(591)
Purchases of businesses, net of cash acquired (see Note 3)	Investing	—		(728)		—
Other sources / (uses) – net	Financing and Investing	(48)		(43)		(88)
Increase (decrease) in cash and cash equivalents		$	(147)	$	121	$	(731)

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Gain on disposition of equity-method investments, (Gain) on sale of certain assets and businesses, (Gain) loss on deconsolidation of businesses, Impairment of goodwill, Impairment of equity-method investments, and Impairment of certain assets.

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

Our Net cash provided (used) by operating activities in 2019 increased from 2018 primarily due to the net favorable changes in operating working capital in 2019, including the collection of Transco’s filed rates subject to refund and the receipt of an income tax refund, as well as higher operating income (excluding noncash items as previously discussed) in 2019, partially offset by the impact of decreased distributions from unconsolidated affiliates in 2019.

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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 19 – 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 $33 million, all of which are included in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31, 2020. We will seek recovery of the accrued costs related to remediation activities by our interstate gas pipelines totaling approximately $4 million through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2020, we paid approximately $3 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $11 million in 2021 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, 2020, 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 promulgate and propose 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, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule's implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to 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. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

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

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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 14 – 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, 2020 and 2019. See Note 18 – 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.

		2021			2022			2023			2024			2025			Thereafter (1)			Total		Fair Value December 31, 2020
	(Millions)
Long-term debt, including current portion:
Fixed rate		$	894		$	2,025		$	1,477		$	2,280		$	1,617		$	14,051		$	22,344	$	27,043
Weighted-average interest rate		5.0		%	5.1		%	5.2		%	5.3		%	5.4		%	5.4		%
		2020			2021			2022			2023			2024			Thereafter (1)			Total		Fair Value December 31, 2019
	(Millions)
Long-term debt, including current portion:
Fixed rate		$	2,141		$	893		$	2,025		$	1,477		$	2,279		$	13,473		$	22,288	$	25,319
Weighted-average interest rate		5.2		%	5.2		%	5.3		%	5.4		%	5.6		%	5.6		%

__________________

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

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of NGLs and natural gas, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts, and limited proprietary trading activities. Our management of the risks associated with these market fluctuations includes maintaining sufficient liquidity, as well as using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. At December 31, 2020 and 2019, our derivative activity was not material.

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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, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

We did not audit the 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 and $217 million as of December 31, 2020 and 2019, respectively, and the Company’s equity earnings in the net income of Gulfstream were $77 million in 2020, $74 million in 2019 and $75 million in 2018. Gulfstream’s 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, 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, 2020, 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 24, 2021 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.

66

Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
	Pension and Other Postretirement Benefit Obligations
Description of the Matter	At December 31, 2020, the Company’s aggregate pension and other postretirement benefit obligations were $1,403 million and were exceeded by the fair value of pension and other postretirement plan assets of $1,635 million, resulting in overfunded pension and other postretirement benefit obligations of $232 million. As explained in Note 10 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.

67

	Impairment Review of Equity-Method Investments
Description of the Matter	As discussed in Note 7 to the consolidated financial statements, the Company has investments in nonconsolidated entities accounted for using the equity-method, totaling $5,159 million as of December 31, 2020, and recorded impairments of equity-method investments of $1,046 million during 2020. The carrying value of each equity-method investment is evaluated for impairment when events or changes in circumstances indicate that the carrying value of the investment may have experienced an other-than-temporary decline in value. When there are indicators of impairment, the fair value of the equity-method investment is estimated. Fair value is estimated using various methods, including income and market approaches. When the estimated fair value is lower than the carrying value, the Company determines whether the impairment is other-than-temporary. Auditing the Company’s impairment assessments was complex and judgmental due to the estimation required in the determination of fair value of the investments for which evidence of loss in value has occurred.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company’s equity-method impairment review process, including controls over the determination of fair value. For the equity-method investments with evidence of loss in value, we performed audit procedures that included, among others, assessing the methodologies used by management to determine fair value, evaluating the significant assumptions, and testing the underlying data used by the Company in its analyses. For example, we compared the estimated cash flows used within the assessments to current operating results and future expected economic trends, and obtained third-party support, where available, to evaluate significant assumptions. We also recalculated management’s estimate. We involved our valuation specialists to assist with our evaluation of the methodologies used by the Company and significant assumptions included in the fair value estimates.

/s/ Ernst & Young LLP

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

Tulsa, Oklahoma

February 24, 2021

68

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 financial position of Gulfstream Natural Gas System, L.L.C. (the “Company”) as of December 31, 2020 and 2019, and the related statements of earnings, comprehensive income, changes in members’ equity and cash flows for each of the three years in the period 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 financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period 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 audits. 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 audits 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 audits 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 audits 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 audits provide a reasonable basis for our opinion.

Critical Audit Matters

Critical audit matters are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to those charged with governance and that (i) relate to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. We determined there are no critical audit matters.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 24, 2021

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

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The Williams Companies, Inc.

Consolidated Statement of Operations

		Year Ended December 31,
		2020		2019		2018
	(Millions, except per-share amounts)
Revenues:
Service revenues		$	5,924	$	5,933	$	5,502
Service revenues – commodity consideration		129		203		400
Product sales		1,666		2,065		2,784
Total revenues		7,719		8,201		8,686
Costs and expenses:
Product costs		1,545		1,961		2,707
Processing commodity expenses		68		105		137
Operating and maintenance expenses		1,326		1,468		1,507
Depreciation and amortization expenses		1,721		1,714		1,725
Selling, general, and administrative expenses		466		558		569
Impairment of certain assets (Note 18)		182		464		1,915
Impairment of goodwill (Note 18)		187		—		—
Gain on sale of certain assets and businesses (Note 3)		—		2		(692)
Other (income) expense – net		22		8		50
Total costs and expenses		5,517		6,280		7,918
Operating income (loss)		2,202		1,921		768
Equity earnings (losses) (Note 7)		328		375		396
Impairment of equity-method investments (Note 18)		(1,046)		(186)		(32)
Other investing income (loss) – net (Note 7)		8		107		219
Interest incurred		(1,192)		(1,218)		(1,160)
Interest capitalized		20		32		48
Other income (expense) – net		(43)		33		92
Income (loss) from continuing operations before income taxes		277		1,064		331
Less: Provision (benefit) for income taxes		79		335		138
Income (loss) from continuing operations		198		729		193
Income (loss) from discontinued operations		—		(15)		—
Net income (loss)		198		714		193
Less: Net income (loss) attributable to noncontrolling interests		(13)		(136)		348
Net income (loss) attributable to The Williams Companies, Inc.		211		850		(155)
Less: Preferred stock dividends (Note 16)		3		3		1
Net income (loss) available to common stockholders		$	208	$	847	$	(156)
Amounts attributable to The Williams Companies, Inc. available to common stockholders:
Income (loss) from continuing operations		$	208	$	862	$	(156)
Income (loss) from discontinued operations		—		(15)		—
Net income (loss)		$	208	$	847	$	(156)
Basic earnings (loss) per common share:
Income (loss) from continuing operations		$	.17	$	.71	$	(.16)
Income (loss) from discontinued operations		—		(.01)		—
Net income (loss)		$	.17	$	.70	$	(.16)
Weighted-average shares (thousands)		1,213,631		1,212,037		973,626
Diluted earnings (loss) per common share:
Income (loss) from continuing operations		$	.17	$	.71	$	(.16)
Income (loss) from discontinued operations		—		(.01)		—
Net income (loss)		$	.17	$	.70	$	(.16)
Weighted-average shares (thousands)		1,215,165		1,214,011		973,626

See accompanying notes.

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The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income (Loss)

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Net income (loss)	$	198	$	714	$	193
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $—, $—, and $1 in 2020, 2019, and 2018, respectively	(2)		—		(7)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $—, $—, and ($1) in 2020, 2019, and 2018, respectively	1		—		8
Pension and other postretirement benefits:
Net actuarial gain (loss) arising during the year, net of taxes of ($27), ($20), and $3 in 2020, 2019, and 2018, respectively	81		59		(6)
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($7), ($4), and ($11) in 2020, 2019, and 2018, respectively	23		12		35
Other comprehensive income (loss)	103		71		30
Comprehensive income (loss)	301		785		223
Less: Comprehensive income (loss) attributable to noncontrolling interests	(13)		(136)		346
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	314	$	921	$	(123)

See accompanying notes.

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The Williams Companies, Inc.

Consolidated Balance Sheet

	December 31,
	2020		2019
	(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	142	$	289
Trade accounts and other receivables	1,000		1,002
Allowance for doubtful accounts	(1)		(6)
Trade accounts and other receivables - net	999		996
Inventories	136		125
Other current assets and deferred charges	152		170
Total current assets	1,429		1,580
Investments	5,159		6,235
Property, plant, and equipment – net	28,929		29,200
Intangible assets – net of accumulated amortization	7,444		7,959
Regulatory assets, deferred charges, and other	1,204		1,066
Total assets	$	44,165	$	46,040
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	482	$	552
Accrued liabilities	944		1,276
Long-term debt due within one year	893		2,140
Total current liabilities	2,319		3,968
Long-term debt	21,451		20,148
Deferred income tax liabilities	1,923		1,782
Regulatory liabilities, deferred income, and other	3,889		3,778
Contingent liabilities and commitments (Note 19)
Equity:
Stockholders’ equity:
Preferred stock	35		35
Common stock ($1 par value; 1,470 million shares authorized at December 31, 2020 and December 31, 2019; 1,248 million shares issued at December 31, 2020 and 1,247 million shares issued at December 31, 2019)	1,248		1,247
Capital in excess of par value	24,371		24,323
Retained deficit	(12,748)		(11,002)
Accumulated other comprehensive income (loss)	(96)		(199)
Treasury stock, at cost (35 million shares of common stock)	(1,041)		(1,041)
Total stockholders’ equity	11,769		13,363
Noncontrolling interests in consolidated subsidiaries	2,814		3,001
Total equity	14,583		16,364
Total liabilities and equity	$	44,165	$	46,040

See accompanying notes.

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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, 2017	$	—	$	861	$	18,508	$	(8,434)	$	(238)	$	(1,041)	$	9,656	$	6,519	$	16,175
Adoption of new accounting standards	—		—		—		(23)		(61)		—		(84)		(37)		(121)
Net income (loss)	—		—		—		(155)		—		—		(155)		348		193
Other comprehensive income (loss)	—		—		—		—		32		—		32		(2)		30
WPZ Merger (Note 1)	—		382		6,112		—		(3)		—		6,491		(4,629)		1,862
Issuance of preferred stock (Note 16)	35		—		—		—		—		—		35		—		35
Cash dividends – common stock ($1.36 per share)	—		—		—		(1,386)		—		—		(1,386)		—		(1,386)
Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(637)		(637)
Stock-based compensation and related common stock issuances, net of tax	—		1		60		—		—		—		61		—		61
Sales of limited partner units of Williams Partners L.P.	—		—		—		—		—		—		—		46		46
Changes in ownership of consolidated subsidiaries, net	—		—		14		—		—		—		14		(18)		(4)
Contributions from noncontrolling interests	—		—		—		—		—		—		—		15		15
Deconsolidation of subsidiary (Note 7)	—		—		—		—		—		—		—		(267)		(267)
Other	—		1		(1)		(4)		—		—		(4)		(1)		(5)
Net increase (decrease) in equity	35		384		6,185		(1,568)		(32)		—		5,004		(5,182)		(178)
Balance at December 31, 2018	35		1,245		24,693		(10,002)		(270)		(1,041)		14,660		1,337		15,997
Net income (loss)	—		—		—		850		—		—		850		(136)		714
Other comprehensive income (loss)	—		—		—		—		71		—		71		—		71
Cash dividends – common stock ($1.52 per share)	—		—		—		(1,842)		—		—		(1,842)		—		(1,842)
Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(124)		(124)
Stock-based compensation and related common stock issuances, net of tax	—		2		56		—		—		—		58		—		58
Sale of partial interest in consolidated subsidiary (Note 3)	—		—		—		—		—		—		—		1,334		1,334
Change in ownership of consolidated subsidiaries, net (Note 3)	—		—		(426)		—		—		—		(426)		567		141
Contributions from noncontrolling interests	—		—		—		—		—		—		—		36		36
Deconsolidation of subsidiary (Note 7)	—		—		—		—		—		—		—		(13)		(13)
Other	—		—		—		(8)		—		—		(8)		—		(8)
Net increase (decrease) in equity	—		2		(370)		(1,000)		71		—		(1,297)		1,664		367
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

*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

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The Williams Companies, Inc.

Consolidated Statement of Cash Flows

	Year Ended December 31,
	2020		2019		2018
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	198	$	714	$	193
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	1,721		1,714		1,725
Provision (benefit) for deferred income taxes	108		376		220
Equity (earnings) losses	(328)		(375)		(396)
Distributions from unconsolidated affiliates	653		657		693
Gain on disposition of equity-method investments (Note 7)	—		(122)		—
(Gain) on sale of certain assets and businesses (Note 3)	—		2		(692)
(Gain) loss on deconsolidation of businesses (Note 7)	—		29		(203)
Impairment of goodwill (Note 18)	187		—		—
Impairment of equity-method investments (Note 18)	1,046		186		32
Impairment of certain assets (Note 18)	182		464		1,915
Amortization of stock-based awards	52		57		55
Cash provided (used) by changes in current assets and liabilities:
Accounts receivable	(2)		34		(36)
Inventories	(11)		5		(16)
Other current assets and deferred charges	11		21		17
Accounts payable	(7)		(46)		(93)
Accrued liabilities	(309)		153		23
Other, including changes in noncurrent assets and liabilities	(5)		(176)		(144)
Net cash provided (used) by operating activities	3,496		3,693		3,293
FINANCING ACTIVITIES:
Proceeds from long-term debt	3,899		767		3,926
Payments of long-term debt	(3,841)		(909)		(3,204)
Proceeds from issuance of common stock	9		10		15
Proceeds from sale of partial interest in consolidated subsidiary (Note 3)	—		1,334		—
Common dividends paid	(1,941)		(1,842)		(1,386)
Dividends and distributions paid to noncontrolling interests	(185)		(124)		(591)
Contributions from noncontrolling interests	7		36		15
Payments for debt issuance costs	(20)		—		(26)
Other – net	(13)		(17)		(48)
Net cash provided (used) by financing activities	(2,085)		(745)		(1,299)
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(1,239)		(2,109)		(3,256)
Dispositions – net	(36)		(40)		(7)
Contributions in aid of construction	37		52		411
Proceeds from sale of businesses, net of cash divested (Note 3)	—		(2)		1,296
Purchases of businesses, net of cash acquired (Note 3)	—		(728)		—
Proceeds from dispositions of equity-method investments (Note 7)	—		485		—
Purchases of and contributions to equity-method investments (Note 7)	(325)		(453)		(1,132)
Other – net	5		(32)		(37)
Net cash provided (used) by investing activities	(1,558)		(2,827)		(2,725)
Increase (decrease) in cash and cash equivalents	(147)		121		(731)
Cash and cash equivalents at beginning of year	289		168		899
Cash and cash equivalents at end of year	$	142	$	289	$	168
_________
(1) Increases to property, plant, and equipment	$	(1,160)	$	(2,023)	$	(3,021)
Changes in related accounts payable and accrued liabilities	(79)		(86)		(235)
Capital expenditures	$	(1,239)	$	(2,109)	$	(3,256)

See accompanying notes.

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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.

WPZ Merger

On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), our previously consolidated master limited partnership, pursuant to which we acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of our common stock (WPZ Merger). Williams continued as the surviving entity. The WPZ Merger was accounted for as a noncash equity transaction resulting in increases to Common stock of $382 million, Capital in excess of par value of $6.112 billion, and Regulatory assets, deferred charges, and other of $33 million and decreases to Accumulated other comprehensive income (loss) (AOCI) of $3 million, Noncontrolling interests in consolidated subsidiaries of $4.629 billion, and Deferred income tax liabilities of $1.829 billion in the Consolidated Balance Sheet. Prior to the completion of the WPZ Merger and pursuant to its distribution reinvestment program, WPZ had issued common units to the public in 2018 associated with reinvested distributions of $46 million.

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. Our operations are presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities 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), 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), which is a proprietary floating production system, 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).

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 99 percent interest in Caiman Energy II, LLC (Caiman II) (a former equity-method investment which is a consolidated entity following our November 2020 acquisition of an additional ownership interest and was subsequently renamed Blue Racer Midstream Holdings, LLC) which owns a 50 percent equity-method investment in Blue Racer Midstream LLC (Blue Racer) (see Note 7 – Investing Activities), 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).

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West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, and Permian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business, 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 interest in Brazos Permian II, LLC (Brazos Permian II) (a nonconsolidated VIE).

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 other identifiable 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 non-core assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities, including effects of financial distress caused by financial and commodity market declines, 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.

Customer bankruptcy

In June 2020, our customer, Chesapeake Energy Corporation (Chesapeake), announced that it had voluntarily filed for relief under Chapter 11 of the U.S. Bankruptcy Code. We provide midstream services, including wellhead gathering, for the natural gas that Chesapeake and its joint interest owners produce, primarily in the Eagle Ford Shale, Haynesville Shale, and Marcellus Shale regions (through Appalachia Midstream Investments).

In November 2020, we reached a global resolution with Chesapeake as part of Chesapeake’s restructuring process. The resolution was approved by the bankruptcy court in December 2020 and per the terms, Chesapeake paid all outstanding pre-petition amounts due to us. Additional terms include reduced gathering fees in the Haynesville Shale region, continuation of the gathering agreements in the Eagle Ford Shale and Marcellus Shale regions, a long-term gas supply commitment for Transco’s Regional Energy Access pipeline currently under development, and transferring certain natural gas properties in Louisiana to us. As a result of this resolution, we recorded increases to our other nonregulated property, plant, and equipment of $98 million, contract liabilities of $67 million (see Note 5 – Revenue Recognition), and asset retirement obligations (AROs) of $31 million (see Note 11 – Property, Plant, and Equipment).

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:

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•Determining whether an entity is a VIE;

•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 the 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.

Equity-method investment basis differences

Differences between the cost 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 the Consolidated Statement of Operations includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.

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, goodwill, and other identifiable intangible assets;

•Litigation-related contingencies;

•Environmental remediation obligations;

•Depreciation and/or amortization of long-lived assets;

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

•AROs;

•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;

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•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, levelized incremental 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 for the years ended December 31, 2020 and 2019 are as follows:

	December 31,
	2020		2019
	(Millions)
Current assets reported within Other current assets and deferred charges	$	64	$	72
Noncurrent assets reported within Regulatory assets, deferred charges, and other	442		466
Total regulated assets	$	506	$	538
Current liabilities reported within Accrued liabilities	$	59	$	60
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other	1,314		1,277
Total regulated liabilities	$	1,373	$	1,337

Cash and cash equivalents

Cash and cash equivalents in the 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 (as discussed below in Accounting standards issued and adopted), the financial condition of our customers, and age of past due accounts. We do not offer extended payment terms and typically receive payment within one month. We consider receivables

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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.

Inventories

Inventories in the Consolidated Balance Sheet primarily consist of NGLs, natural gas in underground storage, and materials and supplies and are stated at the lower of cost or net realizable value. The cost of inventories is primarily determined using the average-cost method.

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.

Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Operations.

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. 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 the Consolidated Statement of Operations, except for regulated entities, for which the liability is offset by 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.

Goodwill

Goodwill included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, as of December 31, 2019, represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, an impairment charge is recorded for the difference (not to exceed the carrying value of goodwill). Judgments and assumptions are inherent in our management’s estimates of fair value.

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Other identifiable intangible assets

Our other identifiable intangible assets included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation contractual customer relationships. Our other identifiable intangible assets are 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, other identifiable intangible assets, and investments

We evaluate our property, plant, and equipment and other identifiable 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 in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the 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 the consolidated financial statements as an impairment charge.

Judgments 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.

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.

Cash flows from revolving credit facilities and commercial paper program

Proceeds and payments related to borrowings under our credit facilities are reflected in the financing activities in the 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 the 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 14 – Debt and Banking Arrangements.)

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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 the Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in the Consolidated Balance Sheet using the average-cost method.

Derivative instruments and hedging activities

We may 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 report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets and deferred charges; Regulatory assets, deferred charges, and other; Accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.

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 on the 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 Product sales or Product costs in the Consolidated Statement of Operations.

For commodity derivatives designated as a cash flow hedge, the change in fair value of the derivative is reported in AOCI in the 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 Product sales or Product costs in the Consolidated Statement of Operations at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by us.

For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Operations.

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Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.

Realized gains and losses on derivatives that (1) require physical delivery, (2) are used for managing commodity risk on NGL processing or natural gas production activities, and (3) are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis.

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” (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. 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 fixed 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;

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•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

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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 the Consolidated Statement of Operations 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. Given that most inventory is sold in the same period that it is generated, the impact of these transactions is expected to have little impact to operating income.

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 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.

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 the 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

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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 liabilities and Regulatory liabilities, deferred income, and other, respectively, in the 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.

Leases

We recognize a lease liability with an offsetting right-of-use asset in the 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, but a certain land lease has a term of 108 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.

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 the Consolidated Statement of Operations. The rates used by regulated companies

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are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.

Employee stock-based awards

We recognize compensation expense on employee stock-based awards on a straight-line basis; forfeitures are recognized when they occur.

Pension and other postretirement benefits

The funded status of each of the pension and other postretirement benefit plans is recognized separately in the Consolidated Balance Sheet as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan’s benefit obligation. 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 and unrecognized prior service costs and credits 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). 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 6 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.

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 the Consolidated Statement of Operations 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 the Consolidated Statement of Operations includes any dilutive effect of nonvested restricted stock units, stock options, and convertible instruments, unless otherwise noted. Diluted earnings (loss) per common share is calculated using the treasury-stock method.

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Accounting standards issued and adopted

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changed the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities are required to use a forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. We adopted ASU 2016-13 effective January 1, 2020, which primarily applied to our short-term trade receivables. There was no cumulative effect adjustment to retained earnings upon adoption.

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 business and gathering and transportation business 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 utilized historical loss rates over many years, which included periods of both high and low commodity prices. Commodity prices could have a significant impact on a portion of our gathering and processing counterparties’ financial health and ability to satisfy current liabilities. Our expected credit loss estimate considered 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 considered 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.

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, 2020.

Note 2 – Variable Interest Entities

Consolidated VIEs

As of December 31, 2020, 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

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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 on a proportional basis.

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,
	2020		2019
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	107	$	102
Trade accounts and other receivables – net	148		167
Other current assets and deferred charges	7		5
Property, plant, and equipment – net	5,514		5,745
Intangible assets – net of accumulated amortization	2,376		2,669
Regulatory assets, deferred charges, and other	15		13
Accounts payable	(42)		(58)
Accrued liabilities	(34)		(66)
Regulatory liabilities, deferred income, and other	(289)		(283)

Nonconsolidated VIEs

Targa Train 7

We own a 20 percent interest in Targa Train 7, which provides fractionation services at Mt. Belvieu and is a VIE due primarily to our limited participating rights as the minority equity holder. At December 31, 2020, the carrying value of our investment in Targa Train 7 was $51 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 (see Note 7 – Investing Activities), 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. During the first quarter of 2020 we recorded an impairment of our equity-method investment in Brazos Permian II (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk). Our maximum exposure to loss is limited to the carrying value of our investment.

Note 3 – Acquisitions and Divestitures

UEOM

As of December 31, 2018, we owned a 62 percent interest in Utica East Ohio Midstream LLC (UEOM) which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the

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remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility borrowings and cash on hand, net of $13 million cash acquired. As a result of acquiring this additional interest, we obtained control of and consolidated UEOM.

UEOM is involved primarily in the processing and fractionation of natural gas and natural gas liquids in the Utica Shale play in eastern Ohio. The purpose of the acquisition was to enhance our position in the region. We expect synergies through common ownership of UEOM and our Ohio Valley midstream systems to create a more efficient platform for capital spending in the region, resulting in reduced operating and maintenance expenses and creating enhanced capabilities and benefits for producers in the area.

The acquisition of UEOM was accounted for as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values. In March 2019, based on the transaction price for our purchase of the remaining interest in UEOM as finalized just prior to the acquisition, we recognized a $74 million noncash impairment loss related to our existing 62 percent interest (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk). Thus, there was no gain or loss on remeasuring our existing equity-method investment to fair value due to the impairment recognized just prior to closing the acquisition of the additional interest.

The valuation techniques used to measure the acquisition date fair value of the UEOM acquisition consisted of the market approach for our previous equity-method investment in UEOM and 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 Northeast G&P segment, and liabilities assumed, including post closing purchase price adjustments. The net assets acquired reflect the sum of the consideration transferred and the noncash elimination of the fair value of our existing equity-method investment upon our acquisition of the additional interest. The fair value of accounts receivable acquired, presented in current assets in the table, equals contractual amounts receivable.

	(Millions)
Current assets, including $13 million cash acquired	$	56
Property, plant, and equipment	1,387
Other intangible assets	328
Total identifiable assets acquired	1,771
Current liabilities	7
Total liabilities assumed	7
Net identifiable assets acquired	1,764
Goodwill	187
Net assets acquired	$	1,951

The goodwill recognized in the acquisition related primarily to enhancing and diversifying our basin positions and is reported within the Northeast G&P segment. Substantially all of the goodwill is expected to be deductible for tax purposes. As of December 31, 2019, goodwill was included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet and represented the excess of the consideration, plus the fair value of any previously held equity interest, over the fair value of the net assets acquired.

The goodwill recognized in the UEOM acquisition of $187 million, which includes a $1 million adjustment recorded in the first quarter of 2020, was impaired during first quarter of 2020. Our partner’s $65 million share of

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this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).

Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas gathering, processing, and fractionation 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 a period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 49 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, processing, and fractionation 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 was approximately 10 years.

The following unaudited pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for the years ended December 31, 2019 and 2018, respectively, are presented as if the UEOM acquisition had been completed on January 1, 2018. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date 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,
	2019		2018
	(Millions)
Revenues	$	8,233	$	8,836
Net income (loss) attributable to The Williams Companies, Inc.	928		(128)

Adjustments to pro forma Net income (loss) attributable to The Williams Companies, Inc. include the removal of the previously described $74 million impairment loss recognized in March 2019 just prior to the acquisition.

During the period from the acquisition date of March 18, 2019 to December 31, 2019, UEOM contributed Revenues of $179 million and Net income (loss) attributable to The Williams Companies, Inc. of $53 million.

Costs related to this acquisition are $4 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expenses in the Consolidated Statement of Operations for the year ended December 31, 2019.

Northeast JV

Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner invested approximately $1.33 billion for a 35 percent ownership interest, and we retained 65 percent ownership of, as well as operate and consolidate, the Northeast JV business. The change in ownership due to this transaction increased Noncontrolling interests in consolidated subsidiaries by $567 million, and decreased Capital in excess of par value by $426 million and Deferred income tax liabilities by $141 million in the Consolidated Balance Sheet as of December 31, 2019. Costs related to this transaction are $6 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expenses in the Consolidated Statement of Operations for the year ended December 31, 2019.

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Sale of Gulf Coast Pipeline Systems

In November 2018, we completed the sale of certain assets and operations located in the Gulf Coast area for $177 million in cash. As a result of this sale, we recorded a gain of approximately $101 million in the fourth quarter of 2018, consisting of $81 million in our Transmission & Gulf of Mexico segment and $20 million in Other.

Previous impairments made to a portion of these assets and operations include $66 million related to certain idle pipelines in the second quarter of 2018. The impairment is reflected in Impairment of certain assets in the Consolidated Statement of Operations. (See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) The results of operations for this disposal group, excluding the impairments and gains noted, were not significant for the reporting period.

Sale of Four Corners Assets

In October 2018, we completed the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado for total consideration of $1.125 billion. As a result of this sale, we recorded a gain of approximately $591 million within the West segment in the fourth quarter of 2018.

The following table presents the results of operations for the Four Corners area, excluding the gain noted above:

	Year Ended December 31,
	2018
	(Millions)
Income (loss) before income taxes of Four Corners area	$	52
Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc.	43

Note 4 – Related Party Transactions

Transactions with Equity-Method Investees

We have purchases from our equity-method investees included in Product costs in the Consolidated Statement of Operations of $348 million, $304 million, and $236 million for the years ended 2020, 2019, and 2018, respectively. We have $50 million and $36 million included in Accounts payable in the Consolidated Balance Sheet with our equity-method investees at December 31, 2020 and 2019, 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 $79 million, $103 million, and $75 million for the years ended 2020, 2019, and 2018, respectively.

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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		Northeast Midstream		West Midstream		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		1,204		—		(75)		2,756
Commodity consideration	—		—		21		7		101		—		—		129
Other	10		—		27		164		65		1		(14)		253
Total service revenues	2,414		449		396		1,450		1,370		1		(96)		5,984
Product sales:
NGL and natural gas	80		—		114		57		1,565		—		(147)		1,669
Total revenues from contracts with customers	2,494		449		510		1,507		2,935		1		(243)		7,653
Other revenues (1)	10		—		9		22		8		33		(16)		66
Total revenues	$	2,504	$	449	$	519	$	1,529	$	2,943	$	34	$	(259)	$	7,719
2019
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,336	$	450	$	—	$	—	$	—	$	—	$	(6)	$	2,780
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		479		1,171		1,309		—		(75)		2,884
Commodity consideration	—		—		41		12		150		—		—		203
Other	11		—		26		147		42		—		(16)		210
Total service revenues	2,347		450		546		1,330		1,501		—		(97)		6,077
Product sales:
NGL and natural gas	106		—		185		150		1,795		—		(173)		2,063
Total revenues from contracts with customers	2,453		450		731		1,480		3,296		—		(270)		8,140
Other revenues (1)	1		—		8		20		14		30		(12)		61
Total revenues	$	2,454	$	450	$	739	$	1,500	$	3,310	$	30	$	(282)	$	8,201

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	Transco		Northwest Pipeline		Gulf of Mexico Midstream		Northeast Midstream		West Midstream		Other		Eliminations		Total
	(Millions)
2018
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	1,921	$	443	$	—	$	—	$	—	$	—	$	(2)	$	2,362
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		541		861		1,590		2		(73)		2,921
Commodity consideration	—		—		59		20		321		—		—		400
Other	2		—		17		94		46		—		(15)		144
Total service revenues	1,923		443		617		975		1,957		2		(90)		5,827
Product sales:
NGL and natural gas	127		—		307		287		2,421		—		(382)		2,760
Other	—		—		—		—		21		—		(4)		17
Total product sales	127		—		307		287		2,442		—		(386)		2,777
Total revenues from contracts with customers	2,050		443		924		1,262		4,399		2		(476)		8,604
Other revenues (1)	11		—		18		21		12		32		(12)		82
Total revenues	$	2,061	$	443	$	942	$	1,283	$	4,411	$	34	$	(488)	$	8,686

______________________________

(1)Revenues not within the scope of ASC 606, “Revenue from Contracts with Customers,” consist of leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated equity-method investments, which are reported in Service revenues in the Consolidated Statement of Operations, and amounts associated with our derivative contracts, which are reported in Product sales in the Consolidated Statement of Operations.

Contract Assets

The following table presents a reconciliation of our contract assets:

	Year Ended December 31,
	2020		2019
	(Millions)
Balance at beginning of year	$	8	$	4
Revenue recognized in excess of amounts invoiced	145		62
Minimum volume commitments invoiced	(141)		(58)
Balance at end of year	$	12	$	8

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Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

	Year Ended December 31,
	2020		2019
	(Millions)
Balance at beginning of year	$	1,215	$	1,397
Payments received and deferred	140		157
Significant financing component	11		13
Chesapeake global resolution (Note 1)	67		—
Recognized in revenue	(224)		(352)
Balance at end of year	$	1,209	$	1,215

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, 2020, 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, 2020, 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, 2020.

	Contract Liabilities		Remaining Performance Obligations
	(Millions)
2021	$	129	$	3,537
2022	113		3,329
2023	118		3,076
2024	98		2,443
2025	92		2,310
Thereafter	659		17,760
Total	$	1,209	$	32,455

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Note 6 – Other Income and Expenses

The following table presents by segment, certain items within Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations:

	Transmission & Gulf of Mexico		Northeast G&P		West		Other
	(Millions)
2020
Income related to benefit policy change	$	(22)	$	(9)	$	(9)	$	—
2019
Severance and related costs	39		7		10		1
2018
Expense from charitable contribution of preferred stock to the Williams Companies Foundation, Inc. (Note 16)	—		—		—		35
WPZ Merger related costs	—		—		—		20

Additional Items

Other income (expense) – net below Operating income (loss) includes $15 million, $32 million, and $89 million of income for equity AFUDC within the Transmission & Gulf of Mexico segment for the years ended December 31, 2020, 2019, and 2018, respectively. Other income (expense) – net below Operating income (loss) also includes $(13) million of loss and $9 million and $35 million of income, for the years ended December 31, 2020, 2019, and 2018, respectively, associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction primarily within the Other segment.

Note 7 – Investing Activities

Acquisition of Additional Interests in Caiman II

As of December 31, 2019, we effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent interest in Caiman II, whose primary asset is a 50 percent interest in Blue Racer. On November 18, 2020, we paid $157 million, net of cash acquired, to acquire an additional 41 percent ownership interest in Caiman II. We now control and consolidate Caiman II, reporting the 50 percent interest in Blue Racer as an equity-method investment. Since substantially all of the fair value of the Caiman II assets acquired is concentrated in a single asset, the investment in Blue Racer, and we previously held a noncontrolling interest in Caiman II, we recorded the November 18, 2020, additional purchase of interests as an asset acquisition.

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 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for information regarding impairments of our equity-method investments of $1,046 million, $186 million, and $32 million for 2020, 2019, and 2018, respectively.

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Other Investing Income (Loss) – Net

The following table presents certain items reflected in Other investing income (loss) – net in the Consolidated Statement of Operations:

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Gain (loss) on deconsolidation of businesses	$	—	$	(29)	$	203
Gain on disposition of Jackalope	—		122		—
Other	8		14		16
Other investing income (loss) – net	$	8	$	107	$	219

Constitution deconsolidation

Upon determination that we were no longer the primary beneficiary, we deconsolidated our interest in Constitution Pipeline Company, LLC (Constitution) as of December 31, 2019, recognizing a loss on deconsolidation of $27 million.

Delaware basin asset deconsolidation and Brazos Permian II equity-method investment

During the fourth quarter of 2018, we contributed the majority of our existing Delaware basin assets and $27 million in cash in exchange for a 15 percent interest in the Brazos Permian II, which consists of gas and crude oil gathering pipelines, natural gas processing, and oil storage facilities. We recorded a deconsolidation gain of $141 million reflecting the excess of the fair value of our acquired interest over the carrying value of the assets contributed. We estimated the fair value of our interest to be $192 million primarily using a market approach (a Level 3 measurement within the fair value hierarchy). This approach involved the observation of recent transaction multiples in the Permian basin, including recent acquisitions consummated during 2018. Our interest in Brazos Permian II is considered an equity-method investment due to the fact that we are able to exert significant influence over its operating and financial policies.

Jackalope deconsolidation

During the second quarter of 2018, we deconsolidated our 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope). We recorded our interest in Jackalope as an equity-method investment at its estimated fair value, resulting in a deconsolidation gain of $62 million. We estimated the fair value of our interest to be $310 million using an income approach based on expected future cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of expected future cash flows involved significant assumptions regarding gathering and processing volumes and related capital spending. A 10.9 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. The deconsolidated carrying value of the net assets of Jackalope included $47 million of goodwill.

Gain on disposition of Jackalope

In April 2019, we sold our 50 percent equity-method interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million.

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Equity-Method Investments

	Ownership Interest at December 31, 2020	December 31,
		2020		2019
		(Millions)
Appalachia Midstream Investments	(1)	$	3,087	$	3,236
RMM	50%	421		881
OPPL	50%	395		403
Blue Racer/Caiman II (2)	50%	357		428
Discovery	60%	352		472
Laurel Mountain	69%	219		249
Gulfstream	50%	204		217
Brazos Permian II	15%	—		194
Other	Various	124		155
		$	5,159	$	6,235

___________

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

(2)See previous discussion in the section Acquisition of Additional Interests in Caiman II above.

The carrying value of our Appalachia Midstream Investments exceeds our portion of the underlying net assets by approximately $1.2 billion and $1.4 billion at December 31, 2020 and 2019, 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 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 $1.3 billion and $360 million at December 31, 2020 and 2019, 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 underlying net assets are generally amortized over the remaining useful lives of the associated underlying assets and included in Equity earnings (losses) within the Consolidated Statement of Operations.

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,
	2020		2019		2018
	(Millions)
Blue Racer/Caiman II (1)	$	157	$	28	$	—
Appalachia Midstream Investments	116		140		246
Targa Train 7	6		43		—
Laurel Mountain	5		36		16
RMM	—		145		795
Jackalope	—		24		42
Brazos Permian II	—		18		27
Discovery	—		—		5
Other	41		19		1
	$	325	$	453	$	1,132

___________

(1)See previous discussion in the section Acquisition of Additional Interests in Caiman II above.

97

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

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,
	2020		2019		2018
	(Millions)
Appalachia Midstream Investments	$	357	$	293	$	297
Gulfstream	93		86		93
OPPL	50		77		73
Blue Racer/Caiman II (1)	47		42		46
RMM	39		38		—
Laurel Mountain	31		30		23
Discovery	21		41		45
UEOM	—		13		70
Other	15		37		46
	$	653	$	657	$	693

___________

(1)See previous discussion in the section Acquisition of Additional Interests in Caiman II above.

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

	December 31,
	2020		2019
	(Millions)
Assets (liabilities):
Current assets	$	630	$	581
Noncurrent assets	13,424		11,966
Current liabilities	(312)		(341)
Noncurrent liabilities	(3,884)		(2,532)

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Gross revenue	$	2,625	$	2,490	$	2,411
Operating income	508		685		804
Net income	459		598		795

98

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 8 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Current:
Federal	$	(29)	$	(41)	$	(83)
State	—		(5)		1
Foreign	—		2		—
	(29)		(44)		(82)
Deferred:
Federal	98		280		183
State	10		99		37
	108		379		220
Provision (benefit) for income taxes	$	79	$	335	$	138

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

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Provision (benefit) at statutory rate	$	58	$	224	$	69
Increases (decreases) in taxes resulting from:
Impact of nontaxable noncontrolling interests	3		29		(73)
State income taxes (net of federal benefit)	6		74		(10)
State deferred income tax rate change	—		—		38
Federal valuation allowance	1		3		105
Other – net	11		5		9
Provision (benefit) for income taxes	$	79	$	335	$	138

Income (loss) from continuing operations before income taxes includes $1 million, $6 million, and $3 million of foreign loss in 2020, 2019, and 2018, respectively.

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.

99

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Significant components of Deferred income tax liabilities and Deferred income tax assets are as follows:

	December 31,
	2020		2019
	(Millions)
Deferred income tax liabilities:
Property, plant and equipment	$	2,320	$	1,921
Investments	1,515		1,411
Other	140		82
Total deferred income tax liabilities	3,975		3,414
Deferred income tax assets:
Accrued liabilities	747		729
Minimum tax credit	—		29
Foreign tax credit	140		140
Federal loss carryovers	905		544
State losses and credits	445		362
Other	140		147
Total deferred income tax assets	2,377		1,951
Less valuation allowance	325		319
Net deferred income tax assets	2,052		1,632
Overall net deferred income tax liabilities	$	1,923	$	1,782

The valuation allowance at December 31, 2020 and 2019 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 credit and State losses and credits may not be realized. 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 2021 and 2039 with some carryovers having indefinite carryforward periods.

Federal loss carryovers include deferred tax assets on loss carryovers of $905 million which have no expiration date.

Cash refunds for income taxes (net of payments) were $40 million and $86 million in 2020 and 2019, respectively. Cash payments for income taxes (net of refunds) were $11 million in 2018.

As of December 31, 2020, we had approximately $51 million of unrecognized tax benefits. No change occurred to the amount of unrecognized tax benefits in each of the years 2020 and 2019. If recognized, income tax expense would be reduced by $51 million for each of the years 2020 and 2019, including the effect of these changes on other tax attributes, with state income tax amounts included net of federal tax effect.

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 a benefit of $900 thousand in 2020 and expenses of $500 thousand and $800 thousand for 2019 and 2018, respectively. Approximately $4 million and $3 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2020 and 2019, respectively.

During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.

100

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Consolidated U.S. Federal income tax returns are open to Internal Revenue Service (IRS) examination for years after 2010, excluding 2015 and 2016, for which the statutes have expired. As of December 31, 2020, examinations of tax returns for 2011 through 2014 are currently in appeals. We do not expect material changes in our financial position resulting from these examinations. The statute of limitations for most states expires one year after expiration of the IRS statute. Generally, tax returns for our previously owned Canadian entities are open to audit for tax years after 2012. Tax years 2013 and 2014 are currently under income tax examination. In September 2016, we sold the majority of our Canadian operations and, as part of the sale, indemnified the purchaser for any increases in Canadian tax due to an audit of any tax periods prior to the sale.

Note 9 – Earnings (Loss) Per Common Share from Continuing Operations

	Year Ended December 31,
	2020		2019		2018
	(Dollars in millions, except per-share amounts; shares in thousands)
Income (loss) from continuing operations available to common stockholders	$	208	$	862	$	(156)
Basic weighted-average shares	1,213,631		1,212,037		973,626
Effect of dilutive securities:
Nonvested restricted stock units	1,531		1,811		—
Stock options	3		163		—
Diluted weighted-average shares (1)	1,215,165		1,214,011		973,626
Earnings (loss) per common share from continuing operations:
Basic	$	.17	$	.71	$	(.16)
Diluted	$	.17	$	.71	$	(.16)

________________

(1)    For the year ended December 31, 2018, 2.0 million weighted-average nonvested restricted stock units and 0.5 million weighted-average stock options have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to The Williams Companies, Inc.

Note 10 – 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. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to receive annuity payments, a lump-sum payment, or a combination of annuity and lump-sum payments.

We recognized a pre-tax, noncash settlement charge of $23 million in 2018, which is substantially reported in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations. This amount is included within the subsequent tables of net periodic benefit cost (credit) and other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes.

Other Postretirement Benefits

We currently provide subsidized retiree medical and life insurance benefits to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December 31, 1995. Subsidized retiree medical benefits for eligible participants age 65 and older are paid through contributions to health reimbursement accounts. Subsidized retiree medical benefits for eligible participants under age 65 are provided through a self-insured medical plan sponsored by us. The self-insured retiree medical plan provides for retiree

101

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

contributions and contains other cost-sharing features such as deductibles, co-payments, and co-insurance. The accounting for this plan anticipates estimated future increases to our contribution levels to the health reimbursement accounts for participants age 65 and older, as well as future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line with health care cost increases for participants under age 65.

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 are not eligible to receive compensation credits under the defined benefit pension plan are eligible for a fixed annual contribution made by us to the defined contribution plan. Our contributions charged to expense were $42 million in 2020, $36 million in 2019, and $35 million in 2018.

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
	2020		2019		2020		2019
	(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,237	$	1,187	$	215	$	186
Service cost	31		45		1		1
Interest cost	36		50		7		8
Plan participants’ contributions	—		—		2		2
Benefits paid	(41)		(111)		(14)		(12)
Net actuarial loss (gain)	47		69		9		30
Settlements	(127)		(3)		—		—
Net increase (decrease) in benefit obligation	(54)		50		5		29
Benefit obligation at end of year	1,183		1,237		220		215
Change in plan assets:
Fair value of plan assets at beginning of year	1,299		1,132		247		214
Actual return on plan assets	212		218		37		38
Employer contributions	14		63		6		5
Plan participants’ contributions	—		—		2		2
Benefits paid	(41)		(111)		(14)		(12)
Settlements	(127)		(3)		—		—
Net increase (decrease) in fair value of plan assets	58		167		31		33
Fair value of plan assets at end of year	1,357		1,299		278		247
Funded status — overfunded (underfunded)	$	174	$	62	$	58	$	32
Accumulated benefit obligation	$	1,167	$	1,221

102

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The overfunded (underfunded) status of our pension plans and other postretirement benefit plan presented in the previous table are recognized in the Consolidated Balance Sheet within the following accounts:

	December 31,
	2020		2019
	(Millions)
Overfunded (underfunded) pension plans:
Noncurrent assets	$	203	$	92
Current liabilities	(3)		(3)
Noncurrent liabilities	(26)		(27)
Overfunded (underfunded) other postretirement benefit plan:
Noncurrent assets	64		38
Current liabilities	(6)		(6)

The plan assets within our other postretirement benefit plan are intended to be used for the payment of benefits for certain groups of participants. The Current liabilities for the other postretirement benefit plan represent the current portion of benefits expected to be payable in the subsequent year for the groups of participants whose benefits are not expected to be paid from plan assets.

The pension plans’ benefit obligation Net actuarial loss (gain) of $47 million in 2020 and $69 million in 2019 are primarily due to the impact of decreases in the discount rates utilized to calculate the benefit obligation, partially offset by the impact of decreases in the cash balance interest crediting rate assumption.

The 2020 benefit obligation Net actuarial loss (gain) of $9 million for our other postretirement benefit plan is primarily due to a decrease in the discount rate used to calculate the benefit obligation, partially offset by the net impact of experience related items. The 2019 benefit obligation Net actuarial loss (gain) of $30 million for our other postretirement benefit plan is primarily due to a decrease in the discount rate used to calculate the benefit obligation and other assumption changes, partially offset by the impact of benefit payment experience and tax law changes.

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

	December 31,
	2020		2019
	(Millions)
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	$	29	$	29
Fair value of plan assets	—		—
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	25		26
Fair value of plan assets	—		—

103

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Pre-tax amounts not yet recognized in Net periodic benefit cost (credit) at December 31 are as follows: 

	Pension Benefits				Other Postretirement Benefits
	2020		2019		2020		2019
	(Millions)
Amounts included in Accumulated other comprehensive income (loss):
Net actuarial loss	$	(101)	$	(243)	$	(25)	$	(21)
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Net actuarial gain	N/A		N/A		$	32	$	11

In addition to the regulatory liabilities included in the previous table, differences in the amount of actuarially determined Net periodic benefit cost (credit) for our other postretirement benefit plan and the other postretirement benefit costs recovered in rates for Transco and Northwest Pipeline are deferred as a regulatory asset or liability. We have regulatory liabilities of $100 million at December 31, 2020 and $106 million at December 31, 2019, related to these deferrals. Additionally, Transco recognizes a regulatory liability for rate collections in excess of its amount funded to the tax-qualified pension plans. At December 31, 2020 and 2019, these regulatory liabilities were $39 million and $43 million, respectively. These pension and other postretirement plans amounts will be reflected in rates based on the rate structures of these gas pipelines.

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
	2020		2019		2018		2020		2019		2018
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	31	$	45	$	50	$	1	$	1	$	1
Interest cost	36		50		46		7		8		7
Expected return on plan assets	(53)		(61)		(63)		(11)		(10)		(11)
Amortization of prior service credit	—		—		—		—		—		(2)
Amortization of net actuarial loss	21		15		23		—		—		—
Net actuarial loss from settlements	9		1		23		—		—		—
Reclassification to regulatory liability	—		—		—		2		1		2
Net periodic benefit cost (credit)	$	44	$	50	$	79	$	(1)	$	—	$	(3)

The components of Net periodic benefit cost (credit) other than the service cost component are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations.

104

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Items Recognized in Other Comprehensive Income (Loss) and Regulatory Assets and Liabilities

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
	2020		2019		2018		2020		2019		2018
	(Millions)
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	$	112	$	88	$	(18)	$	(4)	$	(9)	$	9
Amortization of net actuarial loss	21		15		23		—		—		—
Net actuarial loss from settlements	9		1		23		—		—		—
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	$	142	$	104	$	28	$	(4)	$	(9)	$	9

Other changes in plan assets and benefit obligations for our other postretirement benefit plan associated with Transco and Northwest Pipeline are recognized in regulatory assets and liabilities. Amounts recognized in regulatory assets and liabilities for the years ended December 31 consist of the following:

	2020		2019		2018
	(Millions)
Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities:
Net actuarial gain (loss)	$	21	$	7	$	(10)
Amortization of prior service credit	—		—		(2)

Key Assumptions

The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows: 

	Pension Benefits				Other Postretirement Benefits
	2020		2019		2020		2019
Discount rate	2.45	%	3.19	%	2.59	%	3.27	%
Rate of compensation increase	3.76		3.68		N/A		N/A
Cash balance interest crediting rate	3.00		3.50		N/A		N/A

The weighted-average assumptions utilized to determine Net periodic benefit cost (credit) for the years ended December 31 are as follows: 

	Pension Benefits						Other Postretirement  Benefits
	2020		2019		2018		2020		2019		2018
Discount rate	3.08	%	4.33	%	3.67	%	3.27	%	4.39	%	3.71	%
Expected long-term rate of return on plan assets	4.67		5.26		5.34		4.39		5.01		4.95
Rate of compensation increase	3.68		4.83		4.93		N/A		N/A		N/A
Cash balance interest crediting rate	3.50		4.25		4.25		N/A		N/A		N/A

105

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The mortality assumptions used to determine the benefit obligations for our pension and other postretirement benefit plans reflect generational projection mortality tables.

The assumed health care cost trend rate for 2021 is 7.0 percent. This rate decreases to 4.5 percent by 2027.

Plan Assets

Plan assets for our pension and other postretirement benefit plans consist primarily of equity and fixed income securities including mutual funds and commingled investment funds invested in equity and fixed income securities. The plans’ investment policy provides for a strategy in accordance with the Employee Retirement Income Security Act (ERISA), which governs the investment of the assets in a diversified portfolio. The plans follow a policy of diversifying the investments across various asset classes and investment managers.

The investment policy for the pension plans includes a general target asset allocation at December 31, 2020, of 25 percent equity securities and 75 percent fixed income securities. The target allocation includes the investments in equity and fixed income mutual and commingled investment funds.

Equity securities may include U.S. equities and non-U.S. equities. Investment in Williams’ securities or an entity in which Williams has a majority ownership is prohibited except where these securities may be owned in a commingled investment fund in which the plans’ trusts invest. No more than 5 percent of the total stock portfolio valued at market may be invested in the common stock of any one corporation.

Fixed income securities may consist of U.S. as well as international instruments, including emerging markets. The fixed income strategies may invest in U.S. and sovereign government, corporate, asset-backed securities, and mortgage-backed obligations. The weighted-average credit rating of the fixed income strategies must be at least “investment grade” including ratings by Moody’s and/or Standard & Poor’s. No more than 5 percent of the total fixed income portfolio may be invested in the fixed income securities of any one issuer with the exception of bond index funds and U.S. government guaranteed and agency securities.

The following securities and transactions are not authorized: unregistered securities, commodities or commodity contracts, short sales or margin transactions, or other leveraging strategies. Additionally, real estate equity, natural resource property, venture capital, leveraged buyouts, and other high-return, high-risk investments are generally restricted. Use of derivative securities in mutual funds and commingled investment funds held by the plans’ trusts is allowed. However, direct investment in derivative securities requires approval. Currently, investment managers are approved to enter into U.S. Treasury futures contracts on behalf of the plans to implement and manage duration and yield curve strategy in the fixed income portfolio.

There are no significant concentrations of risk within the plans’ investment securities because of the diversity of the types of investments, diversity of the various industries, and the diversity of the fund managers and investment strategies. Generally, the investments held in the plans are publicly traded, therefore, minimizing liquidity risk in the portfolio.

106

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The fair values of our pension plan assets at December 31, 2020 and 2019 by asset class are as follows: 

	2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Pension assets:
Cash management fund	$	21	$	—	$	—	$	21
Equity securities	39		22		—		61
Fixed income securities (1):
U.S. Treasury securities	110		—		—		110
Government and municipal bonds	—		32		—		32
Mortgage and asset-backed securities	—		19		—		19
Corporate bonds	—		342		—		342
Other	—		4		—		4
	$	170	$	419	$	—	589
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							137
Equities — Global large and mid cap							121
Equities — International emerging markets							30
Fixed income — U.S. long and intermediate duration							346
Fixed income — Corporate bonds							134
Total assets at fair value at December 31, 2020							$	1,357

107

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

	2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Pension assets:
Cash management fund	$	11	$	—	$	—	$	11
Equity securities	41		22		—		63
Fixed income securities (1):
U.S. Treasury securities	62		—		—		62
Government and municipal bonds	—		35		—		35
Mortgage and asset-backed securities	—		11		—		11
Corporate bonds	—		360		—		360
Other	5		4		—		9
	$	119	$	432	$	—	551
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							133
Equities — Global large and mid cap							100
Equities — International emerging markets							26
Fixed income — U.S. long and intermediate duration							380
Fixed income — Corporate bonds							109
Total assets at fair value at December 31, 2019							$	1,299

108

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The fair values of our other postretirement benefits plan assets at December 31, 2020 and 2019 by asset class are as follows:

	2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	12	$	—	$	—	$	12
Equity securities	38		10		—		48
Fixed income securities (1):
U.S. Treasury securities	14		—		—		14
Government and municipal bonds	—		4		—		4
Mortgage and asset-backed securities	—		3		—		3
Corporate bonds	—		45		—		45
Mutual fund — Municipal bonds	52		—		—		52
	$	116	$	62	$	—	178
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							18
Equities — Global large and mid cap							16
Equities — International emerging markets							4
Fixed income — U.S. long and intermediate duration							45
Fixed income — Corporate bonds							17
Total assets at fair value at December 31, 2020							$	278

109

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

	2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	11	$	—	$	—	$	11
Equity securities	35		9		—		44
Fixed income securities (1):
U.S. Treasury securities	8		—		—		8
Government and municipal bonds	—		4		—		4
Mortgage and asset-backed securities	—		1		—		1
Corporate bonds	—		43		—		43
Mutual fund — Municipal bonds	46		—		—		46
	$	100	$	57	$	—	157
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							16
Equities — Global large and mid cap							12
Equities — International emerging markets							3
Fixed income — U.S. long and intermediate duration							46
Fixed income — Corporate bonds							13
Total assets at fair value at December 31, 2019							$	247

____________

(1)The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a weighted-average duration of approximately 16 years for 2020 and 14 years for 2019.

(2)    The stated intents of the funds vary based on each commingled fund’s investment objective. These objectives generally include strategies to replicate or outperform various market indices. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 1 day to 30 days. Additionally, the fund managers retain the right to restrict withdrawals from and/or purchases into the funds so as not to disadvantage other investors in the funds. Generally, the funds also reserve the right to make all or a portion of the redemption in-kind rather than in cash or a combination of cash and in-kind.

The fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement of an asset.

Shares of the cash management and mutual funds are valued at fair value based on published market prices as of the close of business on the last business day of the year, which represents the net asset values of the shares held.

The fair values of equity securities traded on U.S. exchanges are derived from quoted market prices as of the close of business on the last business day of the year. The fair values of equity securities traded on foreign exchanges are also derived from quoted market prices as of the close of business on an active foreign exchange on the last business day of the year. However, the valuation requires translation of the foreign currency to U.S. dollars and this translation is considered an observable input to the valuation.

The fair values of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate values of the funds’ assets at fair value less liabilities, divided by the number of units outstanding.

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The fair values of fixed income securities, except U.S. Treasury securities, are determined using pricing models. These pricing models incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads for similar securities to determine fair value. The U.S. Treasury securities are valued at fair value based on closing prices on the last business day of the year reported in the active market in which the security is traded.

Plan Benefit Payments and Employer Contributions

Following are the expected benefits to be paid by the plans. These estimates are based on the same assumptions previously discussed and reflect future service as appropriate. The actuarial assumptions are based on long-term expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant behaviors differ significantly from the actuarial assumptions. 

	Pension Benefits		Other Postretirement Benefits
	(Millions)
2021	$	96	$	14
2022	91		14
2023	86		14
2024	82		13
2025	82		13
2026-2030	378		57

In 2021, we do not expect to contribute to our tax-qualified pension plans. We expect to contribute approximately $2 million to our nonqualified pension plans and approximately $6 million to our other postretirement benefit plan.

Note 11 – 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,
			2020		2019
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	17,813	$	17,593
Construction in progress	Not applicable		289		354
Other	2 - 45		2,658		2,519
Regulated:
Natural gas transmission facilities		1.25 - 7.13	18,688		18,076
Construction in progress	Not applicable	Not applicable	382		586
Other	5 - 45	0.00 - 33.33	2,659		2,382
Total property, plant, and equipment, at cost			42,489		41,510
Accumulated depreciation and amortization			(13,560)		(12,310)
Property, plant, and equipment — net			$	28,929	$	29,200

__________

(1)    Estimated useful life and depreciation rates are presented as of December 31, 2020. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

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Depreciation and amortization expense for Property, plant, and equipment – net was $1.393 billion, $1.390 billion, and $1.392 billion in 2020, 2019, and 2018, respectively.

Regulated Property, plant, and equipment – net includes approximately $507 million and $547 million at December 31, 2020 and 2019, 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, gas transmission pipelines and facilities, gas processing, fractionation, and compression facilities, gas gathering well connections and pipelines, underground storage caverns, and producing wells. 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 $1.159 billion and $1.117 billion are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 2020 and 2019, respectively.

	December 31,
	2020		2019
	(Millions)
Balance at beginning of year	$	1,165	$	1,032
Liabilities incurred (1)	37		15
Liabilities settled	(19)		(8)
Accretion expense	65		59
Revisions (2)	(26)		67
Balance at end of year	$	1,222	$	1,165

___________

(1)As a result of the global resolution with Chesapeake in 2020, we recorded $31 million of ARO related to natural gas properties transferred to us. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

(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 2020 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, decreases in inflation rates, and decreases in the discount rates used in the annual review process. The 2019 revisions reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets, increases in inflation rates, and decreases in the discount rates used in the annual review process.

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 18 – 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.

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Notes to Consolidated Financial Statements – (Continued)

Note 12 – Goodwill and Other Intangible Assets

Goodwill

Changes in the carrying amount of goodwill, included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, by reportable segment for the periods indicated are as follows:

	Northeast G&P
	(Millions)
December 31, 2018	$	—
UEOM Acquisition (Note 3)	188
December 31, 2019	188
Impairment of goodwill (Note 18)	(187)
Other (Note 3)	(1)
December 31, 2020	$	—

Goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with our evaluation of goodwill for impairment during the years ended December 31, 2019, and 2018, respectively.

Other Intangible Assets

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

	2020				2019
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
	(Millions)
Other intangible assets	$	9,561	$	(2,117)	$	9,560	$	(1,789)

Other intangible assets 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 20 years for the acquisition of UEOM and 30 years for other 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. Based on the estimated future revenues during the contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the contractual customer relationships associated with the UEOM acquisition was approximately 10 years. 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 other intangible assets was $328 million, $324 million, and $333 million in 2020, 2019, and 2018, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $328 million.

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Notes to Consolidated Financial Statements – (Continued)

Note 13 – Accrued Liabilities

	December 31,
	2020		2019
	(Millions)
Interest on debt	$	271	$	288
Employee costs	149		226
Estimated rate refund liabilities	—		189
Contract liabilities (Note 5)	129		158
Asset retirement obligation (Note 11)	63		48
Operating lease liabilities (Note 15)	28		21
Other, including accrued loss contingencies	304		346
	$	944	$	1,276

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Notes to Consolidated Financial Statements – (Continued)

Note 14 – Debt and Banking Arrangements

Long-Term Debt

	December 31,
	2020		2019
	(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		—
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		—
Other financing obligation - Atlantic Sunrise	847		857
Other financing obligation - Dalton	257		259
Northwest Pipeline:
7.125% Debentures due 2025	85		85
4% Notes due 2027	500		500
Williams:
4.125% Notes due 2020	—		600
5.25% Notes due 2020	—		1,500
4% Notes due 2021	500		500
7.875% Notes due 2021	371		371
3.35% Notes due 2022	750		750
3.6% Notes due 2022	1,250		1,250
3.7% Notes due 2023	850		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		—
7.5% Debentures due 2031	339		339
7.75% Notes due 2031	252		252
8.75% Notes due 2032	445		445
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
Various — 7.7% to 10.25% Notes and Debentures due 2020 to 2027	3		24
Credit facility loans	—		—
Unamortized debt issuance costs	(125)		(119)
Net unamortized debt premium (discount)	(63)		(58)
Total long-term debt, including current portion	22,344		22,288
Long-term debt due within one year	(893)		(2,140)
Long-term debt	$	21,451	$	20,148

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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, 2020
	(Millions)
2021	$	894
2022	2,025
2023	1,477
2024	2,280
2025	1,617

Issuances and retirements

On August 17, 2020, we retired $600 million of 4.125 percent senior unsecured notes that were 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. As part of the issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes. Under the terms of the agreement, Transco was obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. In the fourth quarter of 2020, Transco filed the registration statement and completed the exchange offer.

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.

We retired $32 million of 7.625 percent senior unsecured notes that matured on July 15, 2019.

Other financing obligations

During the construction of the Atlantic Sunrise and Dalton projects, Transco received funding from its partners 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 partners’ undivided interest in the assets, including the associated pipeline capacity, and reclassified the funding previously received from its partners from noncurrent liabilities to debt. The obligations, which mature in 2038 and 2052, respectively, require monthly interest and principal payments and both bear an interest rate of approximately 9 percent.

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Notes to Consolidated Financial Statements – (Continued)

Credit Facilities

	December 31, 2020
	Stated Capacity		Outstanding
	(Millions)
Long-term credit facility (1)	$	4,500	$	—
Letters of credit under certain bilateral bank agreements			15

________________

(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 2018, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into a credit agreement (Credit Agreement) with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the credit facility is August 10, 2023. 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 August 10, 2025, 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 $1 billion. 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, make certain distributions during an event of default, and 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 and accelerate the maturity of the loans 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 Citibank N.A.'s alternate base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower’s senior unsecured long-term debt ratings.

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 facility, to be no greater than 5.0 to 1, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions with a total aggregate purchase price of $25 million or more has been executed, in which case 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) must be no greater than 65 percent for each of Transco and Northwest Pipeline.

At December 31, 2020, we are in compliance with these covenants.

Commercial Paper Program

In 2018, we entered into a $4 billion commercial paper program. 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

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Notes to Consolidated Financial Statements – (Continued)

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, 2020 and 2019, no commercial paper was outstanding.

Cash Payments for Interest (Net of Amounts Capitalized)

Cash payments for interest (net of amounts capitalized) were $1.149 billion in 2020, $1.153 billion in 2019, and $1.064 billion in 2018.

Note 15 – 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,
	2020		2019
	(Millions)
Lease Cost:
Operating lease cost	$	37	$	40
Variable lease cost	19		27
Sublease income	(1)		(2)
Total lease cost	$	55	$	65
Cash paid for amounts included in the measurement of operating lease liabilities	$	30	$	39
	December 31,
	2020		2019
	(Millions)
Other Information:
Right-of-use asset (included in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet)	$	182	$	207
Operating lease liabilities:
Current (included in Accrued liabilities in the Consolidated Balance Sheet)	$	28	$	21
Noncurrent (included in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet)	$	161	$	188
Weighted-average remaining lease term – operating leases (years)	13		13
Weighted-average discount rate – operating leases	4.60%		4.61%

Prior to adopting ASU 2016-02 “Leases (Topic 842)”, which was effective January 1, 2019, total rent expense was $73 million in 2018 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations.

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Notes to Consolidated Financial Statements – (Continued)

As of December 31, 2020, 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)
2021	$	34
2022	28
2023	23
2024	19
2025	17
Thereafter	140
Total future lease payments	261
Less amount representing interest	72
Total obligations under operating leases	$	189

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

Note 16 – Stockholders' Equity

On January 26, 2021, our board of directors approved a regular quarterly dividend to common stockholders of $0.41 per share payable on March 29, 2021.

Stockholder Rights Agreement

On March 19, 2020, our board of directors approved the adoption of a limited duration stockholder rights agreements (Rights Agreement) and declared a distribution of one preferred stock purchase right for each outstanding share of common stock. The Rights Agreement is intended to protect the interests of us and our stockholders by reducing the likelihood of another party gaining control of or significant influence over us without paying an appropriate premium considering recent volatile markets. Each preferred stock purchase right represents the right to purchase, upon certain terms and conditions, one one-thousandths (.001) of a share of Series C Participating Cumulative Preferred Stock, $1.00 par value per share. Each one-thousandth (.001) of a share of Series C Participating Cumulative Preferred Stock, if issued, would have rights similar to one share of our common stock. The distribution of preferred stock purchase rights occurred on March 30, 2020, to holders of record as of the close of business on that date. The Rights Agreement expires on March 20, 2021. Please see our Current Report on Form 8-K dated March 20, 2020, for additional details of the Rights Agreement.

On August 27, 2020, a purported shareholder filed a putative class action lawsuit in the Delaware Court of Chancery challenging the Rights Agreement. The plaintiff alleges that the individual members of our board of directors breached their fiduciary duties by adopting the Rights Agreement. On September 3, 2020, a purported shareholder filed a separate putative class action lawsuit in the Delaware Court of Chancery, asserting identical claims to the August 27, 2020, lawsuit. Both complaints seek declaratory relief, an injunction against the agreement, and an award of attorneys’ fees and costs, which are not expected to be material. The court consolidated the lawsuits. The trial occurred January 12 through January 14, 2021, and we are awaiting the court’s decision.

Issuance of Preferred Stock

In July 2018, through a wholly owned subsidiary, we contributed 35,000 shares of newly issued Series B Non-Voting Perpetual Preferred Stock (Preferred Stock) to The Williams Companies Foundation, Inc. (a not-for-profit corporation) for use in future charitable and nonprofit causes. The charitable contribution of Preferred Stock was recorded as an expense in the third quarter of 2018. The Preferred Stock was issued for an aggregate value of $35 million and pays non-cumulative quarterly cash dividends when, as and if declared, at a rate of 7.25 percent per year. Our certificate of incorporation authorizes 30 million shares of Preferred Stock, $1 par value per share.

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Notes to Consolidated Financial Statements – (Continued)

AOCI

The following table presents the changes in AOCI by component, net of income taxes:

	Cash Flow Hedges		Foreign Currency Translation		Pension and Other Post Retirement Benefits		Total
	(Millions)
Balance at December 31, 2019	$	(2)	$	(1)	$	(196)	$	(199)
Other comprehensive income (loss) before reclassifications	(2)		—		81		79
Amounts reclassified from accumulated other comprehensive income (loss)	1		—		23		24
Other comprehensive income (loss)	(1)		—		104		103
Balance at December 31, 2020	$	(3)	$	(1)	$	(92)	$	(96)

Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 2020:

Component	Reclassifications		Classification
	(Millions)
Cash flow hedges:
Energy commodity contracts	$	1	Product sales
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit)	30		Other income (expense) – net below Operating income (loss)
Income tax benefit	(7)		Provision (benefit) for income taxes
Reclassifications during the period	$	24

Note 17 – 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, 2020, 31 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 19 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 347 thousand shares at a weighted-average price of $16.07 per share during 2020. Approximately 1.7 million shares were available for purchase under the ESPP at December 31, 2020.

Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations include equity-based compensation expense for the years ended December 31, 2020, 2019, and 2018 of $52 million, $57 million, and $54 million, respectively. Income tax benefit recognized related to the stock-based compensation expense for the years ended December 31, 2020, 2019, and 2018 was $13 million, $14 million, and $14 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2020, was $57 million, substantially all of which related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.7 years.

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Notes to Consolidated Financial Statements – (Continued)

Nonvested Restricted Stock Units

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2020:

Restricted Stock Units Outstanding	Shares	Weighted- Average Fair Value (1)
	(Millions)
Nonvested at December 31, 2019	5.4	$	28.11
Granted	2.8	$	18.32
Forfeited	(0.5)	$	27.90
Vested	(1.5)	$	29.04
Nonvested at December 31, 2020	6.2	$	23.53

______________

(1)Performance-based restricted stock units are valued considering measures of total shareholder return utilizing a Monte Carlo valuation method, as well as return on capital employed and a ratio of debt to EBITDA. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years.

Value of Restricted Stock Units	2020		2019		2018
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	18.32	$	25.87	$	30.48
Total fair value of restricted stock units vested during the year (in millions)	$	43	$	29	$	35

Performance-based restricted stock units granted under the Plan represent 41 percent of nonvested restricted stock units outstanding at December 31, 2020. These grants may be earned at the end of the vesting period based on actual performance against a performance target. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.

Stock Options

The following summary reflects stock option activity and related information for the year ended December 31, 2020:

Stock Options	Options	Weighted- Average Exercise Price		Aggregate Intrinsic Value
	(Millions)			(Millions)
Outstanding at December 31, 2019	6.8	$	32.64
Granted	—	$	—
Exercised	(0.3)	$	17.28
Cancelled	(0.5)	$	34.04
Outstanding at December 31, 2020	6.0	$	33.18	$	—
Exercisable at December 31, 2020	5.7	$	33.41	$	—

The following table summarizes additional information related to stock option activity during each of the last three years:

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Total intrinsic value of options exercised	$	1	$	6	$	3
Tax benefits realized on options exercised	$	—	$	1	$	—
Cash received from the exercise of options	$	3	$	4	$	9

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Notes to Consolidated Financial Statements – (Continued)

The weighted-average remaining contractual lives for stock options outstanding and exercisable at December 31, 2020, were 3.5 years and 3.3 years, respectively.

The estimated fair value at date of grant of options for our common stock granted in each respective year, using the Black-Scholes option pricing model, is as follows:

	2018
Weighted-average grant date fair value of options for our common stock granted during the year, per share	$	5.49
Weighted-average assumptions:
Dividend yield	4.7		%
Volatility	30.1		%
Risk-free interest rate	2.7		%
Expected life (years)	6.0

There were no stock options granted in 2020 or 2019. The expected dividend yield for each respective year is based on the dividend forecast for that year and the grant-date market price of our stock. Our expected future volatility is determined using the historical volatility of our stock and implied volatility on our traded options. Historical volatility is based on the blended 10-year historical volatility of our stock and certain peer companies. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.

Note 18 – 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, margin deposits, and accounts payable 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, 2020:
Measured on a recurring basis:
ARO Trust investments	$	235	$	235	$	235	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(22,344)		(27,043)		—		(27,043)		—
Guarantees	(40)		(27)		—		(11)		(16)
Assets (liabilities) at December 31, 2019:
Measured on a recurring basis:
ARO Trust investments	$	201	$	201	$	201	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(22,288)		(25,319)		—		(25,319)		—
Guarantees	(41)		(27)		—		(11)		(16)

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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 the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

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 lateral and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach (see Note 14 – 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 liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $27 million at December 31, 2020. 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 the 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 (NYSE: WMB), 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 (COVID-19) pandemic. As a result of these conditions, we performed an interim assessment of the goodwill

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associated with our Northeast G&P reporting unit as of March 31, 2020. This goodwill resulted from the March 2019 acquisition of UEOM (see Note 3 – Acquisitions and Divestitures).

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 the Consolidated Statement of Operations. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations (see Note 3 – Acquisitions and Divestitures).

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		2020		2019		2018
			(Millions)
Impairment of certain assets:
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
Certain pipeline project (3)	Transmission & Gulf of Mexico	December 31, 2019	22				$	354
Certain gathering assets (4)	West	December 31, 2019	25				20
Certain gathering assets (4)	West	June 30, 2019	40				59
Certain idle gathering assets (5)	West	March 31, 2019	—				12
Certain gathering assets (6)	West	December 31, 2018	470						$	1,849
Certain idle pipeline assets (7)	Other	June 30, 2018	25						66
Other impairments and write-downs (8)							19
Impairment of certain assets					$	182	$	464	$	1,915

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					Impairments
					Year Ended December 31,
	Segment	Date of Measurement	Fair Value		2020		2019		2018
			(Millions)
Impairment of equity-method investments:
RMM (9)	West	December 31, 2020	$	421	$	108
RMM (10)	West	March 31, 2020	557		243
Brazos Permian II (10)	West	March 31, 2020	—		193
Caiman II (11)	Northeast G&P	March 31, 2020	191		229
Appalachia Midstream Investments (11)	Northeast G&P	March 31, 2020	2,700		127
Aux Sable (11)	Northeast G&P	March 31, 2020	7		39
Laurel Mountain (11)	Northeast G&P	March 31, 2020	236		10
Discovery (11)	Transmission & Gulf of Mexico	March 31, 2020	367		97
Laurel Mountain (12)	Northeast G&P	September 30, 2019	242				$	79
Appalachia Midstream Investments (13)	Northeast G&P	September 30, 2019	102				17
Pennant (14)	Northeast G&P	August 31, 2019	11				17
UEOM (15)	Northeast G&P	March 17, 2019	1,210				74
UEOM (15)	Northeast G&P	December 31, 2018	1,293						$	32
Other							(1)
Impairment of equity-method investments					$	1,046	$	186	$	32

______________

(1)Relates to capitalized project development costs for the Northeast Supply Enhancement project. As previously disclosed, 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, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now required impairment. The estimated fair value of the materials within the capitalized project costs 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.

(2)Relates to a gathering system in the Marcellus Shale region, that is more likely than not to be sold in the short term. 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.

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(3)Relates to the Constitution proposed pipeline project extending from Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems in New York. Although Constitution received a certificate of public convenience and necessity from the FERC to construct and operate the proposed pipeline and obtained, among other approvals, a waiver of the water quality certification under Section 401 of the Clean Water Act for the New York portion of the project, the members of Constitution, following extensive evaluation and discussion, determined that the underlying risk-adjusted return for this greenfield pipeline project had diminished in such a way that further development was no longer supported. The estimated fair value of the Property, plant, and equipment – net was based on probability-weighted third-party quotes. Our partners’ $209 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations.

(4)Relates to a gas gathering system in the Eagle Ford Shale region with expected declines in asset utilization and possible idling of the gathering system. We designated these operations as held for sale, included in Other current assets and deferred charges, as of December 31, 2019. As a result, we measured the fair value of the disposal group using the expected sales price under a contract with a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value of the Property, plant, and equipment – net at June 30, 2019, was determined using a market approach, which incorporated indications of interest from third parties.

(5)Reflects impairment of Property, plant, and equipment – net that is no longer in use for which the fair value was determined to be lower than the carrying value.

(6)Relates to our gathering operations in the Barnett Shale region. Certain of our contractual gathering rates, primarily those in the Barnett Shale region, are based on a percentage of the New York Mercantile Exchange (NYMEX) natural gas prices. During the fourth quarter of 2018, we determined there was a sustained decline in the forward price curves for natural gas. During this same period, a large producer customer in the Barnett Shale region removed their remaining drilling rig. These factors gave rise to an impairment evaluation of these assets, which incorporated management’s projections of future drilling activity and gathering rates, taking into consideration the information previously noted as well as recently available information regarding producer drilling cost assumptions in the basin. The resulting estimate of future undiscounted cash flows was less than our carrying value, necessitating the estimation of the fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization. To arrive at the fair value, we utilized an income approach with a discount rate of 8.5 percent, reflecting an estimated cost of capital and risks associated with the underlying assets.

(7)Relates to certain idle pipelines. The estimated fair value of the Property, plant, and equipment – net was determined by a market approach incorporating information derived from bids received for these assets, which we marketed for sale together with certain other assets. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. We sold these assets in the fourth quarter of 2018. (See Note 3 – Acquisitions and Divestitures.)

(8)Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value.

(9)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.

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(10)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 recent market declines previously discussed.

(11)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 Caiman II 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 recent market declines previously discussed.

(12)Relates to a gas gathering system in the Marcellus Shale region that was adversely impacted by lower sustained forward natural gas price expectations and changes in expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 10.2 percent in our analysis.

(13)Relates to a certain gathering system held in Appalachia Midstream Investments that was adversely impacted by changes in the timing of expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 9 percent in our analysis.

(14)The estimated fair value of Pennant Midstream, LLC (Pennant) was determined by a market approach based on recent observable third-party transactions. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

(15)The estimated fair value at March 17, 2019, was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the acquisition in March 2019 (see Note 3 – Acquisitions and Divestitures). These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value at December 31, 2018, was determined by a market approach based on our analysis of inputs in the principal market.

Concentration of Credit Risk

The following table summarizes concentration of receivables, net of allowances:

	December 31,
	2020		2019
	(Millions)
NGLs, natural gas, and related products and services	$	638	$	613
Transportation of natural gas and related products	254		277
Accounts Receivable related to revenues from contracts with customers	892		890
Other	107		106
Trade accounts and other receivables - net	$	999	$	996

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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, but customers’ financial condition and credit worthiness are evaluated regularly. Based upon this evaluation, we may obtain collateral to support receivables.

Note 19 – Contingent Liabilities and Commitments

Reporting of Natural Gas-Related Information to Trade Publications

Direct and indirect purchasers of natural gas in various states filed individual and class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter.

In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland appealed. On March 27, 2018, the appellate court reversed the district court’s grant of summary judgment, and on April 10, 2018, the defendants filed a petition for rehearing with the appellate court, which was denied on May 9, 2018. The case was remanded to the Nevada federal district court and subsequently remanded to its originally filed court, the Kansas federal district court where we re-urged our motion for summary judgment. The district court denied the motion but granted our request to seek permission for an immediate appeal to the appellate court. Oral argument occurred before the appellate court on January 19, 2021.

In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order. On August 6, 2018, the Ninth Circuit reversed the order denying class certification and remanded the case to the Nevada federal district court.

We reached an agreement to settle two of the actions, and on April 22, 2019, the Nevada federal district court preliminarily approved the settlements, which are on behalf of Kansas and Missouri class members. The final fairness hearing on the settlement occurred August 5, 2019, and a final judgment of dismissal with prejudice was entered the same day.

Two putative class actions remain unresolved, and they have been remanded to their originally filed court, the Wisconsin federal district court. Trial is scheduled to begin June 14, 2021.

Because of the uncertainty around the remaining unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter and, as a result, have exposure to future developments.

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

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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. 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, 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 tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would apply to both Chesapeake and us. The settlement as reported would not require any contribution from us.

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

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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. The Court of Chancery had scheduled trial for May 20 through May 24, 2019; the court struck this setting and reset the trial for June 8 through June 11, and June 15, 2020. Due to COVID-19, the court struck the June 2020 setting and re-scheduled the trial for August 31 through September 4, 2020; this setting was also struck as a result of COVID-19. The court reset trial for December 14 through December 18, 2020, but also struck this setting as a result of COVID-19. Trial has been reset for May 10 through May 17, 2021.

Former Olefins Business

SABIC Petrochemicals, the other interest owner in our former Geismar, Louisiana, olefins facility we sold in July 2017, sought recovery from us for losses it allegedly suffered, including its share of personal injury settlements in which it was a co-defendant, as well as amounts related to lost income, defense costs, and property damage associated with an explosion and fire at the plant in June 2013. We settled this claim with SABIC Petrochemicals in the fourth quarter 2020. Part of the settlement is covered by our general liability policy and any uninsured losses are immaterial.

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, 2020, we have accrued liabilities totaling $33 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

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December 31, 2020, 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 promulgate and propose 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, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to 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. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

Continuing operations

Our interstate gas pipelines are involved in remediation 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, 2020, we have accrued liabilities of $4 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2020, we have accrued liabilities totaling $8 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, 2020, we have accrued environmental liabilities of $21 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

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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, 2020, 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 $262 million at December 31, 2020.

Note 20 – Segment Disclosures

Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, and West. 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 revenues primarily represent the sale of NGLs from our natural gas processing plants and transportation services provided to our marketing business.

We define Modified EBITDA as follows:

•Net income (loss) before:

◦Income (loss) from discontinued operations;

◦Provision (benefit) for income taxes;

◦Interest incurred, net of interest capitalized;

◦Equity earnings (losses);

◦Impairment of equity-method investments;

◦Other investing income (loss) – net;

132

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

◦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.

133

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 Operations and Other financial information:

	Transmission & Gulf of Mexico		Northeast G&P		West		Other		Eliminations		Total
	(Millions)
2020
Segment revenues:
Service revenues
External	$	3,207	$	1,416	$	1,280	$	21	$	—	$	5,924
Internal	50		49		—		13		(112)		—
Total service revenues	3,257		1,465		1,280		34		(112)		5,924
Total service revenues – commodity consideration	21		7		101		—		—		129
Product sales
External	144		16		1,506		—		—		1,666
Internal	47		41		56		—		(144)		—
Total product sales	191		57		1,562		—		(144)		1,666
Total revenues	$	3,469	$	1,529	$	2,943	$	34	$	(256)	$	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
2019
Segment revenues:
Service revenues
External	$	3,261	$	1,291	$	1,364	$	17	$	—	$	5,933
Internal	50		47		—		13		(110)		—
Total service revenues	3,311		1,338		1,364		30		(110)		5,933
Total service revenues – commodity consideration	41		12		150		—		—		203
Product sales
External	217		115		1,733		—		—		2,065
Internal	71		35		64		—		(170)		—
Total product sales	288		150		1,797		—		(170)		2,065
Total revenues	$	3,640	$	1,500	$	3,311	$	30	$	(280)	$	8,201
Other financial information:
Additions to long-lived assets	$	1,341	$	1,245	$	304	$	21	$	—	$	2,911
Proportional Modified EBITDA of equity-method investments	177		454		115		—		—		746

134

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

	Transmission & Gulf of Mexico		Northeast G&P		West		Other		Eliminations		Total
	(Millions)
2018
Segment revenues:
Service revenues
External	$	2,904	$	935	$	1,641	$	22	$	—	$	5,502
Internal	49		41		—		12		(102)		—
Total service revenues	2,953		976		1,641		34		(102)		5,502
Total service revenues – commodity consideration	59		20		321		—		—		400
Product sales
External	174		245		2,365		—		—		2,784
Internal	261		42		83		—		(386)		—
Total product sales	435		287		2,448		—		(386)		2,784
Total revenues	$	3,447	$	1,283	$	4,410	$	34	$	(488)	$	8,686
Other financial information:
Additions to long-lived assets	$	2,379	$	477	$	279	$	36	$	—	$	3,171
Proportional Modified EBITDA of equity-method investments	183		493		94		—		—		770

The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Operations:

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico	$	2,379	$	2,175	$	2,293
Northeast G&P	1,489		1,314		1,086
West	998		952		38
Other	(15)		6		(29)
	4,851		4,447		3,388
Accretion expense associated with asset retirement obligations for nonregulated operations	(35)		(33)		(33)
Depreciation and amortization expenses	(1,721)		(1,714)		(1,725)
Impairment of goodwill	(187)		—		—
Equity earnings (losses)	328		375		396
Impairment of equity-method investments	(1,046)		(186)		(32)
Other investing income (loss) – net	8		107		219
Proportional Modified EBITDA of equity-method investments	(749)		(746)		(770)
Interest expense	(1,172)		(1,186)		(1,112)
(Provision) benefit for income taxes	(79)		(335)		(138)
Income (loss) from discontinued operations	—		(15)		—
Net income (loss)	$	198	$	714	$	193

135

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The following table reflects Total assets and Equity-method investments by reportable segments:

	Total Assets				Equity-Method Investments
	December 31, 2020		December 31, 2019		December 31, 2020		December 31, 2019
	(Millions)
Transmission & Gulf of Mexico	$	19,110	$	18,796	$	610	$	741
Northeast G&P	14,569		15,399		3,682		3,973
West	10,558		11,265		867		1,521
Other	927		1,151		—		—
Eliminations (1)	(999)		(571)		—		—
Total	$	44,165	$	46,040	$	5,159	$	6,235

______________

(1)    Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program.

Note 21 – Subsequent Event

In February 2021, we acquired certain oil and gas properties, primarily approximately 2,000 operated wells, in the Wamsutter basin in Wyoming from a supermajor oil and gas company for a total of $79 million paid from cash on hand. We are working to identify an operating partner to optimize development of the properties and enhance the value of our connected midstream infrastructure. We expect to report these operations within our Other segment.

136

The Williams Companies, Inc.

Schedule II — Valuation and Qualifying Accounts

			Additions
	Beginning Balance		Charged (Credited) To Costs and Expenses		Other		Deductions		Ending Balance
	(Millions)
2020
Deferred tax asset valuation allowance (1)	$	319	$	6	$	—	$	—	$	325
2019
Deferred tax asset valuation allowance (1)	320		(1)		—		—		319
2018
Deferred tax asset valuation allowance (1)	224		96		—		—		320

__________

(1)    Deducted from related assets.

137

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 Securities Exchange Act) (Disclosure 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 error or mistake. 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 make modifications as necessary; our intent in this regard is that the Disclosure 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 2020 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 Securities Exchange Act of 1934). 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.

138

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 as of December 31, 2020, 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, as of December 31, 2020, 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.

139

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, 2020, 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, 2020, 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, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and the financial statement schedule listed in the index at Item 15(a) and our report dated February 24, 2021, 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 24, 2021

140

Item 9B. Other Information

None.

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 “Election of Directors” in our definitive proxy statement prepared for the solicitation of proxies in connection with our Annual Meeting of Stockholders to be held April 27, 2021, which shall be filed no later than March 18, 2021 (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 Code of Business Conduct, together with 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 and Other Information,” “Compensation of Directors,” “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 Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

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 Ownership of Certain Beneficial Owners and Management” in our Proxy Statement, which information is incorporated by reference herein.

141

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.

142

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) 1 and 2.

	Page
Covered by report of independent auditors:
Consolidated statement of operations for each year in the three-year period ended December 31, 2020	70
Consolidated statement of comprehensive income (loss) for each year in the three-year period ended December 31, 2020	71
Consolidated balance sheet at December 31, 2020 and 2019	72
Consolidated statement of changes in equity for each year in the three-year period ended December 31, 2020	73
Consolidated statement of cash flows for each year in the three-year period ended December 31, 2020	74
Notes to consolidated financial statements	75
Schedule for each year in the three-year period ended December 31, 2020:
II — Valuation and qualifying accounts	137

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 12, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners, L.P., and WPZ GP LLC (filed on May 13, 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).
2.2	—	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).
2.3	—	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).
2.4	—	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).

143

Exhibit No.		Description
2.5	—	Interest Swap and Purchase Agreement by and among Western Gas Partners, LP, WGR Operating, LP, Delaware Basin JV Gathering LLC, Williams Partners L.P., Williams Midstream Gas Services LLC, and Appalachia Midstream Services, L.L.C., dated February 9, 2017 (filed on February 10, 2017, 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).
2.6	—	Membership Interest Purchase Agreement, dated as of April 13, 2017, among Williams Field Services Group, LLC, Williams Partners L.P., Williams Olefins, L.L.C., NOVA Chemicals Inc., and NOVA Chemicals Corporation (filed on August 3, 2017, as Exhibit 2.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) 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).
3.3	—	Certificate of Designations of Series C Participating Preferred Stock of The Williams Companies, Inc. (filed on March 20, 2020, as Exhibit 3.1 to The Williams Companies, Inc. current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.4	—	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).
3.5	—	By-laws (filed on January 20, 2017, 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).
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).

144

Exhibit No.		Description
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).
4.10	—	First Supplemental 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 4.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.11	—	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).
4.12	—	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).
4.13	—	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).
4.14	—	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).
4.15	—	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).
4.16	—	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).

145

Exhibit No.		Description
4.17	—	Second Supplemental Indenture, dated as of November 17, 2011, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed November 18, 2011, 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).
4.18	—	Third Supplemental Indenture (including Form of 3.35% Senior Notes due 2022), dated as of August 14, 2012, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 14, 2012 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).
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).

146

Exhibit No.		Description
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).
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	—	Rights Agreement, dated as of March 20, 2020, between The Williams Companies, Inc. and Computershare Trust Company, N.A., as Rights Agent, which includes the Form of Certificate of Designation of Series C Participating Cumulative Preferred Stock of The Williams Companies, Inc. as Exhibit A, the Summary of Terms of the Rights Agreement as Exhibit B and the Form of Right Certificate as Exhibit C (filed on March 20, 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).
4.36*	—	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).

147

Exhibit No.		Description
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 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 22, 2017, as Exhibit 10.18 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 Time-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 22, 2017, as Exhibit 10.19 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 2016 Time-Based Restricted Stock Unit Agreement among Williams and certain employees and officers vesting February 22, 2019 (filed on February 22, 2017, as Exhibit 10.20 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 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).
10.12§	—	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).
10.13§	—	Form of 2017 Time-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 22, 2017, as Exhibit 10.23 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.14§	—	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).
10.15§	—	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).
10.16§	—	Form of 2017 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on May 4, 2017, as Exhibit 10.10 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 2018 Time-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on May 3, 2018, 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 2018 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on May 3, 2018, 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).

148

Exhibit No.		Description
10.19§	—	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).
10.20§	—	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).
10.21§	—	Form of 2019 Executive Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on May 2, 2019, 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).
10.22§	—	Amended Form of 2019 Performance-Base 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).
10.23§	—	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).
10.24§	—	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).
10.25§	—	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).
10.26§	—	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).
10.27§	—	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).
10.28§*	—	Form of Time-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers.
10.29§*	—	Form of Time-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain non-management directors.
10.30§	—	The Williams Companies, Inc. 1996 Stock Plan for Nonemployee Directors (filed on March 27, 1996, as Exhibit B to The Williams Companies, Inc.’s Definitive Proxy Statement (File No. 002-27038) and incorporated herein by reference).
10.31	—	The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of January 23, 2004 (filed on August 5, 2004, 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).

149

Exhibit No.		Description
10.32§	—	Amendment No. 1 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009, as Exhibit 10.11 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.33§	—	Amendment No. 2 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009, as Exhibit 10.12 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.34§	—	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).
10.35§	—	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).
10.36§	—	The Williams Companies, Inc. Executive Severance Pay Plan, dated November 14, 2012 (filed July 20, 2016, as Exhibit 10.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.37§	—	First Amendment to The Williams Companies, Inc. Executive Severance Pay Plan (filed July 20, 2016, 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).
10.38§	—	The Williams Companies, Inc. 2007 Incentive Plan as amended and restated effective July 14, 2016 (filed on February 22, 2017, as Exhibit 10.38 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.39	—	Credit Agreement dated as of July 13, 2018, between The Williams Companies, Inc., Northwest Pipeline LLC, and Transcontinental Gas Pipe Line Company, LLC as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on July 17, 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).
10.40	—	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.

150

Exhibit No.		Description
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

151

Item 16. Form 10-K Summary

Not applicable.

152

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/     JOHN D. PORTER
	John D. Porter Vice President, Controller and Chief Accounting Officer

Date: February 24, 2021

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 24, 2021
Alan S. Armstrong	(Principal Executive Officer)
/s/    JOHN D. CHANDLER	Senior Vice President and Chief Financial Officer	February 24, 2021
John D. Chandler	(Principal Financial Officer)
/s/    JOHN D. PORTER	Vice President, Controller and Chief Accounting Officer	February 24, 2021
John D. Porter	(Principal Accounting Officer)
/s/    STEPHEN W. BERGSTROM	Chairman of the Board	February 24, 2021
Stephen W. Bergstrom
/s/    NANCY K. BUESE	Director	February 24, 2021
Nancy K. Buese
/s/    STEPHEN I. CHAZEN	Director	February 24, 2021
Stephen I. Chazen
/s/    CHARLES I. COGUT	Director	February 24, 2021
Charles I. Cogut
/s/ STACEY H. DORÉ	Director	February 24, 2021
Stacey H. Doré
/s/    MICHAEL A. CREEL	Director	February 24, 2021
Michael A. Creel
/s/    VICKI L. FULLER	Director	February 24, 2021
Vicki L. Fuller
/s/    PETER A. RAGAUSS	Director	February 24, 2021
Peter A. Ragauss

153

Signature	Title	Date
/s/   ROSE M. ROBESON	Director	February 24, 2021
Rose M. Robeson
/s/    SCOTT D. SHEFFIELD	Director	February 24, 2021
Scott D. Sheffield
/s/    MURRAY D. SMITH	Director	February 24, 2021
Murray D. Smith
/s/    WILLIAM H. SPENCE	Director	February 24, 2021
William H. Spence

154

EX-4.36

Exhibit 4.36

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.

Preferred Stock Purchase Rights

On March 19, 2020, our board of directors approved the adoption of a limited duration stockholder rights agreement (the “Rights Agreement”) and declared a distribution of one preferred stock purchase right (a “Right”) for each outstanding share of common stock. The Rights Agreement is intended to protect the interests of us and our stockholders by reducing the likelihood of another party gaining control of or significant influence over us without paying an appropriate premium considering recent volatile markets. Each preferred stock purchase right represents the right to purchase, upon certain terms and conditions, one one-thousandth of a share of Series C Participating Cumulative Preferred Stock, $1.00 par value per share (“Series C Preferred Stock”). Each one-thousandth of a share of Series C Preferred Stock, if issued, would have rights similar to one share of our common stock. The distribution of preferred stock purchase rights occurred on March 30, 2020 (the “Record Date”), to holders of record as of the close of business on that date. The Rights Agreement expires on March 20, 2021.

The description and terms of the Rights are set forth in a Rights Agreement between us and Computershare Trust Company, N.A., as Rights Agent (the “Rights Agent”). The Rights Agreement has been filed as Exhibit 4.7 to the registration statement of which this prospectus is a part and is incorporated by reference herein.

2

The board of directors of directors has adopted the Rights Agreement to reduce the likelihood that a potential acquirer would gain (or seek to influence or change) control of us by open market accumulation or other tactics without paying an appropriate premium for our shares. In general terms and subject to certain exceptions, it works by imposing a significant penalty upon any person or group (including a group of persons that are acting in concert with each other) that acquires 5% or more of our outstanding common stock without the approval of the board of directors.

The Rights

The board of directors authorized the issuance of a Right with respect to each outstanding share of common Stock on the Record Date. The Rights will initially trade with, and will be inseparable from, the common stock, and the registered holders of the common stock will be deemed to be the registered holders of the Rights. Issuances of new shares of common stock after the Record Date but before the Distribution Date, as defined under the subheading “Exercisability” below, will be accompanied by new Rights.

Prior to the Distribution Date, the Rights will be evidenced by the certificates for (or by the book entry account that evidences record ownership of) the common stock. After the Distribution Date, the Rights Agent will mail separate certificates (“Rights Certificates”) evidencing the Rights to each record holder of the common stock as of the close of business on the Distribution Date, and thereafter the Rights will be transferable separately from the common stock.

Exercisability

The Rights will not be exercisable until after the Distribution Date. After the Distribution Date, each Right will be exercisable to purchase, for $60.68 (the “Purchase Price”), one one-thousandth of a share of Series C Preferred Stock. This portion of a share of Series C Preferred Stock will give the stockholder approximately the same dividend, voting or liquidation rights as would one share of common stock. Prior to exercise, Rights holders in their capacity as such have no rights as a stockholder of ours, including the right to vote and to receive dividends.

The “Distribution Date” generally means the earlier of:

•the close of business on the 10th business day after the date of the first public announcement that a person or any of its affiliates and associates has become an “Acquiring Person,” as defined below, and

3

•the close of business on the 10th business day (or such later day as may be designated by the board of directors before any person has become an Acquiring Person) after the date of the commencement of a tender or exchange offer by any person which would, if consummated, result in such person becoming an Acquiring Person.

An “Acquiring Person” generally means any person who or which, together with all affiliates and associates of such person obtains beneficial ownership of 5% or more of shares of common stock, with certain exceptions, including that an Acquiring Person does not include us, any subsidiary of ours, any employee benefit plan of ours or any subsidiary of ours, any entity or trustee holding common stock for or pursuant to the terms of any such plan or for the purpose of funding any such plan or other benefits for employees of ours or of any subsidiary of ours or any passive investor. A passive investor generally means any person beneficially owning shares of common stock without a plan or an intent to seek control of or influence us. The Rights Agreement also provides that any person that would otherwise be deemed an Acquiring Person as of the date of the adoption of the Rights Agreement will be exempted but only for so long as it does not acquire, without the prior approval of the board of directors, beneficial ownership of any additional common stock following the adoption of the Rights Agreement.

Certain synthetic interests in securities created by derivative positions, whether or not such interests are considered to be ownership of underlying shares of common stock or are reportable for purposes of Regulation 13D of the Exchange Act, are treated as beneficial ownership of the number of shares of common stock equivalent to the economic exposure created by the derivative positions, to the extent actual shares of common stock are directly or indirectly held by counterparties to the derivatives contracts.

Consequences of a Person or Group Becoming an Acquiring Person

Flip in. Subject to our exchange rights, described below, at any time after any person has become an Acquiring Person, each holder of a Right (other than an Acquiring Person, its affiliates and associates) will be entitled to purchase for each Right held, at the Purchase Price, a number of shares of common stock having a market value of twice the Purchase Price.

Exchange. At any time on or after any person has become an Acquiring Person (but before any person becomes the beneficial owner of 50% or more of the outstanding shares of Common Stock or the occurrence of any of the events described in the next paragraph), the board of directors may exchange all or part of the Rights (other than Rights beneficially owned by an Acquiring Person, its affiliates and associates) for shares of common stock at an exchange ratio of one share of common stock per Right.

4

Flip over. If, after any person has become an Acquiring Person, (1) we are involved in a merger or other business combination in which we are not the surviving corporation or our common stock is exchanged for other securities or assets or (2) we and/or one or more of our subsidiaries sell or otherwise transfer assets or earning power aggregating more than 50% of the assets or earning power of us and our subsidiaries, taken as a whole, then each Right (other than Rights beneficially owned by an Acquiring Person, its affiliates and associates) will entitle the holder to purchase for each Right held, for the Purchase Price, a number of shares of common stock of the other party to such business combination or sale (or in certain circumstances, an affiliate) having a market value of twice the Purchase Price.

Expiration

The Rights will expire on the first anniversary of the date of the Rights Agreement, unless earlier exercised, exchanged, amended or redeemed.

Redemption

The board of directors may redeem all of the Rights at a price of $0.001 per Right at any time before any person has become an Acquiring Person. If the board of directors redeems any Rights, it must redeem all of the Rights. Once the Rights are redeemed, the only right of the holders of Rights will be to receive the redemption price per Right. The redemption price will be subject to adjustment.

Amendment

At any time before any person has become an Acquiring Person, the Rights Agreement may be amended in any respect. After such time, the Rights Agreement may be amended (i) to cure any ambiguity, (ii) to correct any defective or inconsistent provision, or (iii) in any respect that does not adversely affect Rights holders (other than any Acquiring Person, its affiliates and associates).

Antidilution

The Rights Agreement includes antidilution provisions designed to prevent efforts to diminish the effectiveness of the Rights.

5

Series C Participating Cumulative Preferred Stock

The value of one one-thousandth interest in a share of Series C Preferred Stock should approximate the value of one share of common stock, subject to adjustment. Each one one-thousandth of a share of Series C Preferred Stock, if issued:

•will not be redeemable;

•will entitle holders to quarterly dividend payments of $0.01 per share, or an amount equal to the dividend paid on one share of common stock, whichever is greater;

•will entitle holders upon liquidation either to receive $1.00 per share or an amount equal to the payment made on one share of common stock, whichever is greater;

•will have the same voting power as one share of common stock and will vote together with the holders of common stock as a single class on all matters submitted to a vote of stockholders; and

•if shares of common stock are exchanged via merger, consolidation, or a similar transaction, will entitle holders to a per share payment equal to the payment made on one share of common stock.

Rank. The Series C Preferred Stock, if issued, shall rank as to the payment of dividends and the distribution of assets upon liquidation, dissolution and winding-up junior to all other series of the preferred stock of ours unless the board of directors shall specifically determine otherwise.

Additional Voting Rights. If at any time dividends on any Series C Preferred Stock shall be in arrears in an amount equal to six quarterly dividends thereon, the number of directors constituting the board of directors will be increased by two. The occurrence of such contingency will mark the beginning of a period (a “default period”), which shall extend until such time when all accrued and unpaid dividends for all previous quarterly dividend periods and for the current quarterly dividend period on all shares of Series C Preferred Stock then outstanding shall have been declared and paid or set apart for payment. During each default period, all holders of Series C Preferred Stock and any other series of preferred stock then entitled as a class to elect directors, voting together as a single class, irrespective of series, shall have the right to elect two directors. Immediately upon the expiration of a default period, the right of the holders of preferred stock as a class to elect directors shall cease, the term of any directors elected by the holders of preferred stock as a class shall terminate, and the number of directors constituting the board of directors shall be reduced by two. Except as described above, holders of Series C

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Preferred Stock do not have any special voting rights and their consent is not required (except to the extent they are entitled to vote with holders of common stock) for taking any corporate action.

Redemption and Other Rights.The Series C Preferred Stock is not subject to redemption by us or at the option of any holder of Series C Preferred Stock. The shares of Series C Preferred Stock are not subject to or entitled to the operation of a retirement or sinking fund. The shares of Series C Preferred Stock do not have any rights of preemption whatsoever as to any of our securities.

Anti-TakeoverProvisions

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

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•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.

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EX-10.28

Exhibit 10.28

Date=Grant Date                                

TO:        Participant Name

FROM:    

SUBJECT:    [YEAR]Restricted Stock Unit Award

You have been selected to receive a restricted stock unit award. This award is subject to the terms and conditions of The Williams Companies, Inc. 2007 Incentive Plan, as amended and restated from time to time, and, the [YEAR] Restricted Stock Unit Agreement (the “Agreement”).

This award is granted to you in recognition of your role as an employee whose responsibilities and performance are critical to the attainment of long-term goals. This award and similar awards are made on a selective basis and are, therefore, to be kept confidential.

Subject to all of the terms of the Agreement, you will become entitled to payment of this award if you are an active employee of the Company on the third anniversary of the grant date.

If you have any questions about this award, you may contact a dedicated Fidelity Stock Plan Representative at 1-800-544-9354.

[YEAR] RESTRICTED STOCK UNIT AGREEMENT

THIS RESTRICTED STOCK UNIT AGREEMENT (this “Agreement”), which contains the terms and conditions for the Restricted Stock Units (“Restricted Stock Units” or “RSUs”) referred to in the [YEAR] Restricted Stock Unit Award Letter delivered in hard copy or electronically to Participant (“[YEAR] Award Letter”), is by and between THE WILLIAMS COMPANIES, INC., a Delaware corporation (the “Company”) and the individual identified on the last page hereof (the “Participant”).

1.    Grant of RSUs. Subject to the terms and conditions of The Williams Companies, Inc. 2007 Incentive Plan, as amended and restated from time to time (the “Plan”), this Agreement and the [YEAR] Award Letter, the Company hereby grants an award (the “Award”) to the Participant of Quantity Granted RSUs effective Grant Date (the “Effective Date”). The Award gives the Participant the opportunity to earn the right to receive the number ofshares of the Common Stock of the Company equal to the number of RSUs shown in the prior sentence, subject to adjustment under the terms of this Agreement. These shares are referred to in this Agreement as the “Shares.” Until the Participant both becomes vested in the RSUs under the terms of Paragraph 4 and is paid such Shares under the terms of Paragraph 5, the Participant shall have no rights as a stockholder of the Company with respect to the Shares; provided, however, that the Participant shall have the right to earn Dividend Equivalents with respect to the RSUs awarded under this Agreement in accordance with Subparagraph 4(i) below.

2.    Incorporation of Plan and Acceptance of Documents. The Plan is hereby incorporated herein by reference, and all capitalized terms used herein which are not defined in this Agreement shall have the respective meanings set forth in the Plan. By accepting this Award, the Participant acknowledges that he or she has received a copy of, or has online access to, the Plan and hereby automatically accepts the RSUs subject to all the terms and provisions of the Plan and this Agreement. The Participant hereby further agrees that he or she has received a copy of, or has online access to, the Plan prospectus, as updated from time to time, and hereby acknowledges his or her automatic acceptance and receipt of such prospectus electronically.

3.    Committee Decisions and Interpretations. The Participant hereby agrees to accept as binding, conclusive and final all actions, decisions and/or interpretations of the Committee, its delegates, or agents, upon any questions or other matters arising under the Plan or this Agreement.

4.    Vesting; Legally Binding Rights.

(a)    Notwithstanding any other provision of this Agreement, (i) a Participant shall not be entitled to any payment of Shares under this Agreement unless and until such Participant obtains a legally binding right to such Shares and satisfies applicable vesting conditions for such payment and (ii) a Participant shall not be entitled to payment of any Dividend Equivalents unless and until such Participant obtains a legally binding right to, and satisfies applicable vesting conditions for payment of, the underlying Shares on which such Dividend Equivalents are payable.

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(b)    Except as otherwise provided in Subparagraphs 4(c) – 4(h) below, the Participant shall vest in all Shares on the third anniversary of the Effective Date (the “Maturity Date”), but only if the Participant remains an active employee of the Company or any of its Affiliates through the Maturity Date.

(c)    If a Participant dies prior to the Maturity Date while an active employee of the Company or any of its Affiliates, the Participant shall vest in all Shares at the time of such death.

(d)    If a Participant becomes Disabled (as defined below) prior to the Maturity Date while an active employee of the Company or any of its Affiliates, the Participant shall vest in all Shares at the time the Participant becomes Disabled. For purposes of this Subparagraph 4(d), the Participant shall be considered Disabled if he or she (A) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, or (B) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve (12) months, receiving income replacement benefits for a period of not less than three (3) months under an accident and health plan covering employees of the Participant’s employer. Notwithstanding the forgoing, all determinations of whether a Participant is Disabled shall be made in accordance with Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”) and the guidance thereunder.

(e)    If the Participant qualifies for Retirement (as defined in (i) below) with the Company or any of its Affiliates prior to the Maturity Date, at the time of such Participant’s Retirement, the Participant shall vest in a pro rata number of the Shares as determined in accordance with this Subparagraph 4(e). The pro rata number referred to above shall be determined by multiplying the number of Shares subject to the Award by a fraction, the numerator of which is the number of full and partial months in the period that begins the month following the month that contains the Effective Date and ends on (and includes) the date of the Participant’s Retirement, and the denominator of which is the total number of full and partial months in the period that begins the month following the month that contains the Effective Date and ends on (and includes) the Maturity Date.

Notwithstanding the preceding paragraph, if the Participant qualifies for Retirement with the Company or any of its Affiliates prior to the Maturity Date and (i) such Retirement occurs at least 6 months after the Effective Date, (ii) the Participant has attained age sixty (60) at the time of such Retirement, and (iii) the Participant has at the time of the Retirement at least 10 years of service as an active employee of the Company and its Affiliates as determined based on the Participant’s company seniority date, then the Participant will vest in all of the Shares.

(i)For purposes of this Subparagraph 4(e), a Participant “qualifies for Retirement” only if such Participant experiences a Separation from Service (as

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defined in (ii) below) after attaining age fifty-five (55) and completing at least three (3) years of service with the Company or any of its Affiliates.

(ii)As used in this Agreement, “Separation from Service” means a Participant’s termination or deemed termination from employment with the Company and its Affiliates. For purposes of determining whether a Separation from Service has occurred, the employment relationship is treated as continuing intact while the Participant is on military leave, sick leave or other bona fide leave of absence if the period of such leave does not exceed six (6) months, or if longer, so long as the Participant retains a right to reemployment with his or her employer under an applicable statute or by contract. For this purpose, a leave of absence constitutes a bona fide leave of absence only if there is a reasonable expectation that the Participant will return to perform services for his or her employer. If the period of leave exceeds six (6) months and the Participant does not retain a right to reemployment under an applicable statute or by contract, the employment relationship will be deemed to terminate on the first date immediately following such six (6) month period. Notwithstanding the foregoing, if a leave of absence is due to any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than six (6) months, and such impairment causes the Participant to be unable to perform the duties of the Participant’s position of employment or any substantially similar position of employment, a twenty-nine (29) month period of absence shall be substituted for such six (6) month period. For purposes of this Agreement, a Separation from Service occurs at the date as of which the facts and circumstances indicate either that, after such date: (A) the Participant and the Company reasonably anticipate the Participant will perform no further services for the Company and its Affiliates (whether as an employee or an independent contractor) or (B) that the level of bona fide services the Participant will perform for the Company and its Affiliates (whether as an employee or independent contractor) will permanently decrease to no more than twenty (20%) of the average level of bona fide services performed over the immediately preceding thirty-six (36) month period or, if the Participant has been providing services to the Company and its Affiliates for less than thirty-six (36) months, the full period over which the Participant has rendered services, whether as an employee or independent contractor. The determination of whether a Separation from Service has occurred shall be governed by the provisions of Treasury Regulation § 1.409A-1, as amended, taking into account the objective facts and circumstances with respect to the level of bona fide services performed by the Participant after a certain date.

(f)    If the Participant experiences a Separation from Service prior to the Maturity Date within two years following a Change in Control (as defined in (i) below), either voluntarily for Good Reason or involuntarily (other than due to Cause), the Participant shall vest in all of the Shares upon such Separation from Service.

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(i)For the purposes of this Agreement, a “Change in Control” means, unless otherwise defined in an individual employment, change in control or other severance agreement, the occurrence of any of the following events:

(a)A majority of the members of the Board is replaced during any 12-month period by directors whose appointment or election is not approved by a majority of the members constituting the Board prior to the date of the appointment or election; or

(b)any Person becomes a “Beneficial Owner” (such term for purposes of this definition being as defined in Rule 13d-3 under the 1934 Act), directly or indirectly, of securities of the Company representing 30% or more of the combined voting power of the Company’s then outstanding securities eligible to vote for the election of directors (the “Company Voting Securities”); provided, however, that for purposes of this subsection (B), the following acquisitions shall not constitute a Change in Control: (w) an acquisition directly from the Company, (x) an acquisition by the Company or a subsidiary of the Company (a “Subsidiary”), (y) an acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any Subsidiary, or (z) an acquisition pursuant to a Non-Qualifying Transaction (as defined in subsection (C) below); or

(c)the consummation of a reorganization, merger, consolidation, statutory share exchange or similar form of corporate transaction involving the Company or a Subsidiary (a “Reorganization”), or the sale or other disposition of all or substantially all of the Company’s assets (a “Sale”) or the acquisition of assets or stock of another entity (an “Acquisition”), unless immediately following such Reorganization, Sale or Acquisition: (1) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the outstanding shares of common stock of the Company (“Company Common Stock”) and outstanding Company Voting Securities immediately prior to such Reorganization, Sale or Acquisition beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the entity resulting from such Reorganization, Sale or Acquisition (including, without limitation, an entity which as a result of such transaction owns the Company or all or substantially all of the Company’s assets or stock either directly or through one or more subsidiaries, the “Surviving Entity”) in substantially the same proportions as their ownership, immediately prior to such Reorganization, Sale or Acquisition, of the outstanding Company Common Stock and the outstanding Company Voting Securities, as the case may be, and (2) no Person (other than (x) the Company or any Subsidiary of the Company, (y) the Surviving Entity or its ultimate parent,

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or (z) any employee benefit plan (or related trust) sponsored or maintained by any of the foregoing) is the Beneficial Owner, directly or indirectly, of 30% or more of the Company Voting Securities, and (3) at least a majority of the members of the board of directors or similar governing body of the Surviving Entity were members of the Incumbent Board at the time of the execution of the initial agreement, or at the time of the action of the Board, providing for such Reorganization, Sale or Acquisition (any Reorganization, Sale or Acquisition which satisfies all of the criteria specified in (1), (2) and (3) above shall be deemed to be a “Non-Qualifying Transaction”); or

(d)approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.

(ii) “Incumbent Board” means, unless otherwise defined in an individual employment, change in control or other severance agreement, individuals who, as of the Effective Date, constitute the Board and any other individual who becomes a director of the Company after that date and whose election or appointment by the Board or nomination for election by the Company’s stockholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board.

(iii)“Person” means, unless otherwise defined in an individual employment, change in control or other severance agreement, a Person as defined in Section 3(a)(9) of the Securities Exchange Act of 1934 (the “1934 Act”) and as used in this Subparagraph (f) and 14(d)(2) of the 1934 Act.

(g)    If the Participant experiences an involuntary Separation from Service prior to the Maturity Date and the Participant either receives cash severance benefits under a severance pay plan or program maintained by the Company or receives benefits under a separation agreement with the Company, the Participant shall vest in all Shares upon such Separation from Service.

(h)    If the Participant experiences an involuntary Separation from Service prior to the Maturity Date due to a sale of a business or the outsourcing of any portion of a business, the Participant shall vest in all Shares upon such Separation from Service, but only if the Company or any of its Affiliates failed to make an offer of comparable employment, as defined by a severance pay plan or program maintained by the Company, to the Participant. For purposes of this Subparagraph 4(h), a Termination of Affiliation shall constitute an involuntary Separation from Service.

(i)If the Participant becomes entitled to payment of any Shares under this Agreement, the Participant shall also be entitled to receipt of Dividend Equivalents with respect to such Shares in an amount equal to the amount of dividends, if any, that would have been payable on such Shares if such Shares had been issued and outstanding from the date of this Agreement through the payment date of the Shares. Dividend Equivalents

6

shall remain assets of the Company until paid hereunder and may, in the discretion of the Committee be paid in either cash or Shares. If Dividend Equivalents are paid in Shares, the number of Shares so payable will equal the total amount of Dividend Equivalents payable, if any, divided by the Fair Market Value of a Share on the payment date. No fractional Shares shall be issued.

5.    Payment of Shares and Dividend Equivalents.

    (a)    The payment date for all Shares in which a Participant becomes vested pursuant to Subparagraph 4(b) above, and Dividend Equivalents in which the Participant becomes vested pursuant to Subparagraph 4(i), shall be the Maturity Date.

(b)     The payment date for all Shares in which a Participant becomes vested pursuant to Subparagraphs 4(c) and 4(d) above, and Dividend Equivalents in which the Participant becomes vested pursuant to Subparagraph 4(i), shall be no more than thirty (30) days after the date the Participant dies or becomes Disabled, as applicable. If such 30-day period spans two calendar years, then payment will be made in the later calendar year.

(c)    The payment date for all Shares in which the Participant becomes vested pursuant to Subparagraphs 4(e), 4(f), 4(g) and 4(h) above, and Dividend Equivalents in which the Participant becomes vested pursuant to Subparagraph 4(i), shall be no more than sixty (60) days following such Participant’s Separation from Service, unless otherwise provided in Subparagraph 5(e) below. If such 60-day period spans two calendar years, then payment will be made in the later calendar year.

(d)    Upon conversion of RSUs into Shares under this Agreement, such RSUs shall be cancelled. Shares that become payable under this Agreement and will be paid by the Company by the delivery to the Participant, or the Participant’s beneficiary or legal representative, of one or more certificates (or other indicia of ownership) representing shares of Williams Common Stock equal in number to the number of Shares otherwise payable under this Agreement less the number of Shares having a Fair Market Value, as of the date the withholding tax obligation arises, equal to the minimum statutory withholding requirements. Notwithstanding the foregoing, to the extent permitted by Section 409A of the Code and the guidance issued by the Internal Revenue Service thereunder, if federal employment taxes become due upon the Participant’s becoming entitled to payment of Shares, the number of Shares necessary to cover minimum statutory withholding requirements may, in the discretion of the Company, be used to satisfy such requirements upon such entitlement.

(e)    If the Participant was a “key employee” within the meaning of Section 409A(a)(B)(i) of the Code immediately prior to his or her Separation from Service, and such Participant vested in such Shares under Subparagraphs 4(e), (4)(f), 4(g) or 4(h) above, payment shall not be made sooner than six (6) months following the date such Participant experienced a Separation from Service. “Key employee” means an employee designated on an annual basis by the Company as of December 31 (the “Key Employee

7

Designation Date”) as an employee meeting the requirements of Section 416(i) of Code utilizing the definition of compensation under Treasury Regulation § 1.415(c)-2(d)(2). A Participant designated as a “key employee” shall be a “key employee” for the entire twelve (12) month period beginning on April 1 following the Key Employee Designation Date.

6.    Other Provisions.

(a)    The Participant understands and agrees that payments under this Agreement shall not be used for, or in the determination of, any other payment or benefit under any continuing agreement, plan, policy, practice or arrangement providing for the making of any payment or the provision of any benefits to or for the Participant or the Participant’s beneficiaries or representatives, including, without limitation, any employment agreement, any change of control severance protection plan or any employee benefit plan as defined in Section 3(3) of ERISA, including, but not limited to qualified and non-qualified retirement plans.

(b)    The Participant agrees and understands that, subject to the limit expressed in clause (iii) of the following sentence, upon payment of Shares and Dividend Equivalents under this Agreement, stock certificates (or other indicia of ownership) issued may be held as collateral for monies he/she owes to Company or any of its Affiliates, including but not limited to personal loan(s), Company credit card debt, relocation repayment obligations or benefits from any plan that provides for pre-paid educational assistance. In addition, the Company may accelerate the time or schedule of a payment of vested Shares and Dividend Equivalents, and/or deduct from any payment of Shares and Dividend Equivalents to the Participant under this Agreement, or to his or her beneficiaries in the case of the Participant’s death, that number of Shares and Dividend Equivalents having a Fair Market Value at the date of such deduction to the amount of such debt as satisfaction of any such debt, provided that (i) such debt is incurred in the ordinary course of the employment relationship between the Company or any of its Affiliates and the Participant, (ii) the aggregate amount of any such debt-related collateral held or deduction made in any taxable year of the Company with respect to the Participant does not exceed $5,000, and (iii) the deduction of Shares and Dividend Equivalents is made at the same time and in the same amount as the debt otherwise would have been due and collected from the Participant.

(c)    Except as provided in Subparagraphs 4(c) through 4(h) above, in the event that the Participant experiences a Separation from Service prior to the Participant’s becoming vested in the Shares under this Agreement, RSUs subject to this Agreement and any right to Shares and Dividend Equivalents issuable hereunder shall be forfeited.

(d)    The Participant acknowledges that this Award and similar awards are made on a selective basis and are, therefore, to be kept confidential.

(e)    RSUs, Shares and Dividend Equivalents and the Participant’s interest in RSUs and Shares and Dividend Equivalents may not be sold, assigned, transferred, pledged or

8

otherwise disposed of or encumbered at any time prior to both (i) the Participant’s becoming vested in such Shares and (ii) payment of such Shares and Dividend Equivalents under this Agreement.

(f)    If the Participant at any time forfeits any or all of the RSUs pursuant to this Agreement, the Participant agrees that all of the Participant’s rights to and interest in such RSUs and in Shares and Dividend Equivalents payable thereon, if any, issuable hereunder shall terminate upon forfeiture without payment of consideration.

(g)    The Committee shall determine whether an event has occurred resulting in the forfeiture of the Shares and Dividend Equivalents payable thereon in accordance with this Agreement, and all determinations of the Committee shall be final and conclusive.

(h)    With respect to the right to receive payment of the Shares and Dividend Equivalents under this Agreement, nothing contained herein shall give the Participant any rights that are greater than those of a general creditor of the Company.

(i)    The obligations of the Company under this Agreement are unfunded and unsecured. Each Participant shall have the status of a general creditor of the Company with respect to amounts due, if any, under this Agreement.

(j)    The parties to this Agreement intend that this Agreement meet the applicable requirements of Section 409A of the Code and recognize that it may be necessary to modify this Agreement and/or the Plan to reflect guidance under Section 409A of the Code issued by the Internal Revenue Service. Participant agrees that the Committee shall have sole discretion in determining (i) whether any such modification is desirable or appropriate and (ii) the terms of any such modification.

(k)    The Participant hereby automatically becomes a party to this Agreement whether or not he or she accepts the Award electronically or in writing in accordance with procedures of the Committee, its delegates or agents.

(l)    Nothing in this Agreement or the Plan shall interfere with or limit in any way the right of the Company or an Affiliate to terminate the Participant’s employment or service at any time, nor confer upon the Participant the right to continue in the employ of the Company and/or Affiliate.

(m)    The Participant hereby acknowledges that nothing in this Agreement shall be construed as requiring the Committee to allow a Domestic Relations Order with respect to this Award.

7.    Notices. All notices to the Company required hereunder shall be in writing and delivered by hand or by mail, addressed to The Williams Companies, Inc., One Williams Center, Tulsa, Oklahoma 74172, Attention: Stock Administration Department. Notices shall become effective upon their receipt by the Company if delivered in the foregoing manner. To direct the sale of

9

any Shares issued under this Agreement, contact Fidelity at http://netbenefits.fidelity.comor by telephone at 800-544-9354.

8.    Tax Consultation. You understand you will incur tax consequences as a result of acquisition or disposition of the Shares and Dividend Equivalents. You agree to consult with any tax consultants you think advisable in connection with the acquisition of the Shares and Dividend Equivalents and acknowledge that you are not relying, and will not rely, on the Company for any tax advice.

    THE WILLIAMS COMPANIES, INC.

Participant: Participant Name

SSN: Participant ID

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EX-10.29

Exhibit 10.29

                                        Date=Grant Date                                

TO:        <@Name@>

FROM:    

SUBJECT:    [YEAR]Restricted Stock Unit Award

You have been granted a restricted stock unit award. This award, which is subject to adjustment under the [YEAR] Restricted Stock Unit Agreement (the “Agreement”), is granted to you in recognition of your role as a non-management director for The Williams Companies, Inc. It is granted and subject to the terms and conditions of The Williams Companies, Inc. 2007 Incentive Plan, as amended and restated from time to time, and the Agreement.

Subject to all of the terms of the Agreement, you will generally become entitled to payment of this award when you leave your role as a non-management director for the Company.

If you have any questions about this award, you may contact a dedicated Fidelity Stock Plan Representative at 1-800-823-0217.

[YEAR] RESTRICTED STOCK UNIT AGREEMENT

THIS RESTRICTED STOCK UNIT AGREEMENT (this “Agreement”), which contains the terms and conditions for the Restricted Stock Units (“Restricted Stock Units” or “RSUs”) referred to in the [YEAR] Restricted Stock Unit Award Letter delivered in hard copy or electronically to Participant (“[YEAR] Award Letter”), is by and between THE WILLIAMS COMPANIES, INC., a Delaware corporation (the “Company”) and the individual identified on the last page hereof (the “Participant”).

1.    Grant of RSUs. Subject to the terms and conditions of The Williams Companies, Inc. 2007 Incentive Plan, as amended and restated from time to time (the “Plan”), this Agreement and the [YEAR] Award Letter, the Company hereby grants an award (the “Award”) to the Participant of <@Num+C @> RSUs effective <@GrDt+C@> (the “Effective Date”). The Award gives the Participant the right to receive the number ofshares of the Common Stock of the Company equal to the number of RSUs shown in the prior sentence, subject to adjustment under the terms of this Agreement. These shares are referred to in this Agreement as the “Shares.” Until the Participant receives payment of the Shares under the terms of Paragraph 4, the Participant shall have no rights as a stockholder of the Company with respect to the Shares, except for the right to earn Dividend Equivalents as set forth herein.

2.    Incorporation of Plan and Acceptance of Documents. The Plan is hereby incorporated herein by reference, and all capitalized terms used herein which are not defined in this Agreement shall have the respective meanings set forth in the Plan. The Participant acknowledges that he or she has received a copy of, or has online access to, the Plan and hereby automatically accepts the RSUs subject to all the terms and provisions of the Plan and this Agreement. The Participant hereby further agrees that he or she has received a copy of, or has online access to, the prospectus and hereby acknowledges his or her automatic acceptance and receipt of such prospectus electronically.

3.    Board Decisions and Interpretations. The Participant hereby agrees to accept as binding, conclusive and final all actions, decisions and/or interpretations of the Board, its delegates, or agents, upon any questions or other matters arising under the Plan or this Agreement.

4.    Payment of Shares; Dividend Equivalents.

(a)    The Participant shall receive payment of all Shares if the Participant dies while serving as a Non-Management Director of the Company or his or her service as a Non-Management Director of the Company terminates for any other reason and such termination constitutes a “separation from service” as defined under Treasury Regulation § 1.409A-1, as amended, the Participant shall receive payment of all Shares at the time of such death or separation from service. In this regard, if at the time a Non-Management Director’s service as a Non-Management Director terminates, such Non-Management Director is also providing services to the Company or an Affiliate (as defined below) as an independent contractor, no separation from service by such Non-Management Director shall occur, and no Shares shall be payable to such Non-Management Director until the

2

date on which such Non-Management Director has a Separation from Service as an Independent Contractor (as defined below) from the Company and its Affiliates.

(b)     All Shares that are paid pursuant to the Participant’s death or separation from service as provided in Subparagraph 4(a) above shall be paid to the Participant upon occurrence of the event giving rise to the right to payment or, in the case of Participant’s death, to the beneficiary of the Participant under the Plan or, if no beneficiary has been designated, to the Participant’s estate, providedthat, except as otherwise required under Federal securities laws or other applicable law, all Shares that are paid pursuant to Subparagraph 4(a) above in the event of death shall be paid not more than 90 days following such death, and all Shares that are paid pursuant to Subparagraph 4(a) above in the event of a separation from service shall be paid not more than 30 days following such separation from service. If such 90-day or 30-day period as applicable spans two calendar years, then payment will be made in the later calendar year.

(c)    Shares that become payable under this Agreement will be paid by the Company by the delivery to the Participant, or, in the case of the Participant’s death, to the Participant’s beneficiary or legal representative, of one or more certificates (or other indicia of ownership) representing shares of Williams Common Stock equal in number to the number of Shares otherwise payable under this Agreement. Notwithstanding the foregoing, to the extent permitted by Section 409A of the Code and the guidance issued by the Internal Revenue Service thereunder, if employment taxes become due or other withholding obligations arise upon the Participant’s becoming entitled to payment of Shares, the number of Shares necessary to cover minimum statutory withholding requirements may be used to satisfy such requirements upon such entitlement.

(d)    Upon conversion of RSUs into Shares under this Agreement, such RSUs shall be cancelled.

(e)    From and after the Effective Date, the Participant shall be entitled to accrue Dividend Equivalents with respect to each Share subject to the Award. On each date on which the Company pays a dividends to stockholders generally, the number of RSUs subject to this Agreement shall be increased by a number equal to the number of whole Shares with a value equal to the value of the dividends that would have been paid on the Shares deliverable pursuant to the RSUs (if such Shares were outstanding), divided by the Fair Market Value of the Shares on such dividend payment date. Prior to payment, the Dividend Equivalents shall be subject to the same restrictions and limitations set forth herein with respect to the RSUs to which the Dividend Equivalents relate. The Dividend Equivalents accrued hereunder shall be paid in Shares (without interest) to the Participant (or beneficiary or estate, as applicable) as and when the Shares to which such Dividend Equivalents relate are paid pursuant to this Section 4.

5.    Definitions. As used in this Agreement, the following terms shall have the definitions set forth below.

3

(a)    “Affiliate” means all persons with whom the Company would be considered a single employer under Section 414(b) of the Code, and all persons with whom such person would be considered a single employer under Section 414(c) of the Code.    

(b)    “Separation from Service as an Independent Contractor” will occur upon the expiration of the contract (or in the case of more than one contract, all contracts) under which services are performed by a Non-Management Director for the Company or an Affiliate, but only if the expiration constitutes a good-faith and complete termination of the contractual relationship. An expiration of a contract shall not constitute a good faith and complete termination of the contractual relationship if the Company or an Affiliate anticipates either a renewal of a contractual relationship or the Non-Management Director’s becoming an employee. The determination of whether a Separation from Service as an Independent Contractor has occurred shall be governed by the provisions of Treasury Regulation § 1.409A-1, as amended.

6.    Other Provisions.

(a)    The Participant understands and agrees that payments under this Agreement shall not be used for, or in the determination of, any other payment or benefit under any continuing agreement, plan, policy, practice or arrangement providing for the making of any payment or the provision of any benefits to or for the Participant or the Participant’s beneficiaries or representatives, including, without limitation, any employment agreement, any change of control severance protection plan or any employee benefit plan as defined in Section 3(3) of ERISA, including, but not limited to qualified and non-qualified retirement plans.

(b)    The Participant agrees and understands that, upon payment of Shares under this Agreement, stock certificates (or other indicia of ownership) issued may be held as collateral for monies he/she owes to the Company or any of its Affiliates, including but not limited to personal loan(s) or the Company credit card debt.

(c)    RSUs, Shares and the Participant’s interest in RSUs and Shares may not be sold, assigned, transferred, pledged or otherwise disposed of or encumbered at any time prior to the Participant’s becoming entitled to payment of Shares under this Agreement.

(d)    With respect to the right to receive payment of the Shares under this Agreement, nothing contained herein shall give the Participant any rights that are greater than those of a general creditor of the Company.

(e)    The obligations of the Company under this Agreement are unfunded and unsecured. Each Participant shall have the status of a general creditor of the Company with respect to amounts due, if any, under this Agreement.

(f)    The parties to this Agreement intend that this Agreement meet the applicable requirements of Section 409A of the Code and recognize that it may be necessary to modify this Agreement and/or the Plan to reflect guidance under Section 409A of the

4

Code issued by the Internal Revenue Service. Participant agrees that the Board shall have sole discretion in determining (i) whether any such modification is desirable or appropriate and (ii) the terms of any such modification.

(g)    The Participant hereby automatically becomes a party to this Agreement whether or not he or she accepts the Award electronically or in writing in accordance with procedures of the Board, its delegates or agents.

(h)    Nothing in this Agreement or the Plan shall confer upon the Participant the right to continue to serve as a director of the Company.

(i)    The Participant hereby acknowledges that nothing in this Agreement shall be construed as requiring the Board or Committee to allow a Domestic Relations Order with respect to this Award.

7.    Notices. All notices to the Company required hereunder shall be in writing and delivered by hand or by mail, addressed to The Williams Companies, Inc., One Williams Center, Tulsa, Oklahoma 74172, Attention: Stock Administration Department. Notices shall become effective upon their receipt by the Company if delivered in the foregoing manner. To direct the sale of any Shares issued under this Agreement, the Participant must contact Fidelity at http://netbenefits.fidelity.comor by telephone at 800-823-0217.

8.    Tax Consultation. You understand you will incur tax consequences as a result of acquisition or disposition of the Shares. You agree to consult with any tax consultants you think advisable in connection with the acquisition of the Shares and acknowledge that you are not relying, and will not rely, on the Company for any tax advice.

    THE WILLIAMS COMPANIES, INC.

Participant: <@Name@>

SSN: <@SSN@>

5

EX-21

	Exhibit 21
ENTITY	JURISDICTION
Alliance Canada Marketing L.P.	Alberta
Alliance Canada Marketing LTD	Alberta
Appalachia Midstream Services, L.L.C.	Oklahoma
Aux Sable Liquid Products Inc.	Delaware
Aux Sable Liquid Products LP	Delaware
Aux Sable Midstream LLC	Delaware
Bargath LLC	Delaware
Baton Rouge Fractionators LLC	Delaware
Baton Rouge Pipeline LLC	Delaware
Black Marlin Pipeline LLC	Texas
Bluebonnet Market Express LLC	Delaware
Blue Racer Midstream, LLC	Delaware
Bluestem Gas Services, L.L.C.	Oklahoma
Bluestem Pipeline LLC	Delaware
Brazos Permian II, LLC	Delaware
Caiman Energy II, LLC	Delaware
Caiman Ohio Midstream, LLC	Texas
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
Constitution Pipeline Company LLC	Delaware
Discovery Gas Transmission LLC	Delaware
Discovery Producer Services LLC	Delaware
DMP New York, Inc.	New York
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
Inland Ports, Inc.	Tennessee
Kiowa Lateral LLC	Delaware
Laurel Mountain Midstream Operating LLC	Delaware
Laurel Mountain Midstream, 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
Nopal Gathering LLC	Delaware
Northwest Pipeline LLC	Delaware

	Exhibit 21
ENTITY	JURISDICTION
Ohio Valley Midstream LLC	Delaware
Oklahoma Midstream Gas Services, L.L.C.	Oklahoma
Overland Pass Pipeline Company LLC	Delaware
Pacific Connector Gas Pipeline, LP	Delaware
Parachute Pipeline LLC	Delaware
Pecan Hill Water Solutions	Delaware
Pennant Midstream 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
South Mansfield E&P, LLC	Delaware
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
TWC Holdings C.V.	Netherlands
UEOM NGL Pipelines LLC	Delaware
Utica East Ohio Midstream, L.L.C.	Delaware
Utica Gas Services, L.L.C.	Oklahoma
Wamsutter LLC	Delaware
Wamsutter E&P, LLC	Delaware
WFS - Liquids LLC	Delaware
WFS Gathering Company, L.L.C.	Delaware
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 Compression, L.L.C.	Oklahoma

	Exhibit 21
ENTITY	JURISDICTION
Williams CV Holdings LLC	Delaware
Williams Energy Resources LLC	Delaware
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
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 Midstream Gas Services, L.L.C.	Oklahoma
Williams MLP Operating, L.L.C.	Delaware
Williams Mobile Bay Producer Services, L.L.C.	Delaware
Williams Ohio River Valley LLC	Delaware
Williams Ohio River Valley Corporation	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 Pacific Connector Gas Operator, LLC	Delaware
Williams Partners Operating LLC	Delaware
Williams PERK, 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

	Exhibit 21
ENTITY	JURISDICTION
Williams Strategic Sourcing Company	Delaware
Williams Upstream Holdings, LLC	Delaware
Williams WPC - I, LLC	Delaware
WilPro Energy Services (El Furrial) Limited	Cayman Islands
WilPro Energy Services (Pigap II) Limited	Cayman Islands

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 No. 333-29185) 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 24, 2021, 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, 2020.

/s/ Ernst & Young LLP

Tulsa, Oklahoma
February 24, 2021

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 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 24, 2021 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 24, 2021

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 24, 2021

/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. Chandler, 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 24, 2021

/s/ John D. Chandler

John D. Chandler

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, 2020, 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 24, 2021

/s/ John D. Chandler

John D. Chandler

Senior Vice President and Chief Financial Officer

February 24, 2021

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, 2020	Feb. 19, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
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	918
Local Phone Number	573-2000
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
Entity Shell Company	false
Entity Public Float			$ 23,078,419,375
Entity Common Stock, Shares Outstanding		1,213,790,391
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 27, 2021, are incorporated into Part III, as specifically set forth in Part III.
Entity Central Index Key	0000107263
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31

XML

Consolidated Statement of Operations - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues:
Revenues	$ 7,719	$ 8,201	$ 8,686
Costs and expenses:
Operating and maintenance expenses	1,326	1,468	1,507
Depreciation and amortization expenses	1,721	1,714	1,725
Selling, general, and administrative expenses	466	558	569
Impairment of certain assets (Note 18)	182	464	1,915
Impairment of goodwill (Note 18)	187	0	0
Gain on sale of certain assets and businesses (Note 3)	0	2	(692)
Other (income) expense – net	22	8	50
Total costs and expenses	5,517	6,280	7,918
Operating income (loss)	2,202	1,921	768
Equity earnings (losses) (Note 7)	328	375	396
Impairment of equity-method investments (Note 18)	(1,046)	(186)	(32)
Other investing income (loss) – net (Note 7)	8	107	219
Interest incurred	(1,192)	(1,218)	(1,160)
Interest capitalized	20	32	48
Other income (expense) – net	(43)	33	92
Income (loss) from continuing operations before income taxes	277	1,064	331
Less: Provision (benefit) for income taxes	79	335	138
Income (Loss) from Continuing Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	198	729	193
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	0	(15)	0
Net income (loss)	198	714	193
Less: Net income (loss) attributable to noncontrolling interests	(13)	(136)	348
Amounts attributable to The Williams Companies, Inc. available to common stockholders:
Net income (loss) attributable to The Williams Companies, Inc.	211	850	(155)
Less: Preferred stock dividends (Note 16)	3	3	1
Net income (loss) available to common stockholders	208	847	(156)
Income (loss) from continuing operations available to common stockholders	$ 208	$ 862	$ (156)
Basic earnings (loss) per common share:
Net income (loss)	$ 0.17	$ 0.70	$ (0.16)
Basic	0.17	0.71	(0.16)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share	$ 0	$ (0.01)	$ 0
Weighted-average shares (thousands)	1,213,631	1,212,037	973,626
Diluted earnings (loss) per common share:
Net income (loss)	$ 0.17	$ 0.70	$ (0.16)
Diluted	0.17	0.71	(0.16)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share	$ 0	$ (0.01)	$ 0
Weighted-average shares (thousands)	1,215,165	1,214,011	973,626	[1]
Service [Member]
Revenues:
Revenues	$ 5,924	$ 5,933	$ 5,502
NonRegulated Service Commodity Consideration [Member]
Revenues:
Revenues	129	203	400
Product [Member]
Revenues:
Revenues	1,666	2,065	2,784
Oil and Gas, Purchased [Member]
Costs and expenses:
Cost of Goods and Service, Excluding Depreciation, Depletion, and Amortization	1,545	1,961	2,707
Natural Gas Purchased For Shrink [Member]
Costs and expenses:
Cost of Goods and Service, Excluding Depreciation, Depletion, and Amortization	$ 68	$ 105	$ 137

[1] For the year ended December 31, 2018, 2.0 million weighted-average nonvested restricted stock units and 0.5 million weighted-average stock options have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to The Williams Companies, Inc.

XML

Consolidated Statement of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Comprehensive income (loss):
Net income (loss)	$ 198	$ 714	$ 193
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $—, $—, and $1 in 2020, 2019, and 2018, respectively	(2)	0	(7)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $—, $—, and ($1) in 2020, 2019, and 2018, respectively	1	0	8
Pension and other postretirement benefits:
Net actuarial gain (loss) arising during the year, net of taxes of ($27), ($20), and $3 in 2020, 2019, and 2018, respectively	81	59	(6)
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($7), ($4), and ($11) in 2020, 2019, and 2018, respectively	23	12	35
Other comprehensive income (loss)	103	71	30
Comprehensive income (loss)	301	785	223
Less: Comprehensive income (loss) attributable to noncontrolling interests	(13)	(136)	346
Comprehensive Income (loss) attributable to The Williams Companies, Inc.	$ 314	$ 921	$ (123)

XML

Consolidated Statement of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flow hedging activities:
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, Tax	$ 0	$ 0	$ 1
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	0	0	(1)
Pension and other postretirement benefits:
Other Comprehensive Income (Loss), Defined Benefit Plan, Net Actuarial Gain (Loss) Arising During Period, Tax	(27)	(20)	3
Other Comprehensive Income Loss, Reclassification Pension And Other Postretirement Benefit Plans Net Gain Loss Included In Net Periodic Benefit Cost (Credit), Tax	$ (7)	$ (4)	$ (11)

XML

Consolidated Balance Sheet - USD ($) shares in Millions, $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 142	$ 289
Trade accounts and other receivables	1,000	1,002
Allowance for doubtful accounts	(1)	(6)
Trade accounts and other receivables - net	999	996
Inventories	136	125
Other current assets and deferred charges	152	170
Total current assets	1,429	1,580
Investments	5,159	6,235
Property, plant, and equipment – net	28,929	29,200
Intangible assets – net of accumulated amortization	7,444	7,959
Regulatory assets, deferred charges, and other	1,204	1,066
Total assets	44,165	46,040
Current liabilities:
Accounts payable	482	552
Accrued liabilities	944	1,276
Long-term debt due within one year	893	2,140
Total current liabilities	2,319	3,968
Long-term debt	21,451	20,148
Deferred income tax liabilities	1,923	1,782
Regulatory liabilities, deferred income, and other	3,889	3,778
Contingent liabilities and commitments (Note 19)
Stockholders’ equity:
Preferred stock	35	35
Common stock ($1 par value; 1,470 million shares authorized at December 31, 2020 and December 31, 2019; 1,248 million shares issued at December 31, 2020 and 1,247 million shares issued at December 31, 2019)	1,248	1,247
Capital in excess of par value	24,371	24,323
Retained deficit	(12,748)	(11,002)
Accumulated other comprehensive income (loss)	(96)	(199)
Treasury stock, at cost (35 million shares of common stock)	(1,041)	(1,041)
Total stockholders’ equity	11,769	13,363
Noncontrolling interests in consolidated subsidiaries	2,814	3,001
Total equity	14,583	16,364
Total liabilities and equity	$ 44,165	$ 46,040
Common Stock, Par or Stated Value Per Share	$ 1	$ 1
Common Stock, Shares Authorized	1,470	1,470
Common Stock, Shares, Issued	1,248	1,247
Treasury Stock, Shares	35	35

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Consolidated Balance Sheet (Parenthetical) - $ / shares shares in Millions	Dec. 31, 2020	Dec. 31, 2019
Stockholders’ equity:
Common stock, shares authorized	1,470	1,470
Common stock, par value per share	$ 1	$ 1
Common Stock, shares issued	1,248	1,247
Treasury stock, shares of common stock	35	35

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Consolidated Statement of Changes in Equity - USD ($) $ in Millions	Total	Adoption of new accounting standards	Preferred Stock	Preferred Stock Adoption of new accounting standards	Common Stock	Common Stock Adoption of new accounting standards	Capital in Excess of Par Value	Capital in Excess of Par Value Adoption of new accounting standards	Retained Deficit	Retained Deficit Adoption of new accounting standards	Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Adoption of new accounting standards	Treasury Stock	Treasury Stock Adoption of new accounting standards	Total Stockholders' Equity	Total Stockholders' Equity Adoption of new accounting standards	Noncontrolling Interests	Noncontrolling Interests Adoption of new accounting standards
Beginning balance at Dec. 31, 2017	$ 16,175		$ 0		$ 861		$ 18,508		$ (8,434)		$ (238)		$ (1,041)		$ 9,656		$ 6,519
Net income (loss)	193		0		0		0		(155)		0		0		(155)		348
Other comprehensive income (loss)	30		0		0		0		0		32		0		32		(2)
WPZ Merger (Note 1)	1,862		0		382		6,112		0		(3)		0		6,491		(4,629)
Issuance of preferred stock (Note 16)	35		35		0		0		0		0		0		35		0
Cash dividends – common stock	(1,386)		0		0		0		(1,386)		0		0		(1,386)		0
Dividends and distributions to noncontrolling interests	(637)		0		0		0		0		0		0		0		(637)
Stock-based compensation and related common stock issuances, net of tax	61		0		1		60		0		0		0		61		0
Sales of limited partner units of Williams Partners L.P.	46		0		0		0		0		0		0		0		46
Changes in ownership of consolidated subsidiaries, net	(4)		0		0		14		0		0		0		14		(18)
Contributions from noncontrolling interests	15		0		0		0		0		0		0		0		15
Deconsolidation of subsidiary (Note 7)	(267)		0		0		0		0		0		0		0		(267)
Other	(5)	$ (121)	0	$ 0	1	$ 0	(1)	$ 0	(4)	$ (23)	0	$ (61)	0	$ 0	(4)	$ (84)	(1)	$ (37)
Net increase (decrease) in equity	(178)		35		384		6,185		(1,568)		(32)		0		5,004		(5,182)
Ending balance at Dec. 31, 2018	15,997		35		1,245		24,693		(10,002)		(270)		(1,041)		14,660		1,337
Net income (loss)	714		0		0		0		850		0		0		850		(136)
Other comprehensive income (loss)	71		0		0		0		0		71		0		71		0
Cash dividends – common stock	(1,842)		0		0		0		(1,842)		0		0		(1,842)		0
Dividends and distributions to noncontrolling interests	(124)		0		0		0		0		0		0		0		(124)
Stock-based compensation and related common stock issuances, net of tax	58		0		2		56		0		0		0		58		0
Sales of limited partner units of Williams Partners L.P.	1,334		0		0		0		0		0		0		0		1,334
Changes in ownership of consolidated subsidiaries, net	141		0		0		(426)		0		0		0		(426)		567
Contributions from noncontrolling interests	36		0		0		0		0		0		0		0		36
Deconsolidation of subsidiary (Note 7)	(13)		0		0		0		0		0		0		0		(13)
Other	(8)		0		0		0		(8)		0		0		(8)		0
Net increase (decrease) in equity	367		0		2		(370)		(1,000)		71		0		(1,297)		1,664
Ending 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
Cash dividends – common stock	(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

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Consolidated Statement of Changes in Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Stockholders' Equity [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 1.60	$ 1.52	$ 1.36

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Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
OPERATING ACTIVITIES:
Net income (loss)	$ 198	$ 714	$ 193
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	1,721	1,714	1,725
Provision (benefit) for deferred income taxes	108	376	220
Equity (earnings) losses	(328)	(375)	(396)
Distributions from unconsolidated affiliates	653	657	693
Gain on disposition of equity-method investments (Note 7)	0	(122)	0
(Gain) on sale of certain assets and businesses (Note 3)	0	2	(692)
(Gain) loss on deconsolidation of businesses (Note 7)	0	29	(203)
Impairment of goodwill (Note 18)	187	0	0
Impairment of equity-method investments (Note 18)	1,046	186	32
Impairment of certain assets (Note 18)	182	464	1,915
Amortization of stock-based awards	52	57	55
Cash provided (used) by changes in current assets and liabilities:
Accounts receivable	(2)	34	(36)
Inventories	(11)	5	(16)
Other current assets and deferred charges	11	21	17
Accounts payable	(7)	(46)	(93)
Accrued liabilities	(309)	153	23
Other, including changes in noncurrent assets and liabilities	(5)	(176)	(144)
Net cash provided (used) by operating activities	3,496	3,693	3,293
FINANCING ACTIVITIES:
Proceeds from long-term debt	3,899	767	3,926
Payments of long-term debt	(3,841)	(909)	(3,204)
Proceeds from issuance of common stock	9	10	15
Common dividends paid	(1,941)	(1,842)	(1,386)
Dividends and distributions paid to noncontrolling interests	(185)	(124)	(591)
Proceeds from Noncontrolling Interests	7	36	15
Payments for debt issuance costs	(20)	0	(26)
Other – net	(13)	(17)	(48)
Net cash provided (used) by financing activities	(2,085)	(745)	(1,299)
INVESTING ACTIVITIES:
Capital expenditures (1)	(1,239)	(2,109)	(3,256)
Dispositions – net	(36)	(40)	(7)
Contributions in aid of construction	37	52	411
Proceeds from sale of businesses, net of cash divested (Note 3)	0	(2)	1,296
Purchases of businesses, net of cash acquired (Note 3)	0	(728)	0
Proceeds from dispositions of equity-method investments (Note 7)	0	485	0
Purchases of and contributions to equity-method investments (Note 7)	(325)	(453)	(1,132)
Other – net	5	(32)	(37)
Net cash provided (used) by investing activities	(1,558)	(2,827)	(2,725)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect, Total	(147)	121	(731)
Cash and cash equivalents at beginning of year	289	168	899
Cash and cash equivalents at end of year	142	289	168
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
(1) Increases to property, plant, and equipment	(1,160)	(2,023)	(3,021)
Changes in related accounts payable and accrued liabilities	(79)	(86)	(235)
Capital expenditures	(1,239)	(2,109)	(3,256)
Northeast JV [Member]
FINANCING ACTIVITIES:
Proceeds from Noncontrolling Interests	$ 0	$ 1,334	$ 0

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

12 Months Ended

Dec. 31, 2020

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.

WPZ Merger

On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), our previously consolidated master limited partnership, pursuant to which we acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of our common stock (WPZ Merger). Williams continued as the surviving entity. The WPZ Merger was accounted for as a noncash equity transaction resulting in increases to Common stock of $382 million, Capital in excess of par value of $6.112 billion, and Regulatory assets, deferred charges, and other of $33 million and decreases to Accumulated other comprehensive income (loss) (AOCI) of $3 million, Noncontrolling interests in consolidated subsidiaries of $4.629 billion, and Deferred income tax liabilities of $1.829 billion in the Consolidated Balance Sheet. Prior to the completion of the WPZ Merger and pursuant to its distribution reinvestment program, WPZ had issued common units to the public in 2018 associated with reinvested distributions of $46 million.

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. Our operations are presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities 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), 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), which is a proprietary floating production system, 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).

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 99 percent interest in Caiman Energy II, LLC (Caiman II) (a former equity-method investment which is a consolidated entity following our November 2020 acquisition of an additional ownership interest and was subsequently renamed Blue Racer Midstream Holdings, LLC) which owns a 50 percent equity-method investment in Blue Racer Midstream LLC (Blue Racer) (see Note 7 – Investing Activities), 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 northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, and Permian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business, 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 interest in Brazos Permian II, LLC (Brazos Permian II) (a nonconsolidated VIE).

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 other identifiable 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 non-core assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities, including effects of financial distress caused by financial and commodity market declines, 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.

Customer bankruptcy

In June 2020, our customer, Chesapeake Energy Corporation (Chesapeake), announced that it had voluntarily filed for relief under Chapter 11 of the U.S. Bankruptcy Code. We provide midstream services, including wellhead gathering, for the natural gas that Chesapeake and its joint interest owners produce, primarily in the Eagle Ford Shale, Haynesville Shale, and Marcellus Shale regions (through Appalachia Midstream Investments).

In November 2020, we reached a global resolution with Chesapeake as part of Chesapeake’s restructuring process. The resolution was approved by the bankruptcy court in December 2020 and per the terms, Chesapeake paid all outstanding pre-petition amounts due to us. Additional terms include reduced gathering fees in the Haynesville Shale region, continuation of the gathering agreements in the Eagle Ford Shale and Marcellus Shale regions, a long-term gas supply commitment for Transco’s Regional Energy Access pipeline currently under development, and transferring certain natural gas properties in Louisiana to us. As a result of this resolution, we recorded increases to our other nonregulated property, plant, and equipment of $98 million, contract liabilities of $67 million (see Note 5 – Revenue Recognition), and asset retirement obligations (AROs) of $31 million (see Note 11 – Property, Plant, and Equipment).

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;

•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 the 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.

Equity-method investment basis differences

Differences between the cost 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 the Consolidated Statement of Operations includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.

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, goodwill, and other identifiable intangible assets;

•Litigation-related contingencies;

•Environmental remediation obligations;

•Depreciation and/or amortization of long-lived assets;

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

•AROs;

•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, levelized incremental 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 for the years ended December 31, 2020 and 2019 are as follows:

	December 31,
	2020		2019
	(Millions)
Current assets reported within Other current assets and deferred charges	$	64	$	72
Noncurrent assets reported within Regulatory assets, deferred charges, and other	442		466
Total regulated assets	$	506	$	538
Current liabilities reported within Accrued liabilities	$	59	$	60
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other	1,314		1,277
Total regulated liabilities	$	1,373	$	1,337

Cash and cash equivalents

Cash and cash equivalents in the 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 (as discussed below in Accounting standards issued and adopted), the financial condition of our customers, and age of past due accounts. 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.

Inventories

Inventories in the Consolidated Balance Sheet primarily consist of NGLs, natural gas in underground storage, and materials and supplies and are stated at the lower of cost or net realizable value. The cost of inventories is primarily determined using the average-cost method.

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.

Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Operations.

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. 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 the Consolidated Statement of Operations, except for regulated entities, for which the liability is offset by 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.

Goodwill

Goodwill included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, as of December 31, 2019, represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, an impairment charge is recorded for the difference (not to exceed the carrying value of goodwill). Judgments and assumptions are inherent in our management’s estimates of fair value.

Other identifiable intangible assets

Our other identifiable intangible assets included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation contractual customer relationships. Our other identifiable intangible assets are 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, other identifiable intangible assets, and investments

We evaluate our property, plant, and equipment and other identifiable 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 in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the 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 the consolidated financial statements as an impairment charge.

Judgments 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.

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.

Cash flows from revolving credit facilities and commercial paper program

Proceeds and payments related to borrowings under our credit facilities are reflected in the financing activities in the 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 the 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 14 – Debt and Banking Arrangements.)

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 the Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in the Consolidated Balance Sheet using the average-cost method.

Derivative instruments and hedging activities

We may 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 report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets and deferred charges; Regulatory assets, deferred charges, and other; Accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.

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 on the 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 Product sales or Product costs in the Consolidated Statement of Operations.

For commodity derivatives designated as a cash flow hedge, the change in fair value of the derivative is reported in AOCI in the 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 Product sales or Product costs in the Consolidated Statement of Operations at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by us.

For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Operations.

Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.

Realized gains and losses on derivatives that (1) require physical delivery, (2) are used for managing commodity risk on NGL processing or natural gas production activities, and (3) are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis.

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” (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. 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 fixed 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 the Consolidated Statement of Operations 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. Given that most inventory is sold in the same period that it is generated, the impact of these transactions is expected to have little impact to operating income.

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 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.

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 the 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 liabilities and Regulatory liabilities, deferred income, and other, respectively, in the 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.

Leases

We recognize a lease liability with an offsetting right-of-use asset in the 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, but a certain land lease has a term of 108 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.

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 the Consolidated Statement of Operations. 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.

Employee stock-based awards

We recognize compensation expense on employee stock-based awards on a straight-line basis; forfeitures are recognized when they occur.

Pension and other postretirement benefits

The funded status of each of the pension and other postretirement benefit plans is recognized separately in the Consolidated Balance Sheet as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan’s benefit obligation. 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 and unrecognized prior service costs and credits 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). 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 6 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.

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 the Consolidated Statement of Operations 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 the Consolidated Statement of Operations includes any dilutive effect of nonvested restricted stock units, stock options, and convertible instruments, unless otherwise noted. Diluted earnings (loss) per common share is calculated using the treasury-stock method.

Accounting standards issued and adopted

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changed the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities are required to use a forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. We adopted ASU 2016-13 effective January 1, 2020, which primarily applied to our short-term trade receivables. There was no cumulative effect adjustment to retained earnings upon adoption.

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 business and gathering and transportation business 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 utilized historical loss rates over many years, which included periods of both high and low commodity prices. Commodity prices could have a significant impact on a portion of our gathering and processing counterparties’ financial health and ability to satisfy current liabilities. Our expected credit loss estimate considered 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 considered 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.

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, 2020.

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Variable Interest Entities

12 Months Ended

Dec. 31, 2020

Variable Interest Entity Disclosures [Abstract]

Variable Interest Entities [Text Block]

Note 2 – Variable Interest Entities

Consolidated VIEs

As of December 31, 2020, 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 on a proportional basis.

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,
	2020		2019
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	107	$	102
Trade accounts and other receivables – net	148		167
Other current assets and deferred charges	7		5
Property, plant, and equipment – net	5,514		5,745
Intangible assets – net of accumulated amortization	2,376		2,669
Regulatory assets, deferred charges, and other	15		13
Accounts payable	(42)		(58)
Accrued liabilities	(34)		(66)
Regulatory liabilities, deferred income, and other	(289)		(283)

Nonconsolidated VIEs

Targa Train 7

We own a 20 percent interest in Targa Train 7, which provides fractionation services at Mt. Belvieu and is a VIE due primarily to our limited participating rights as the minority equity holder. At December 31, 2020, the carrying value of our investment in Targa Train 7 was $51 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 (see Note 7 – Investing Activities), 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. During the first quarter of 2020 we recorded an impairment of our equity-method investment in Brazos Permian II (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk). Our maximum exposure to loss is limited to the carrying value of our investment.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2020

Business Combinations [Abstract]

Acquisitions and Divestitures [Text Block]

Note 3 – Acquisitions and Divestitures

UEOM

As of December 31, 2018, we owned a 62 percent interest in Utica East Ohio Midstream LLC (UEOM) which we accounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the

remaining 38 percent interest in UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility borrowings and cash on hand, net of $13 million cash acquired. As a result of acquiring this additional interest, we obtained control of and consolidated UEOM.

UEOM is involved primarily in the processing and fractionation of natural gas and natural gas liquids in the Utica Shale play in eastern Ohio. The purpose of the acquisition was to enhance our position in the region. We expect synergies through common ownership of UEOM and our Ohio Valley midstream systems to create a more efficient platform for capital spending in the region, resulting in reduced operating and maintenance expenses and creating enhanced capabilities and benefits for producers in the area.

The acquisition of UEOM was accounted for as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values. In March 2019, based on the transaction price for our purchase of the remaining interest in UEOM as finalized just prior to the acquisition, we recognized a $74 million noncash impairment loss related to our existing 62 percent interest (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk). Thus, there was no gain or loss on remeasuring our existing equity-method investment to fair value due to the impairment recognized just prior to closing the acquisition of the additional interest.

The valuation techniques used to measure the acquisition date fair value of the UEOM acquisition consisted of the market approach for our previous equity-method investment in UEOM and 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 Northeast G&P segment, and liabilities assumed, including post closing purchase price adjustments. The net assets acquired reflect the sum of the consideration transferred and the noncash elimination of the fair value of our existing equity-method investment upon our acquisition of the additional interest. The fair value of accounts receivable acquired, presented in current assets in the table, equals contractual amounts receivable.

	(Millions)
Current assets, including $13 million cash acquired	$	56
Property, plant, and equipment	1,387
Other intangible assets	328
Total identifiable assets acquired	1,771
Current liabilities	7
Total liabilities assumed	7
Net identifiable assets acquired	1,764
Goodwill	187
Net assets acquired	$	1,951

The goodwill recognized in the acquisition related primarily to enhancing and diversifying our basin positions and is reported within the Northeast G&P segment. Substantially all of the goodwill is expected to be deductible for tax purposes. As of December 31, 2019, goodwill was included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet and represented the excess of the consideration, plus the fair value of any previously held equity interest, over the fair value of the net assets acquired.

The goodwill recognized in the UEOM acquisition of $187 million, which includes a $1 million adjustment recorded in the first quarter of 2020, was impaired during first quarter of 2020. Our partner’s $65 million share of

this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).

Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas gathering, processing, and fractionation 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 a period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 49 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, processing, and fractionation 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 was approximately 10 years.

The following unaudited pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for the years ended December 31, 2019 and 2018, respectively, are presented as if the UEOM acquisition had been completed on January 1, 2018. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date 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,
	2019		2018
	(Millions)
Revenues	$	8,233	$	8,836
Net income (loss) attributable to The Williams Companies, Inc.	928		(128)

Adjustments to pro forma Net income (loss) attributable to The Williams Companies, Inc. include the removal of the previously described $74 million impairment loss recognized in March 2019 just prior to the acquisition.

During the period from the acquisition date of March 18, 2019 to December 31, 2019, UEOM contributed Revenues of $179 million and Net income (loss) attributable to The Williams Companies, Inc. of $53 million.

Costs related to this acquisition are $4 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expenses in the Consolidated Statement of Operations for the year ended December 31, 2019.

Northeast JV

Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner invested approximately $1.33 billion for a 35 percent ownership interest, and we retained 65 percent ownership of, as well as operate and consolidate, the Northeast JV business. The change in ownership due to this transaction increased Noncontrolling interests in consolidated subsidiaries by $567 million, and decreased Capital in excess of par value by $426 million and Deferred income tax liabilities by $141 million in the Consolidated Balance Sheet as of December 31, 2019. Costs related to this transaction are $6 million and are reported within our Northeast G&P segment and included in Selling, general, and administrative expenses in the Consolidated Statement of Operations for the year ended December 31, 2019.

Sale of Gulf Coast Pipeline Systems

In November 2018, we completed the sale of certain assets and operations located in the Gulf Coast area for $177 million in cash. As a result of this sale, we recorded a gain of approximately $101 million in the fourth quarter of 2018, consisting of $81 million in our Transmission & Gulf of Mexico segment and $20 million in Other.

Previous impairments made to a portion of these assets and operations include $66 million related to certain idle pipelines in the second quarter of 2018. The impairment is reflected in Impairment of certain assets in the Consolidated Statement of Operations. (See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) The results of operations for this disposal group, excluding the impairments and gains noted, were not significant for the reporting period.

Sale of Four Corners Assets

In October 2018, we completed the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado for total consideration of $1.125 billion. As a result of this sale, we recorded a gain of approximately $591 million within the West segment in the fourth quarter of 2018.

The following table presents the results of operations for the Four Corners area, excluding the gain noted above:

	Year Ended December 31,
	2018
	(Millions)
Income (loss) before income taxes of Four Corners area	$	52
Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc.	43

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Related Party Transactions

12 Months Ended

Dec. 31, 2020

Related Party Transactions [Abstract]

Related Party Transactions [Text Block]

Note 4 – Related Party Transactions

Transactions with Equity-Method Investees

We have purchases from our equity-method investees included in Product costs in the Consolidated Statement of Operations of $348 million, $304 million, and $236 million for the years ended 2020, 2019, and 2018, respectively. We have $50 million and $36 million included in Accounts payable in the Consolidated Balance Sheet with our equity-method investees at December 31, 2020 and 2019, 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 $79 million, $103 million, and $75 million for the years ended 2020, 2019, and 2018, respectively.

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Revenue Recognition

12 Months Ended

Dec. 31, 2020

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		Northeast Midstream		West Midstream		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		1,204		—		(75)		2,756
Commodity consideration	—		—		21		7		101		—		—		129
Other	10		—		27		164		65		1		(14)		253
Total service revenues	2,414		449		396		1,450		1,370		1		(96)		5,984
Product sales:
NGL and natural gas	80		—		114		57		1,565		—		(147)		1,669
Total revenues from contracts with customers	2,494		449		510		1,507		2,935		1		(243)		7,653
Other revenues (1)	10		—		9		22		8		33		(16)		66
Total revenues	$	2,504	$	449	$	519	$	1,529	$	2,943	$	34	$	(259)	$	7,719
2019
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,336	$	450	$	—	$	—	$	—	$	—	$	(6)	$	2,780
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		479		1,171		1,309		—		(75)		2,884
Commodity consideration	—		—		41		12		150		—		—		203
Other	11		—		26		147		42		—		(16)		210
Total service revenues	2,347		450		546		1,330		1,501		—		(97)		6,077
Product sales:
NGL and natural gas	106		—		185		150		1,795		—		(173)		2,063
Total revenues from contracts with customers	2,453		450		731		1,480		3,296		—		(270)		8,140
Other revenues (1)	1		—		8		20		14		30		(12)		61
Total revenues	$	2,454	$	450	$	739	$	1,500	$	3,310	$	30	$	(282)	$	8,201

	Transco		Northwest Pipeline		Gulf of Mexico Midstream		Northeast Midstream		West Midstream		Other		Eliminations		Total
	(Millions)
2018
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	1,921	$	443	$	—	$	—	$	—	$	—	$	(2)	$	2,362
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		541		861		1,590		2		(73)		2,921
Commodity consideration	—		—		59		20		321		—		—		400
Other	2		—		17		94		46		—		(15)		144
Total service revenues	1,923		443		617		975		1,957		2		(90)		5,827
Product sales:
NGL and natural gas	127		—		307		287		2,421		—		(382)		2,760
Other	—		—		—		—		21		—		(4)		17
Total product sales	127		—		307		287		2,442		—		(386)		2,777
Total revenues from contracts with customers	2,050		443		924		1,262		4,399		2		(476)		8,604
Other revenues (1)	11		—		18		21		12		32		(12)		82
Total revenues	$	2,061	$	443	$	942	$	1,283	$	4,411	$	34	$	(488)	$	8,686

______________________________

(1)Revenues not within the scope of ASC 606, “Revenue from Contracts with Customers,” consist of leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated equity-method investments, which are reported in Service revenues in the Consolidated Statement of Operations, and amounts associated with our derivative contracts, which are reported in Product sales in the Consolidated Statement of Operations.

Contract Assets

The following table presents a reconciliation of our contract assets:

	Year Ended December 31,
	2020		2019
	(Millions)
Balance at beginning of year	$	8	$	4
Revenue recognized in excess of amounts invoiced	145		62
Minimum volume commitments invoiced	(141)		(58)
Balance at end of year	$	12	$	8

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

	Year Ended December 31,
	2020		2019
	(Millions)
Balance at beginning of year	$	1,215	$	1,397
Payments received and deferred	140		157
Significant financing component	11		13
Chesapeake global resolution (Note 1)	67		—
Recognized in revenue	(224)		(352)
Balance at end of year	$	1,209	$	1,215

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, 2020, 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, 2020, 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, 2020.

	Contract Liabilities		Remaining Performance Obligations
	(Millions)
2021	$	129	$	3,537
2022	113		3,329
2023	118		3,076
2024	98		2,443
2025	92		2,310
Thereafter	659		17,760
Total	$	1,209	$	32,455

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Other Income and Expenses

12 Months Ended

Dec. 31, 2020

Other Income and Expenses [Abstract]

Other Income and Expenses [Text Block]

Note 6 – Other Income and Expenses

The following table presents by segment, certain items within Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations:

	Transmission & Gulf of Mexico		Northeast G&P		West		Other
	(Millions)
2020
Income related to benefit policy change	$	(22)	$	(9)	$	(9)	$	—
2019
Severance and related costs	39		7		10		1
2018
Expense from charitable contribution of preferred stock to the Williams Companies Foundation, Inc. (Note 16)	—		—		—		35
WPZ Merger related costs	—		—		—		20

Additional Items

Other income (expense) – net below Operating income (loss) includes $15 million, $32 million, and $89 million of income for equity AFUDC within the Transmission & Gulf of Mexico segment for the years ended December 31, 2020, 2019, and 2018, respectively. Other income (expense) – net below Operating income (loss) also includes $(13) million of loss and $9 million and $35 million of income, for the years ended December 31, 2020, 2019, and 2018, respectively, associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction primarily within the Other segment.

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Investing Activities

12 Months Ended

Dec. 31, 2020

Investments [Abstract]

Investing Activities [Text Block]

Note 7 – Investing Activities

Acquisition of Additional Interests in Caiman II

As of December 31, 2019, we effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent interest in Caiman II, whose primary asset is a 50 percent interest in Blue Racer. On November 18, 2020, we paid $157 million, net of cash acquired, to acquire an additional 41 percent ownership interest in Caiman II. We now control and consolidate Caiman II, reporting the 50 percent interest in Blue Racer as an equity-method investment. Since substantially all of the fair value of the Caiman II assets acquired is concentrated in a single asset, the investment in Blue Racer, and we previously held a noncontrolling interest in Caiman II, we recorded the November 18, 2020, additional purchase of interests as an asset acquisition.

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 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for information regarding impairments of our equity-method investments of $1,046 million, $186 million, and $32 million for 2020, 2019, and 2018, respectively.

Other Investing Income (Loss) – Net

The following table presents certain items reflected in Other investing income (loss) – net in the Consolidated Statement of Operations:

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Gain (loss) on deconsolidation of businesses	$	—	$	(29)	$	203
Gain on disposition of Jackalope	—		122		—
Other	8		14		16
Other investing income (loss) – net	$	8	$	107	$	219

Constitution deconsolidation

Upon determination that we were no longer the primary beneficiary, we deconsolidated our interest in Constitution Pipeline Company, LLC (Constitution) as of December 31, 2019, recognizing a loss on deconsolidation of $27 million.

Delaware basin asset deconsolidation and Brazos Permian II equity-method investment

During the fourth quarter of 2018, we contributed the majority of our existing Delaware basin assets and $27 million in cash in exchange for a 15 percent interest in the Brazos Permian II, which consists of gas and crude oil gathering pipelines, natural gas processing, and oil storage facilities. We recorded a deconsolidation gain of $141 million reflecting the excess of the fair value of our acquired interest over the carrying value of the assets contributed. We estimated the fair value of our interest to be $192 million primarily using a market approach (a Level 3 measurement within the fair value hierarchy). This approach involved the observation of recent transaction multiples in the Permian basin, including recent acquisitions consummated during 2018. Our interest in Brazos Permian II is considered an equity-method investment due to the fact that we are able to exert significant influence over its operating and financial policies.

Jackalope deconsolidation

During the second quarter of 2018, we deconsolidated our 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope). We recorded our interest in Jackalope as an equity-method investment at its estimated fair value, resulting in a deconsolidation gain of $62 million. We estimated the fair value of our interest to be $310 million using an income approach based on expected future cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of expected future cash flows involved significant assumptions regarding gathering and processing volumes and related capital spending. A 10.9 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. The deconsolidated carrying value of the net assets of Jackalope included $47 million of goodwill.

Gain on disposition of Jackalope

In April 2019, we sold our 50 percent equity-method interest in Jackalope for $485 million in cash, resulting in a gain on the disposition of $122 million.

Equity-Method Investments

	Ownership Interest at December 31, 2020	December 31,
		2020		2019
		(Millions)
Appalachia Midstream Investments	(1)	$	3,087	$	3,236
RMM	50%	421		881
OPPL	50%	395		403
Blue Racer/Caiman II (2)	50%	357		428
Discovery	60%	352		472
Laurel Mountain	69%	219		249
Gulfstream	50%	204		217
Brazos Permian II	15%	—		194
Other	Various	124		155
		$	5,159	$	6,235

___________

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

(2)See previous discussion in the section Acquisition of Additional Interests in Caiman II above.

The carrying value of our Appalachia Midstream Investments exceeds our portion of the underlying net assets by approximately $1.2 billion and $1.4 billion at December 31, 2020 and 2019, 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 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 $1.3 billion and $360 million at December 31, 2020 and 2019, 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 underlying net assets are generally amortized over the remaining useful lives of the associated underlying assets and included in Equity earnings (losses) within the Consolidated Statement of Operations.

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,
	2020		2019		2018
	(Millions)
Blue Racer/Caiman II (1)	$	157	$	28	$	—
Appalachia Midstream Investments	116		140		246
Targa Train 7	6		43		—
Laurel Mountain	5		36		16
RMM	—		145		795
Jackalope	—		24		42
Brazos Permian II	—		18		27
Discovery	—		—		5
Other	41		19		1
	$	325	$	453	$	1,132

___________

(1)See previous discussion in the section Acquisition of Additional Interests in Caiman II above.

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,
	2020		2019		2018
	(Millions)
Appalachia Midstream Investments	$	357	$	293	$	297
Gulfstream	93		86		93
OPPL	50		77		73
Blue Racer/Caiman II (1)	47		42		46
RMM	39		38		—
Laurel Mountain	31		30		23
Discovery	21		41		45
UEOM	—		13		70
Other	15		37		46
	$	653	$	657	$	693

___________

(1)See previous discussion in the section Acquisition of Additional Interests in Caiman II above.

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

	December 31,
	2020		2019
	(Millions)
Assets (liabilities):
Current assets	$	630	$	581
Noncurrent assets	13,424		11,966
Current liabilities	(312)		(341)
Noncurrent liabilities	(3,884)		(2,532)

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Gross revenue	$	2,625	$	2,490	$	2,411
Operating income	508		685		804
Net income	459		598		795

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Provision (Benefit) for Income Taxes

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Provision (Benefit) for Income Taxes [Text Block]

Note 8 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Current:
Federal	$	(29)	$	(41)	$	(83)
State	—		(5)		1
Foreign	—		2		—
	(29)		(44)		(82)
Deferred:
Federal	98		280		183
State	10		99		37
	108		379		220
Provision (benefit) for income taxes	$	79	$	335	$	138

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

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Provision (benefit) at statutory rate	$	58	$	224	$	69
Increases (decreases) in taxes resulting from:
Impact of nontaxable noncontrolling interests	3		29		(73)
State income taxes (net of federal benefit)	6		74		(10)
State deferred income tax rate change	—		—		38
Federal valuation allowance	1		3		105
Other – net	11		5		9
Provision (benefit) for income taxes	$	79	$	335	$	138

Income (loss) from continuing operations before income taxes includes $1 million, $6 million, and $3 million of foreign loss in 2020, 2019, and 2018, respectively.

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 and Deferred income tax assets are as follows:

	December 31,
	2020		2019
	(Millions)
Deferred income tax liabilities:
Property, plant and equipment	$	2,320	$	1,921
Investments	1,515		1,411
Other	140		82
Total deferred income tax liabilities	3,975		3,414
Deferred income tax assets:
Accrued liabilities	747		729
Minimum tax credit	—		29
Foreign tax credit	140		140
Federal loss carryovers	905		544
State losses and credits	445		362
Other	140		147
Total deferred income tax assets	2,377		1,951
Less valuation allowance	325		319
Net deferred income tax assets	2,052		1,632
Overall net deferred income tax liabilities	$	1,923	$	1,782

The valuation allowance at December 31, 2020 and 2019 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 credit and State losses and credits may not be realized. 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 2021 and 2039 with some carryovers having indefinite carryforward periods.

Federal loss carryovers include deferred tax assets on loss carryovers of $905 million which have no expiration date.

Cash refunds for income taxes (net of payments) were $40 million and $86 million in 2020 and 2019, respectively. Cash payments for income taxes (net of refunds) were $11 million in 2018.

As of December 31, 2020, we had approximately $51 million of unrecognized tax benefits. No change occurred to the amount of unrecognized tax benefits in each of the years 2020 and 2019. If recognized, income tax expense would be reduced by $51 million for each of the years 2020 and 2019, including the effect of these changes on other tax attributes, with state income tax amounts included net of federal tax effect.

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 a benefit of $900 thousand in 2020 and expenses of $500 thousand and $800 thousand for 2019 and 2018, respectively. Approximately $4 million and $3 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2020 and 2019, respectively.

During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.

Consolidated U.S. Federal income tax returns are open to Internal Revenue Service (IRS) examination for years after 2010, excluding 2015 and 2016, for which the statutes have expired. As of December 31, 2020, examinations of tax returns for 2011 through 2014 are currently in appeals. We do not expect material changes in our financial position resulting from these examinations. The statute of limitations for most states expires one year after expiration of the IRS statute. Generally, tax returns for our previously owned Canadian entities are open to audit for tax years after 2012. Tax years 2013 and 2014 are currently under income tax examination. In September 2016, we sold the majority of our Canadian operations and, as part of the sale, indemnified the purchaser for any increases in Canadian tax due to an audit of any tax periods prior to the sale.

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Earnings (Loss) Per Common Share from Continuing Operations

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

Earnings (Loss) Per Common Share from Continuing Operations [Text Block]

Note 9 – Earnings (Loss) Per Common Share from Continuing Operations

	Year Ended December 31,
	2020		2019		2018
	(Dollars in millions, except per-share amounts; shares in thousands)
Income (loss) from continuing operations available to common stockholders	$	208	$	862	$	(156)
Basic weighted-average shares	1,213,631		1,212,037		973,626
Effect of dilutive securities:
Nonvested restricted stock units	1,531		1,811		—
Stock options	3		163		—
Diluted weighted-average shares (1)	1,215,165		1,214,011		973,626
Earnings (loss) per common share from continuing operations:
Basic	$	.17	$	.71	$	(.16)
Diluted	$	.17	$	.71	$	(.16)

________________

(1)    For the year ended December 31, 2018, 2.0 million weighted-average nonvested restricted stock units and 0.5 million weighted-average stock options have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to The Williams Companies, Inc.

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2020

Retirement Benefits [Abstract]

Employee Benefit Plans [Text Block]

Note 10 – 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. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to receive annuity payments, a lump-sum payment, or a combination of annuity and lump-sum payments.

We recognized a pre-tax, noncash settlement charge of $23 million in 2018, which is substantially reported in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations. This amount is included within the subsequent tables of net periodic benefit cost (credit) and other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes.

Other Postretirement Benefits

We currently provide subsidized retiree medical and life insurance benefits to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December 31, 1995. Subsidized retiree medical benefits for eligible participants age 65 and older are paid through contributions to health reimbursement accounts. Subsidized retiree medical benefits for eligible participants under age 65 are provided through a self-insured medical plan sponsored by us. The self-insured retiree medical plan provides for retiree

contributions and contains other cost-sharing features such as deductibles, co-payments, and co-insurance. The accounting for this plan anticipates estimated future increases to our contribution levels to the health reimbursement accounts for participants age 65 and older, as well as future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line with health care cost increases for participants under age 65.

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 are not eligible to receive compensation credits under the defined benefit pension plan are eligible for a fixed annual contribution made by us to the defined contribution plan. Our contributions charged to expense were $42 million in 2020, $36 million in 2019, and $35 million in 2018.

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
	2020		2019		2020		2019
	(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,237	$	1,187	$	215	$	186
Service cost	31		45		1		1
Interest cost	36		50		7		8
Plan participants’ contributions	—		—		2		2
Benefits paid	(41)		(111)		(14)		(12)
Net actuarial loss (gain)	47		69		9		30
Settlements	(127)		(3)		—		—
Net increase (decrease) in benefit obligation	(54)		50		5		29
Benefit obligation at end of year	1,183		1,237		220		215
Change in plan assets:
Fair value of plan assets at beginning of year	1,299		1,132		247		214
Actual return on plan assets	212		218		37		38
Employer contributions	14		63		6		5
Plan participants’ contributions	—		—		2		2
Benefits paid	(41)		(111)		(14)		(12)
Settlements	(127)		(3)		—		—
Net increase (decrease) in fair value of plan assets	58		167		31		33
Fair value of plan assets at end of year	1,357		1,299		278		247
Funded status — overfunded (underfunded)	$	174	$	62	$	58	$	32
Accumulated benefit obligation	$	1,167	$	1,221

The overfunded (underfunded) status of our pension plans and other postretirement benefit plan presented in the previous table are recognized in the Consolidated Balance Sheet within the following accounts:

	December 31,
	2020		2019
	(Millions)
Overfunded (underfunded) pension plans:
Noncurrent assets	$	203	$	92
Current liabilities	(3)		(3)
Noncurrent liabilities	(26)		(27)
Overfunded (underfunded) other postretirement benefit plan:
Noncurrent assets	64		38
Current liabilities	(6)		(6)

The plan assets within our other postretirement benefit plan are intended to be used for the payment of benefits for certain groups of participants. The Current liabilities for the other postretirement benefit plan represent the current portion of benefits expected to be payable in the subsequent year for the groups of participants whose benefits are not expected to be paid from plan assets.

The pension plans’ benefit obligation Net actuarial loss (gain) of $47 million in 2020 and $69 million in 2019 are primarily due to the impact of decreases in the discount rates utilized to calculate the benefit obligation, partially offset by the impact of decreases in the cash balance interest crediting rate assumption.

The 2020 benefit obligation Net actuarial loss (gain) of $9 million for our other postretirement benefit plan is primarily due to a decrease in the discount rate used to calculate the benefit obligation, partially offset by the net impact of experience related items. The 2019 benefit obligation Net actuarial loss (gain) of $30 million for our other postretirement benefit plan is primarily due to a decrease in the discount rate used to calculate the benefit obligation and other assumption changes, partially offset by the impact of benefit payment experience and tax law changes.

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

	December 31,
	2020		2019
	(Millions)
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	$	29	$	29
Fair value of plan assets	—		—
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	25		26
Fair value of plan assets	—		—

Pre-tax amounts not yet recognized in Net periodic benefit cost (credit) at December 31 are as follows: 

	Pension Benefits				Other Postretirement Benefits
	2020		2019		2020		2019
	(Millions)
Amounts included in Accumulated other comprehensive income (loss):
Net actuarial loss	$	(101)	$	(243)	$	(25)	$	(21)
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Net actuarial gain	N/A		N/A		$	32	$	11

In addition to the regulatory liabilities included in the previous table, differences in the amount of actuarially determined Net periodic benefit cost (credit) for our other postretirement benefit plan and the other postretirement benefit costs recovered in rates for Transco and Northwest Pipeline are deferred as a regulatory asset or liability. We have regulatory liabilities of $100 million at December 31, 2020 and $106 million at December 31, 2019, related to these deferrals. Additionally, Transco recognizes a regulatory liability for rate collections in excess of its amount funded to the tax-qualified pension plans. At December 31, 2020 and 2019, these regulatory liabilities were $39 million and $43 million, respectively. These pension and other postretirement plans amounts will be reflected in rates based on the rate structures of these gas pipelines.

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
	2020		2019		2018		2020		2019		2018
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	31	$	45	$	50	$	1	$	1	$	1
Interest cost	36		50		46		7		8		7
Expected return on plan assets	(53)		(61)		(63)		(11)		(10)		(11)
Amortization of prior service credit	—		—		—		—		—		(2)
Amortization of net actuarial loss	21		15		23		—		—		—
Net actuarial loss from settlements	9		1		23		—		—		—
Reclassification to regulatory liability	—		—		—		2		1		2
Net periodic benefit cost (credit)	$	44	$	50	$	79	$	(1)	$	—	$	(3)

The components of Net periodic benefit cost (credit) other than the service cost component are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations.

Items Recognized in Other Comprehensive Income (Loss) and Regulatory Assets and Liabilities

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
	2020		2019		2018		2020		2019		2018
	(Millions)
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	$	112	$	88	$	(18)	$	(4)	$	(9)	$	9
Amortization of net actuarial loss	21		15		23		—		—		—
Net actuarial loss from settlements	9		1		23		—		—		—
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	$	142	$	104	$	28	$	(4)	$	(9)	$	9

Other changes in plan assets and benefit obligations for our other postretirement benefit plan associated with Transco and Northwest Pipeline are recognized in regulatory assets and liabilities. Amounts recognized in regulatory assets and liabilities for the years ended December 31 consist of the following:

	2020		2019		2018
	(Millions)
Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities:
Net actuarial gain (loss)	$	21	$	7	$	(10)
Amortization of prior service credit	—		—		(2)

Key Assumptions

The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows: 

	Pension Benefits				Other Postretirement Benefits
	2020		2019		2020		2019
Discount rate	2.45	%	3.19	%	2.59	%	3.27	%
Rate of compensation increase	3.76		3.68		N/A		N/A
Cash balance interest crediting rate	3.00		3.50		N/A		N/A

The weighted-average assumptions utilized to determine Net periodic benefit cost (credit) for the years ended December 31 are as follows: 

	Pension Benefits						Other Postretirement  Benefits
	2020		2019		2018		2020		2019		2018
Discount rate	3.08	%	4.33	%	3.67	%	3.27	%	4.39	%	3.71	%
Expected long-term rate of return on plan assets	4.67		5.26		5.34		4.39		5.01		4.95
Rate of compensation increase	3.68		4.83		4.93		N/A		N/A		N/A
Cash balance interest crediting rate	3.50		4.25		4.25		N/A		N/A		N/A

The mortality assumptions used to determine the benefit obligations for our pension and other postretirement benefit plans reflect generational projection mortality tables. The assumed health care cost trend rate for 2021 is 7.0 percent. This rate decreases to 4.5 percent by 2027.

Plan Assets

Plan assets for our pension and other postretirement benefit plans consist primarily of equity and fixed income securities including mutual funds and commingled investment funds invested in equity and fixed income securities. The plans’ investment policy provides for a strategy in accordance with the Employee Retirement Income Security Act (ERISA), which governs the investment of the assets in a diversified portfolio. The plans follow a policy of diversifying the investments across various asset classes and investment managers.

The investment policy for the pension plans includes a general target asset allocation at December 31, 2020, of 25 percent equity securities and 75 percent fixed income securities. The target allocation includes the investments in equity and fixed income mutual and commingled investment funds.

Equity securities may include U.S. equities and non-U.S. equities. Investment in Williams’ securities or an entity in which Williams has a majority ownership is prohibited except where these securities may be owned in a commingled investment fund in which the plans’ trusts invest. No more than 5 percent of the total stock portfolio valued at market may be invested in the common stock of any one corporation.

Fixed income securities may consist of U.S. as well as international instruments, including emerging markets. The fixed income strategies may invest in U.S. and sovereign government, corporate, asset-backed securities, and mortgage-backed obligations. The weighted-average credit rating of the fixed income strategies must be at least “investment grade” including ratings by Moody’s and/or Standard & Poor’s. No more than 5 percent of the total fixed income portfolio may be invested in the fixed income securities of any one issuer with the exception of bond index funds and U.S. government guaranteed and agency securities.

The following securities and transactions are not authorized: unregistered securities, commodities or commodity contracts, short sales or margin transactions, or other leveraging strategies. Additionally, real estate equity, natural resource property, venture capital, leveraged buyouts, and other high-return, high-risk investments are generally restricted. Use of derivative securities in mutual funds and commingled investment funds held by the plans’ trusts is allowed. However, direct investment in derivative securities requires approval. Currently, investment managers are approved to enter into U.S. Treasury futures contracts on behalf of the plans to implement and manage duration and yield curve strategy in the fixed income portfolio.

There are no significant concentrations of risk within the plans’ investment securities because of the diversity of the types of investments, diversity of the various industries, and the diversity of the fund managers and investment strategies. Generally, the investments held in the plans are publicly traded, therefore, minimizing liquidity risk in the portfolio.

The fair values of our pension plan assets at December 31, 2020 and 2019 by asset class are as follows: 

	2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Pension assets:
Cash management fund	$	21	$	—	$	—	$	21
Equity securities	39		22		—		61
Fixed income securities (1):
U.S. Treasury securities	110		—		—		110
Government and municipal bonds	—		32		—		32
Mortgage and asset-backed securities	—		19		—		19
Corporate bonds	—		342		—		342
Other	—		4		—		4
	$	170	$	419	$	—	589
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							137
Equities — Global large and mid cap							121
Equities — International emerging markets							30
Fixed income — U.S. long and intermediate duration							346
Fixed income — Corporate bonds							134
Total assets at fair value at December 31, 2020							$	1,357

	2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Pension assets:
Cash management fund	$	11	$	—	$	—	$	11
Equity securities	41		22		—		63
Fixed income securities (1):
U.S. Treasury securities	62		—		—		62
Government and municipal bonds	—		35		—		35
Mortgage and asset-backed securities	—		11		—		11
Corporate bonds	—		360		—		360
Other	5		4		—		9
	$	119	$	432	$	—	551
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							133
Equities — Global large and mid cap							100
Equities — International emerging markets							26
Fixed income — U.S. long and intermediate duration							380
Fixed income — Corporate bonds							109
Total assets at fair value at December 31, 2019							$	1,299

The fair values of our other postretirement benefits plan assets at December 31, 2020 and 2019 by asset class are as follows:

	2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	12	$	—	$	—	$	12
Equity securities	38		10		—		48
Fixed income securities (1):
U.S. Treasury securities	14		—		—		14
Government and municipal bonds	—		4		—		4
Mortgage and asset-backed securities	—		3		—		3
Corporate bonds	—		45		—		45
Mutual fund — Municipal bonds	52		—		—		52
	$	116	$	62	$	—	178
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							18
Equities — Global large and mid cap							16
Equities — International emerging markets							4
Fixed income — U.S. long and intermediate duration							45
Fixed income — Corporate bonds							17
Total assets at fair value at December 31, 2020							$	278

	2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	11	$	—	$	—	$	11
Equity securities	35		9		—		44
Fixed income securities (1):
U.S. Treasury securities	8		—		—		8
Government and municipal bonds	—		4		—		4
Mortgage and asset-backed securities	—		1		—		1
Corporate bonds	—		43		—		43
Mutual fund — Municipal bonds	46		—		—		46
	$	100	$	57	$	—	157
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							16
Equities — Global large and mid cap							12
Equities — International emerging markets							3
Fixed income — U.S. long and intermediate duration							46
Fixed income — Corporate bonds							13
Total assets at fair value at December 31, 2019							$	247

____________

(1)The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a weighted-average duration of approximately 16 years for 2020 and 14 years for 2019.

(2)    The stated intents of the funds vary based on each commingled fund’s investment objective. These objectives generally include strategies to replicate or outperform various market indices. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 1 day to 30 days. Additionally, the fund managers retain the right to restrict withdrawals from and/or purchases into the funds so as not to disadvantage other investors in the funds. Generally, the funds also reserve the right to make all or a portion of the redemption in-kind rather than in cash or a combination of cash and in-kind.

The fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement of an asset.

Shares of the cash management and mutual funds are valued at fair value based on published market prices as of the close of business on the last business day of the year, which represents the net asset values of the shares held.

The fair values of equity securities traded on U.S. exchanges are derived from quoted market prices as of the close of business on the last business day of the year. The fair values of equity securities traded on foreign exchanges are also derived from quoted market prices as of the close of business on an active foreign exchange on the last business day of the year. However, the valuation requires translation of the foreign currency to U.S. dollars and this translation is considered an observable input to the valuation.

The fair values of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate values of the funds’ assets at fair value less liabilities, divided by the number of units outstanding.

The fair values of fixed income securities, except U.S. Treasury securities, are determined using pricing models. These pricing models incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads for similar securities to determine fair value. The U.S. Treasury securities are valued at fair value based on closing prices on the last business day of the year reported in the active market in which the security is traded.

Plan Benefit Payments and Employer Contributions

Following are the expected benefits to be paid by the plans. These estimates are based on the same assumptions previously discussed and reflect future service as appropriate. The actuarial assumptions are based on long-term expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant behaviors differ significantly from the actuarial assumptions. 

	Pension Benefits		Other Postretirement Benefits
	(Millions)
2021	$	96	$	14
2022	91		14
2023	86		14
2024	82		13
2025	82		13
2026-2030	378		57

In 2021, we do not expect to contribute to our tax-qualified pension plans. We expect to contribute approximately $2 million to our nonqualified pension plans and approximately $6 million to our other postretirement benefit plan.

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Property, Plant, and Equipment

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Property, Plant, and Equipment [Text Block]

Note 11 – 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,
			2020		2019
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	17,813	$	17,593
Construction in progress	Not applicable		289		354
Other	2 - 45		2,658		2,519
Regulated:
Natural gas transmission facilities		1.25 - 7.13	18,688		18,076
Construction in progress	Not applicable	Not applicable	382		586
Other	5 - 45	0.00 - 33.33	2,659		2,382
Total property, plant, and equipment, at cost			42,489		41,510
Accumulated depreciation and amortization			(13,560)		(12,310)
Property, plant, and equipment — net			$	28,929	$	29,200

__________

(1)    Estimated useful life and depreciation rates are presented as of December 31, 2020. 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 $1.393 billion, $1.390 billion, and $1.392 billion in 2020, 2019, and 2018, respectively.

Regulated Property, plant, and equipment – net includes approximately $507 million and $547 million at December 31, 2020 and 2019, 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, gas transmission pipelines and facilities, gas processing, fractionation, and compression facilities, gas gathering well connections and pipelines, underground storage caverns, and producing wells. 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 $1.159 billion and $1.117 billion are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 2020 and 2019, respectively.

	December 31,
	2020		2019
	(Millions)
Balance at beginning of year	$	1,165	$	1,032
Liabilities incurred (1)	37		15
Liabilities settled	(19)		(8)
Accretion expense	65		59
Revisions (2)	(26)		67
Balance at end of year	$	1,222	$	1,165

___________

(1)As a result of the global resolution with Chesapeake in 2020, we recorded $31 million of ARO related to natural gas properties transferred to us. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

(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 2020 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, decreases in inflation rates, and decreases in the discount rates used in the annual review process. The 2019 revisions reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets, increases in inflation rates, and decreases in the discount rates used in the annual review process.

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 18 – 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.

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Goodwill and Other Intangible Assets

12 Months Ended

Dec. 31, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Other Intangible Assets [Text Block]

Note 12 – Goodwill and Other Intangible Assets

Goodwill

Changes in the carrying amount of goodwill, included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, by reportable segment for the periods indicated are as follows:

	Northeast G&P
	(Millions)
December 31, 2018	$	—
UEOM Acquisition (Note 3)	188
December 31, 2019	188
Impairment of goodwill (Note 18)	(187)
Other (Note 3)	(1)
December 31, 2020	$	—

Goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with our evaluation of goodwill for impairment during the years ended December 31, 2019, and 2018, respectively.

Other Intangible Assets

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

	2020				2019
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
	(Millions)
Other intangible assets	$	9,561	$	(2,117)	$	9,560	$	(1,789)

Other intangible assets 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 20 years for the acquisition of UEOM and 30 years for other 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. Based on the estimated future revenues during the contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the contractual customer relationships associated with the UEOM acquisition was approximately 10 years. 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 other intangible assets was $328 million, $324 million, and $333 million in 2020, 2019, and 2018, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $328 million.

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Accrued Liabilities

12 Months Ended

Dec. 31, 2020

Accrued Liabilities, Current [Abstract]

Accrued Liabilities [Text Block]

Note 13 – Accrued Liabilities

	December 31,
	2020		2019
	(Millions)
Interest on debt	$	271	$	288
Employee costs	149		226
Estimated rate refund liabilities	—		189
Contract liabilities (Note 5)	129		158
Asset retirement obligation (Note 11)	63		48
Operating lease liabilities (Note 15)	28		21
Other, including accrued loss contingencies	304		346
	$	944	$	1,276

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Debt and Banking Arrangements

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Debt and Banking Arrangements [Text Block]

Note 14 – Debt and Banking Arrangements

Long-Term Debt

	December 31,
	2020		2019
	(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		—
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		—
Other financing obligation - Atlantic Sunrise	847		857
Other financing obligation - Dalton	257		259
Northwest Pipeline:
7.125% Debentures due 2025	85		85
4% Notes due 2027	500		500
Williams:
4.125% Notes due 2020	—		600
5.25% Notes due 2020	—		1,500
4% Notes due 2021	500		500
7.875% Notes due 2021	371		371
3.35% Notes due 2022	750		750
3.6% Notes due 2022	1,250		1,250
3.7% Notes due 2023	850		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		—
7.5% Debentures due 2031	339		339
7.75% Notes due 2031	252		252
8.75% Notes due 2032	445		445
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
Various — 7.7% to 10.25% Notes and Debentures due 2020 to 2027	3		24
Credit facility loans	—		—
Unamortized debt issuance costs	(125)		(119)
Net unamortized debt premium (discount)	(63)		(58)
Total long-term debt, including current portion	22,344		22,288
Long-term debt due within one year	(893)		(2,140)
Long-term debt	$	21,451	$	20,148

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, 2020
	(Millions)
2021	$	894
2022	2,025
2023	1,477
2024	2,280
2025	1,617

Issuances and retirements

On August 17, 2020, we retired $600 million of 4.125 percent senior unsecured notes that were 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. As part of the issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes. Under the terms of the agreement, Transco was obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. In the fourth quarter of 2020, Transco filed the registration statement and completed the exchange offer.

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.

We retired $32 million of 7.625 percent senior unsecured notes that matured on July 15, 2019.

Other financing obligations

During the construction of the Atlantic Sunrise and Dalton projects, Transco received funding from its partners 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 partners’ undivided interest in the assets, including the associated pipeline capacity, and reclassified the funding previously received from its partners from noncurrent liabilities to debt. The obligations, which mature in 2038 and 2052, respectively, require monthly interest and principal payments and both bear an interest rate of approximately 9 percent.

Credit Facilities

	December 31, 2020
	Stated Capacity		Outstanding
	(Millions)
Long-term credit facility (1)	$	4,500	$	—
Letters of credit under certain bilateral bank agreements			15

________________

(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 2018, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into a credit agreement (Credit Agreement) with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the credit facility is August 10, 2023. 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 August 10, 2025, 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 $1 billion. 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, make certain distributions during an event of default, and 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 and accelerate the maturity of the loans 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 Citibank N.A.'s alternate base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower’s senior unsecured long-term debt ratings.

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 facility, to be no greater than 5.0 to 1, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions with a total aggregate purchase price of $25 million or more has been executed, in which case 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) must be no greater than 65 percent for each of Transco and Northwest Pipeline.

At December 31, 2020, we are in compliance with these covenants.

Commercial Paper Program

In 2018, we entered into a $4 billion commercial paper program. 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, 2020 and 2019, no commercial paper was outstanding.

Cash Payments for Interest (Net of Amounts Capitalized)

Cash payments for interest (net of amounts capitalized) were $1.149 billion in 2020, $1.153 billion in 2019, and $1.064 billion in 2018.

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Leases

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Leases [Text Block]

Note 15 – 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,
	2020		2019
	(Millions)
Lease Cost:
Operating lease cost	$	37	$	40
Variable lease cost	19		27
Sublease income	(1)		(2)
Total lease cost	$	55	$	65
Cash paid for amounts included in the measurement of operating lease liabilities	$	30	$	39
	December 31,
	2020		2019
	(Millions)
Other Information:
Right-of-use asset (included in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet)	$	182	$	207
Operating lease liabilities:
Current (included in Accrued liabilities in the Consolidated Balance Sheet)	$	28	$	21
Noncurrent (included in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet)	$	161	$	188
Weighted-average remaining lease term – operating leases (years)	13		13
Weighted-average discount rate – operating leases	4.60%		4.61%

Prior to adopting ASU 2016-02 “Leases (Topic 842)”, which was effective January 1, 2019, total rent expense was $73 million in 2018 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations.

As of December 31, 2020, 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)
2021	$	34
2022	28
2023	23
2024	19
2025	17
Thereafter	140
Total future lease payments	261
Less amount representing interest	72
Total obligations under operating leases	$	189

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

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Stockholders' Equity

12 Months Ended

Dec. 31, 2020

Stockholders' Equity Note [Abstract]

Stockholders' Equity [Text Block]

Note 16 – Stockholders' Equity

On January 26, 2021, our board of directors approved a regular quarterly dividend to common stockholders of $0.41 per share payable on March 29, 2021.

Stockholder Rights Agreement

On March 19, 2020, our board of directors approved the adoption of a limited duration stockholder rights agreements (Rights Agreement) and declared a distribution of one preferred stock purchase right for each outstanding share of common stock. The Rights Agreement is intended to protect the interests of us and our stockholders by reducing the likelihood of another party gaining control of or significant influence over us without paying an appropriate premium considering recent volatile markets. Each preferred stock purchase right represents the right to purchase, upon certain terms and conditions, one one-thousandths (.001) of a share of Series C Participating Cumulative Preferred Stock, $1.00 par value per share. Each one-thousandth (.001) of a share of Series C Participating Cumulative Preferred Stock, if issued, would have rights similar to one share of our common stock. The distribution of preferred stock purchase rights occurred on March 30, 2020, to holders of record as of the close of business on that date. The Rights Agreement expires on March 20, 2021. Please see our Current Report on Form 8-K dated March 20, 2020, for additional details of the Rights Agreement.

On August 27, 2020, a purported shareholder filed a putative class action lawsuit in the Delaware Court of Chancery challenging the Rights Agreement. The plaintiff alleges that the individual members of our board of directors breached their fiduciary duties by adopting the Rights Agreement. On September 3, 2020, a purported shareholder filed a separate putative class action lawsuit in the Delaware Court of Chancery, asserting identical claims to the August 27, 2020, lawsuit. Both complaints seek declaratory relief, an injunction against the agreement, and an award of attorneys’ fees and costs, which are not expected to be material. The court consolidated the lawsuits. The trial occurred January 12 through January 14, 2021, and we are awaiting the court’s decision.

Issuance of Preferred Stock

In July 2018, through a wholly owned subsidiary, we contributed 35,000 shares of newly issued Series B Non-Voting Perpetual Preferred Stock (Preferred Stock) to The Williams Companies Foundation, Inc. (a not-for-profit corporation) for use in future charitable and nonprofit causes. The charitable contribution of Preferred Stock was recorded as an expense in the third quarter of 2018. The Preferred Stock was issued for an aggregate value of $35 million and pays non-cumulative quarterly cash dividends when, as and if declared, at a rate of 7.25 percent per year. Our certificate of incorporation authorizes 30 million shares of Preferred Stock, $1 par value per share.

AOCI

The following table presents the changes in AOCI by component, net of income taxes:

	Cash Flow Hedges		Foreign Currency Translation		Pension and Other Post Retirement Benefits		Total
	(Millions)
Balance at December 31, 2019	$	(2)	$	(1)	$	(196)	$	(199)
Other comprehensive income (loss) before reclassifications	(2)		—		81		79
Amounts reclassified from accumulated other comprehensive income (loss)	1		—		23		24
Other comprehensive income (loss)	(1)		—		104		103
Balance at December 31, 2020	$	(3)	$	(1)	$	(92)	$	(96)

Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 2020:

Component	Reclassifications		Classification
	(Millions)
Cash flow hedges:
Energy commodity contracts	$	1	Product sales
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit)	30		Other income (expense) – net below Operating income (loss)
Income tax benefit	(7)		Provision (benefit) for income taxes
Reclassifications during the period	$	24

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Equity-Based Compensation

12 Months Ended

Dec. 31, 2020

Share-based Payment Arrangement, Noncash Expense [Abstract]

Equity-Based Compensation [Text Block]

Note 17 – 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, 2020, 31 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 19 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 347 thousand shares at a weighted-average price of $16.07 per share during 2020. Approximately 1.7 million shares were available for purchase under the ESPP at December 31, 2020.

Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations include equity-based compensation expense for the years ended December 31, 2020, 2019, and 2018 of $52 million, $57 million, and $54 million, respectively. Income tax benefit recognized related to the stock-based compensation expense for the years ended December 31, 2020, 2019, and 2018 was $13 million, $14 million, and $14 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2020, was $57 million, substantially 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

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2020:

Restricted Stock Units Outstanding	Shares	Weighted- Average Fair Value (1)
	(Millions)
Nonvested at December 31, 2019	5.4	$	28.11
Granted	2.8	$	18.32
Forfeited	(0.5)	$	27.90
Vested	(1.5)	$	29.04
Nonvested at December 31, 2020	6.2	$	23.53

______________

(1)Performance-based restricted stock units are valued considering measures of total shareholder return utilizing a Monte Carlo valuation method, as well as return on capital employed and a ratio of debt to EBITDA. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years.

Value of Restricted Stock Units	2020		2019		2018
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	18.32	$	25.87	$	30.48
Total fair value of restricted stock units vested during the year (in millions)	$	43	$	29	$	35

Performance-based restricted stock units granted under the Plan represent 41 percent of nonvested restricted stock units outstanding at December 31, 2020. These grants may be earned at the end of the vesting period based on actual performance against a performance target. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.

Stock Options

The following summary reflects stock option activity and related information for the year ended December 31, 2020:

Stock Options	Options	Weighted- Average Exercise Price		Aggregate Intrinsic Value
	(Millions)			(Millions)
Outstanding at December 31, 2019	6.8	$	32.64
Granted	—	$	—
Exercised	(0.3)	$	17.28
Cancelled	(0.5)	$	34.04
Outstanding at December 31, 2020	6.0	$	33.18	$	—
Exercisable at December 31, 2020	5.7	$	33.41	$	—

The following table summarizes additional information related to stock option activity during each of the last three years:

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Total intrinsic value of options exercised	$	1	$	6	$	3
Tax benefits realized on options exercised	$	—	$	1	$	—
Cash received from the exercise of options	$	3	$	4	$	9

The weighted-average remaining contractual lives for stock options outstanding and exercisable at December 31, 2020, were 3.5 years and 3.3 years, respectively.

The estimated fair value at date of grant of options for our common stock granted in each respective year, using the Black-Scholes option pricing model, is as follows:

	2018
Weighted-average grant date fair value of options for our common stock granted during the year, per share	$	5.49
Weighted-average assumptions:
Dividend yield	4.7		%
Volatility	30.1		%
Risk-free interest rate	2.7		%
Expected life (years)	6.0

There were no stock options granted in 2020 or 2019. The expected dividend yield for each respective year is based on the dividend forecast for that year and the grant-date market price of our stock. Our expected future volatility is determined using the historical volatility of our stock and implied volatility on our traded options. Historical volatility is based on the blended 10-year historical volatility of our stock and certain peer companies. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.

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Fair Value Measurements, Guarantees, and Concentration of Credit Risk

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements, Guarantees, and Concentration of Credit Risk [Text Block]

Note 18 – 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, margin deposits, and accounts payable 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, 2020:
Measured on a recurring basis:
ARO Trust investments	$	235	$	235	$	235	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(22,344)		(27,043)		—		(27,043)		—
Guarantees	(40)		(27)		—		(11)		(16)
Assets (liabilities) at December 31, 2019:
Measured on a recurring basis:
ARO Trust investments	$	201	$	201	$	201	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(22,288)		(25,319)		—		(25,319)		—
Guarantees	(41)		(27)		—		(11)		(16)

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 the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

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 lateral and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach (see Note 14 – 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 liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $27 million at December 31, 2020. 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 the 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 (NYSE: WMB), 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 (COVID-19) 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. This goodwill resulted from the March 2019 acquisition of UEOM (see Note 3 – Acquisitions and Divestitures).

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 the Consolidated Statement of Operations. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations (see Note 3 – Acquisitions and Divestitures).

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		2020		2019		2018
			(Millions)
Impairment of certain assets:
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
Certain pipeline project (3)	Transmission & Gulf of Mexico	December 31, 2019	22				$	354
Certain gathering assets (4)	West	December 31, 2019	25				20
Certain gathering assets (4)	West	June 30, 2019	40				59
Certain idle gathering assets (5)	West	March 31, 2019	—				12
Certain gathering assets (6)	West	December 31, 2018	470						$	1,849
Certain idle pipeline assets (7)	Other	June 30, 2018	25						66
Other impairments and write-downs (8)							19
Impairment of certain assets					$	182	$	464	$	1,915

					Impairments
					Year Ended December 31,
	Segment	Date of Measurement	Fair Value		2020		2019		2018
			(Millions)
Impairment of equity-method investments:
RMM (9)	West	December 31, 2020	$	421	$	108
RMM (10)	West	March 31, 2020	557		243
Brazos Permian II (10)	West	March 31, 2020	—		193
Caiman II (11)	Northeast G&P	March 31, 2020	191		229
Appalachia Midstream Investments (11)	Northeast G&P	March 31, 2020	2,700		127
Aux Sable (11)	Northeast G&P	March 31, 2020	7		39
Laurel Mountain (11)	Northeast G&P	March 31, 2020	236		10
Discovery (11)	Transmission & Gulf of Mexico	March 31, 2020	367		97
Laurel Mountain (12)	Northeast G&P	September 30, 2019	242				$	79
Appalachia Midstream Investments (13)	Northeast G&P	September 30, 2019	102				17
Pennant (14)	Northeast G&P	August 31, 2019	11				17
UEOM (15)	Northeast G&P	March 17, 2019	1,210				74
UEOM (15)	Northeast G&P	December 31, 2018	1,293						$	32
Other							(1)
Impairment of equity-method investments					$	1,046	$	186	$	32

______________

(1)Relates to capitalized project development costs for the Northeast Supply Enhancement project. As previously disclosed, 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, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now required impairment. The estimated fair value of the materials within the capitalized project costs 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.

(2)Relates to a gathering system in the Marcellus Shale region, that is more likely than not to be sold in the short term. 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)Relates to the Constitution proposed pipeline project extending from Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems in New York. Although Constitution received a certificate of public convenience and necessity from the FERC to construct and operate the proposed pipeline and obtained, among other approvals, a waiver of the water quality certification under Section 401 of the Clean Water Act for the New York portion of the project, the members of Constitution, following extensive evaluation and discussion, determined that the underlying risk-adjusted return for this greenfield pipeline project had diminished in such a way that further development was no longer supported. The estimated fair value of the Property, plant, and equipment – net was based on probability-weighted third-party quotes. Our partners’ $209 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations.

(4)Relates to a gas gathering system in the Eagle Ford Shale region with expected declines in asset utilization and possible idling of the gathering system. We designated these operations as held for sale, included in Other current assets and deferred charges, as of December 31, 2019. As a result, we measured the fair value of the disposal group using the expected sales price under a contract with a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value of the Property, plant, and equipment – net at June 30, 2019, was determined using a market approach, which incorporated indications of interest from third parties.

(5)Reflects impairment of Property, plant, and equipment – net that is no longer in use for which the fair value was determined to be lower than the carrying value.

(6)Relates to our gathering operations in the Barnett Shale region. Certain of our contractual gathering rates, primarily those in the Barnett Shale region, are based on a percentage of the New York Mercantile Exchange (NYMEX) natural gas prices. During the fourth quarter of 2018, we determined there was a sustained decline in the forward price curves for natural gas. During this same period, a large producer customer in the Barnett Shale region removed their remaining drilling rig. These factors gave rise to an impairment evaluation of these assets, which incorporated management’s projections of future drilling activity and gathering rates, taking into consideration the information previously noted as well as recently available information regarding producer drilling cost assumptions in the basin. The resulting estimate of future undiscounted cash flows was less than our carrying value, necessitating the estimation of the fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization. To arrive at the fair value, we utilized an income approach with a discount rate of 8.5 percent, reflecting an estimated cost of capital and risks associated with the underlying assets.

(7)Relates to certain idle pipelines. The estimated fair value of the Property, plant, and equipment – net was determined by a market approach incorporating information derived from bids received for these assets, which we marketed for sale together with certain other assets. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. We sold these assets in the fourth quarter of 2018. (See Note 3 – Acquisitions and Divestitures.)

(8)Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value.

(9)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.

(10)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 recent market declines previously discussed.

(11)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 Caiman II 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 recent market declines previously discussed.

(12)Relates to a gas gathering system in the Marcellus Shale region that was adversely impacted by lower sustained forward natural gas price expectations and changes in expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 10.2 percent in our analysis.

(13)Relates to a certain gathering system held in Appalachia Midstream Investments that was adversely impacted by changes in the timing of expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 9 percent in our analysis.

(14)The estimated fair value of Pennant Midstream, LLC (Pennant) was determined by a market approach based on recent observable third-party transactions. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

(15)The estimated fair value at March 17, 2019, was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the acquisition in March 2019 (see Note 3 – Acquisitions and Divestitures). These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value at December 31, 2018, was determined by a market approach based on our analysis of inputs in the principal market.

Concentration of Credit Risk

The following table summarizes concentration of receivables, net of allowances:

	December 31,
	2020		2019
	(Millions)
NGLs, natural gas, and related products and services	$	638	$	613
Transportation of natural gas and related products	254		277
Accounts Receivable related to revenues from contracts with customers	892		890
Other	107		106
Trade accounts and other receivables - net	$	999	$	996

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, but customers’ financial condition and credit worthiness are evaluated regularly. Based upon this evaluation, we may obtain collateral to support receivables.

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Contingent Liabilities and Commitments

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities and Commitments [Text Block]

Note 19 – Contingent Liabilities and Commitments

Reporting of Natural Gas-Related Information to Trade Publications

Direct and indirect purchasers of natural gas in various states filed individual and class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter.

In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland appealed. On March 27, 2018, the appellate court reversed the district court’s grant of summary judgment, and on April 10, 2018, the defendants filed a petition for rehearing with the appellate court, which was denied on May 9, 2018. The case was remanded to the Nevada federal district court and subsequently remanded to its originally filed court, the Kansas federal district court where we re-urged our motion for summary judgment. The district court denied the motion but granted our request to seek permission for an immediate appeal to the appellate court. Oral argument occurred before the appellate court on January 19, 2021.

In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order. On August 6, 2018, the Ninth Circuit reversed the order denying class certification and remanded the case to the Nevada federal district court.

We reached an agreement to settle two of the actions, and on April 22, 2019, the Nevada federal district court preliminarily approved the settlements, which are on behalf of Kansas and Missouri class members. The final fairness hearing on the settlement occurred August 5, 2019, and a final judgment of dismissal with prejudice was entered the same day.

Two putative class actions remain unresolved, and they have been remanded to their originally filed court, the Wisconsin federal district court. Trial is scheduled to begin June 14, 2021.

Because of the uncertainty around the remaining unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter and, as a result, have exposure to future developments.

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. 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, 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 tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would apply to both Chesapeake and us. The settlement as reported would not require any contribution from us.

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. The Court of Chancery had scheduled trial for May 20 through May 24, 2019; the court struck this setting and reset the trial for June 8 through June 11, and June 15, 2020. Due to COVID-19, the court struck the June 2020 setting and re-scheduled the trial for August 31 through September 4, 2020; this setting was also struck as a result of COVID-19. The court reset trial for December 14 through December 18, 2020, but also struck this setting as a result of COVID-19. Trial has been reset for May 10 through May 17, 2021.

Former Olefins Business

SABIC Petrochemicals, the other interest owner in our former Geismar, Louisiana, olefins facility we sold in July 2017, sought recovery from us for losses it allegedly suffered, including its share of personal injury settlements in which it was a co-defendant, as well as amounts related to lost income, defense costs, and property damage associated with an explosion and fire at the plant in June 2013. We settled this claim with SABIC Petrochemicals in the fourth quarter 2020. Part of the settlement is covered by our general liability policy and any uninsured losses are immaterial.

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, 2020, we have accrued liabilities totaling $33 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, 2020, 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 promulgate and propose 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, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to 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. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

Continuing operations

Our interstate gas pipelines are involved in remediation 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, 2020, we have accrued liabilities of $4 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2020, we have accrued liabilities totaling $8 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, 2020, we have accrued environmental liabilities of $21 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, 2020, 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 $262 million at December 31, 2020.

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Segment Disclosures

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Segment Disclosures [Text Block]

Note 20 – Segment Disclosures

Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, and West. 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 revenues primarily represent the sale of NGLs from our natural gas processing plants and transportation services provided to our marketing business.

We define Modified EBITDA as follows:

•Net income (loss) before:

◦Income (loss) from discontinued operations;

◦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 Segment revenues to Total revenues as reported in the Consolidated Statement of Operations and Other financial information:

	Transmission & Gulf of Mexico		Northeast G&P		West		Other		Eliminations		Total
	(Millions)
2020
Segment revenues:
Service revenues
External	$	3,207	$	1,416	$	1,280	$	21	$	—	$	5,924
Internal	50		49		—		13		(112)		—
Total service revenues	3,257		1,465		1,280		34		(112)		5,924
Total service revenues – commodity consideration	21		7		101		—		—		129
Product sales
External	144		16		1,506		—		—		1,666
Internal	47		41		56		—		(144)		—
Total product sales	191		57		1,562		—		(144)		1,666
Total revenues	$	3,469	$	1,529	$	2,943	$	34	$	(256)	$	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
2019
Segment revenues:
Service revenues
External	$	3,261	$	1,291	$	1,364	$	17	$	—	$	5,933
Internal	50		47		—		13		(110)		—
Total service revenues	3,311		1,338		1,364		30		(110)		5,933
Total service revenues – commodity consideration	41		12		150		—		—		203
Product sales
External	217		115		1,733		—		—		2,065
Internal	71		35		64		—		(170)		—
Total product sales	288		150		1,797		—		(170)		2,065
Total revenues	$	3,640	$	1,500	$	3,311	$	30	$	(280)	$	8,201
Other financial information:
Additions to long-lived assets	$	1,341	$	1,245	$	304	$	21	$	—	$	2,911
Proportional Modified EBITDA of equity-method investments	177		454		115		—		—		746

	Transmission & Gulf of Mexico		Northeast G&P		West		Other		Eliminations		Total
	(Millions)
2018
Segment revenues:
Service revenues
External	$	2,904	$	935	$	1,641	$	22	$	—	$	5,502
Internal	49		41		—		12		(102)		—
Total service revenues	2,953		976		1,641		34		(102)		5,502
Total service revenues – commodity consideration	59		20		321		—		—		400
Product sales
External	174		245		2,365		—		—		2,784
Internal	261		42		83		—		(386)		—
Total product sales	435		287		2,448		—		(386)		2,784
Total revenues	$	3,447	$	1,283	$	4,410	$	34	$	(488)	$	8,686
Other financial information:
Additions to long-lived assets	$	2,379	$	477	$	279	$	36	$	—	$	3,171
Proportional Modified EBITDA of equity-method investments	183		493		94		—		—		770

The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Operations:

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico	$	2,379	$	2,175	$	2,293
Northeast G&P	1,489		1,314		1,086
West	998		952		38
Other	(15)		6		(29)
	4,851		4,447		3,388
Accretion expense associated with asset retirement obligations for nonregulated operations	(35)		(33)		(33)
Depreciation and amortization expenses	(1,721)		(1,714)		(1,725)
Impairment of goodwill	(187)		—		—
Equity earnings (losses)	328		375		396
Impairment of equity-method investments	(1,046)		(186)		(32)
Other investing income (loss) – net	8		107		219
Proportional Modified EBITDA of equity-method investments	(749)		(746)		(770)
Interest expense	(1,172)		(1,186)		(1,112)
(Provision) benefit for income taxes	(79)		(335)		(138)
Income (loss) from discontinued operations	—		(15)		—
Net income (loss)	$	198	$	714	$	193

The following table reflects Total assets and Equity-method investments by reportable segments:

	Total Assets				Equity-Method Investments
	December 31, 2020		December 31, 2019		December 31, 2020		December 31, 2019
	(Millions)
Transmission & Gulf of Mexico	$	19,110	$	18,796	$	610	$	741
Northeast G&P	14,569		15,399		3,682		3,973
West	10,558		11,265		867		1,521
Other	927		1,151		—		—
Eliminations (1)	(999)		(571)		—		—
Total	$	44,165	$	46,040	$	5,159	$	6,235

______________

(1)    Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program.

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Subsequent Event

12 Months Ended

Dec. 31, 2020

Subsequent Events [Abstract]

Subsequent Event [Text Block]

Note 21 – Subsequent Event

In February 2021, we acquired certain oil and gas properties, primarily approximately 2,000 operated wells, in the Wamsutter basin in Wyoming from a supermajor oil and gas company for a total of $79 million paid from cash on hand. We are working to identify an operating partner to optimize development of the properties and enhance the value of our connected midstream infrastructure. We expect to report these operations within our Other segment.

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2020

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)
2020
Deferred tax asset valuation allowance (1)	$	319	$	6	$	—	$	—	$	325
2019
Deferred tax asset valuation allowance (1)	320		(1)		—		—		319
2018
Deferred tax asset valuation allowance (1)	224		96		—		—		320

__________

(1)    Deducted from related assets.

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General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2020

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;

•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 the 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.

Equity-method investment basis differences [Policy Text Block]

Equity-method investment basis differences

Differences between the cost 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 the Consolidated Statement of Operations includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.

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, goodwill, and other identifiable intangible assets;

•Litigation-related contingencies;

•Environmental remediation obligations;

•Depreciation and/or amortization of long-lived assets;

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

•AROs;

•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, levelized incremental 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 for the years ended December 31, 2020 and 2019 are as follows:

	December 31,
	2020		2019
	(Millions)
Current assets reported within Other current assets and deferred charges	$	64	$	72
Noncurrent assets reported within Regulatory assets, deferred charges, and other	442		466
Total regulated assets	$	506	$	538
Current liabilities reported within Accrued liabilities	$	59	$	60
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other	1,314		1,277
Total regulated liabilities	$	1,373	$	1,337

Cash and cash equivalents [Policy Text Block]

Cash and cash equivalents

Cash and cash equivalents in the 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 (as discussed below in Accounting standards issued and adopted), the financial condition of our customers, and age of past due accounts. 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.

Inventories [Policy Text Block]

Inventories

Inventories in the Consolidated Balance Sheet primarily consist of NGLs, natural gas in underground storage, and materials and supplies and are stated at the lower of cost or net realizable value. The cost of inventories is primarily determined using the average-cost method.

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.

Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Operations.

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. 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 the Consolidated Statement of Operations, except for regulated entities, for which the liability is offset by 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.

Goodwill [Policy Text Block]

Goodwill Goodwill included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, as of December 31, 2019, represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, an impairment charge is recorded for the difference (not to exceed the carrying value of goodwill). Judgments and assumptions are inherent in our management’s estimates of fair value.

Other identifiable intangible assets [Policy Text Block]

Other identifiable intangible assets

Our other identifiable intangible assets included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation contractual customer relationships. Our other identifiable intangible assets are 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, other identifiable intangible assets, and investments [Policy Text Block]

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

We evaluate our property, plant, and equipment and other identifiable 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 in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the 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 the consolidated financial statements as an impairment charge.

Judgments 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.

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.

Cash flows from revolving credit facilities and commercial paper program [Policy Text Block]

Cash flows from revolving credit facilities and commercial paper program

Proceeds and payments related to borrowings under our credit facilities are reflected in the financing activities in the 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 the 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 14 – Debt and Banking Arrangements.)

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 the Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in the Consolidated Balance Sheet using the average-cost method.

Derivative instruments and hedging activities [Policy Text Block]

Derivative instruments and hedging activities

We may 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 report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets and deferred charges; Regulatory assets, deferred charges, and other; Accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.

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 on the 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 Product sales or Product costs in the Consolidated Statement of Operations.

For commodity derivatives designated as a cash flow hedge, the change in fair value of the derivative is reported in AOCI in the 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 Product sales or Product costs in the Consolidated Statement of Operations at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by us.

For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Operations.

Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.

Realized gains and losses on derivatives that (1) require physical delivery, (2) are used for managing commodity risk on NGL processing or natural gas production activities, and (3) are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis.

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” (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. 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 fixed 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 the Consolidated Statement of Operations 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. Given that most inventory is sold in the same period that it is generated, the impact of these transactions is expected to have little impact to operating income.

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 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.

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 the 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 liabilities and Regulatory liabilities, deferred income, and other, respectively, in the 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.

Leases [Policy Text Block]

Leases

We recognize a lease liability with an offsetting right-of-use asset in the 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, but a certain land lease has a term of 108 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.

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 the Consolidated Statement of Operations. 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.

Employee stock-based awards [Policy Text Block]

Employee stock-based awards

We recognize compensation expense on employee stock-based awards on a straight-line basis; forfeitures are recognized when they occur.

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 the Consolidated Balance Sheet as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan’s benefit obligation. 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 and unrecognized prior service costs and credits 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). 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 6 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.

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 the Consolidated Statement of Operations 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 the Consolidated Statement of Operations includes any dilutive effect of nonvested restricted stock units, stock options, and convertible instruments, unless otherwise noted. Diluted earnings (loss) per common share is calculated using the treasury-stock method.

New Accounting Pronouncements and Changes in Accounting Principles [Text Block]

Accounting standards issued and adopted

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changed the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities are required to use a forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. We adopted ASU 2016-13 effective January 1, 2020, which primarily applied to our short-term trade receivables. There was no cumulative effect adjustment to retained earnings upon adoption.

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 business and gathering and transportation business 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 utilized historical loss rates over many years, which included periods of both high and low commodity prices. Commodity prices could have a significant impact on a portion of our gathering and processing counterparties’ financial health and ability to satisfy current liabilities. Our expected credit loss estimate considered 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 considered 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.

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, 2020.

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General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Regulatory Assets and Liabilities [Table Text Block]

Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2020 and 2019 are as follows:

	December 31,
	2020		2019
	(Millions)
Current assets reported within Other current assets and deferred charges	$	64	$	72
Noncurrent assets reported within Regulatory assets, deferred charges, and other	442		466
Total regulated assets	$	506	$	538
Current liabilities reported within Accrued liabilities	$	59	$	60
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other	1,314		1,277
Total regulated liabilities	$	1,373	$	1,337

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Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	107	$	102
Trade accounts and other receivables – net	148		167
Other current assets and deferred charges	7		5
Property, plant, and equipment – net	5,514		5,745
Intangible assets – net of accumulated amortization	2,376		2,669
Regulatory assets, deferred charges, and other	15		13
Accounts payable	(42)		(58)
Accrued liabilities	(34)		(66)
Regulatory liabilities, deferred income, and other	(289)		(283)

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Acquisitions and Divestitures Acquisitions (Tables)

12 Months Ended

Dec. 31, 2020

Business Acquisition [Line Items]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

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 Northeast G&P segment, and liabilities assumed, including post closing purchase price adjustments. The net assets acquired reflect the sum of the consideration transferred and the noncash elimination of the fair value of our existing equity-method investment upon our acquisition of the additional interest. The fair value of accounts receivable acquired, presented in current assets in the table, equals contractual amounts receivable.

	(Millions)
Current assets, including $13 million cash acquired	$	56
Property, plant, and equipment	1,387
Other intangible assets	328
Total identifiable assets acquired	1,771
Current liabilities	7
Total liabilities assumed	7
Net identifiable assets acquired	1,764
Goodwill	187
Net assets acquired	$	1,951

Business Acquisition, Pro Forma Information [Table Text Block]

The following unaudited pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for the years ended December 31, 2019 and 2018, respectively, are presented as if the UEOM acquisition had been completed on January 1, 2018. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date 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,
	2019		2018
	(Millions)
Revenues	$	8,233	$	8,836
Net income (loss) attributable to The Williams Companies, Inc.	928		(128)

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Acquisitions and Divestitures Divestitures (Tables)

12 Months Ended

Dec. 31, 2020

Four Corners [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Disposal Groups, Including Discontinued Operations [Table Text Block]

The following table presents the results of operations for the Four Corners area, excluding the gain noted above:

	Year Ended December 31,
	2018
	(Millions)
Income (loss) before income taxes of Four Corners area	$	52
Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc.	43

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Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2020

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		Northeast Midstream		West Midstream		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		1,204		—		(75)		2,756
Commodity consideration	—		—		21		7		101		—		—		129
Other	10		—		27		164		65		1		(14)		253
Total service revenues	2,414		449		396		1,450		1,370		1		(96)		5,984
Product sales:
NGL and natural gas	80		—		114		57		1,565		—		(147)		1,669
Total revenues from contracts with customers	2,494		449		510		1,507		2,935		1		(243)		7,653
Other revenues (1)	10		—		9		22		8		33		(16)		66
Total revenues	$	2,504	$	449	$	519	$	1,529	$	2,943	$	34	$	(259)	$	7,719
2019
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,336	$	450	$	—	$	—	$	—	$	—	$	(6)	$	2,780
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		479		1,171		1,309		—		(75)		2,884
Commodity consideration	—		—		41		12		150		—		—		203
Other	11		—		26		147		42		—		(16)		210
Total service revenues	2,347		450		546		1,330		1,501		—		(97)		6,077
Product sales:
NGL and natural gas	106		—		185		150		1,795		—		(173)		2,063
Total revenues from contracts with customers	2,453		450		731		1,480		3,296		—		(270)		8,140
Other revenues (1)	1		—		8		20		14		30		(12)		61
Total revenues	$	2,454	$	450	$	739	$	1,500	$	3,310	$	30	$	(282)	$	8,201

	Transco		Northwest Pipeline		Gulf of Mexico Midstream		Northeast Midstream		West Midstream		Other		Eliminations		Total
	(Millions)
2018
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	1,921	$	443	$	—	$	—	$	—	$	—	$	(2)	$	2,362
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		541		861		1,590		2		(73)		2,921
Commodity consideration	—		—		59		20		321		—		—		400
Other	2		—		17		94		46		—		(15)		144
Total service revenues	1,923		443		617		975		1,957		2		(90)		5,827
Product sales:
NGL and natural gas	127		—		307		287		2,421		—		(382)		2,760
Other	—		—		—		—		21		—		(4)		17
Total product sales	127		—		307		287		2,442		—		(386)		2,777
Total revenues from contracts with customers	2,050		443		924		1,262		4,399		2		(476)		8,604
Other revenues (1)	11		—		18		21		12		32		(12)		82
Total revenues	$	2,061	$	443	$	942	$	1,283	$	4,411	$	34	$	(488)	$	8,686

______________________________

(1)Revenues not within the scope of ASC 606, “Revenue from Contracts with Customers,” consist of leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated equity-method investments, which are reported in Service revenues in the Consolidated Statement of Operations, and amounts associated with our derivative contracts, which are reported in Product sales in the Consolidated Statement of Operations.

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,
	2020		2019
	(Millions)
Balance at beginning of year	$	8	$	4
Revenue recognized in excess of amounts invoiced	145		62
Minimum volume commitments invoiced	(141)		(58)
Balance at end of year	$	12	$	8

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

	Year Ended December 31,
	2020		2019
	(Millions)
Balance at beginning of year	$	1,215	$	1,397
Payments received and deferred	140		157
Significant financing component	11		13
Chesapeake global resolution (Note 1)	67		—
Recognized in revenue	(224)		(352)
Balance at end of year	$	1,209	$	1,215

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, 2020.

	Contract Liabilities		Remaining Performance Obligations
	(Millions)
2021	$	129	$	3,537
2022	113		3,329
2023	118		3,076
2024	98		2,443
2025	92		2,310
Thereafter	659		17,760
Total	$	1,209	$	32,455

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Other Income and Expenses (Tables)

12 Months Ended

Dec. 31, 2020

Other Income and Expenses [Abstract]

Other Income and Expenses [Table Text Block]

The following table presents by segment, certain items within Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations:

	Transmission & Gulf of Mexico		Northeast G&P		West		Other
	(Millions)
2020
Income related to benefit policy change	$	(22)	$	(9)	$	(9)	$	—
2019
Severance and related costs	39		7		10		1
2018
Expense from charitable contribution of preferred stock to the Williams Companies Foundation, Inc. (Note 16)	—		—		—		35
WPZ Merger related costs	—		—		—		20

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Investing Activities (Tables)

12 Months Ended

Dec. 31, 2020

Investments [Abstract]

Realized Gain (Loss) on Investments [Table Text Block]

The following table presents certain items reflected in Other investing income (loss) – net in the Consolidated Statement of Operations:

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Gain (loss) on deconsolidation of businesses	$	—	$	(29)	$	203
Gain on disposition of Jackalope	—		122		—
Other	8		14		16
Other investing income (loss) – net	$	8	$	107	$	219

Investments [Table Text Block]

	Ownership Interest at December 31, 2020	December 31,
		2020		2019
		(Millions)
Appalachia Midstream Investments	(1)	$	3,087	$	3,236
RMM	50%	421		881
OPPL	50%	395		403
Blue Racer/Caiman II (2)	50%	357		428
Discovery	60%	352		472
Laurel Mountain	69%	219		249
Gulfstream	50%	204		217
Brazos Permian II	15%	—		194
Other	Various	124		155
		$	5,159	$	6,235

___________

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

(2)See previous discussion in the section Acquisition of Additional Interests in Caiman II above.

Contributions [Table Text Block]

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,
	2020		2019		2018
	(Millions)
Blue Racer/Caiman II (1)	$	157	$	28	$	—
Appalachia Midstream Investments	116		140		246
Targa Train 7	6		43		—
Laurel Mountain	5		36		16
RMM	—		145		795
Jackalope	—		24		42
Brazos Permian II	—		18		27
Discovery	—		—		5
Other	41		19		1
	$	325	$	453	$	1,132

___________

(1)See previous discussion in the section Acquisition of Additional Interests in Caiman II above.

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,
	2020		2019		2018
	(Millions)
Appalachia Midstream Investments	$	357	$	293	$	297
Gulfstream	93		86		93
OPPL	50		77		73
Blue Racer/Caiman II (1)	47		42		46
RMM	39		38		—
Laurel Mountain	31		30		23
Discovery	21		41		45
UEOM	—		13		70
Other	15		37		46
	$	653	$	657	$	693

___________

(1)See previous discussion in the section Acquisition of Additional Interests in Caiman II 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,
	2020		2019
	(Millions)
Assets (liabilities):
Current assets	$	630	$	581
Noncurrent assets	13,424		11,966
Current liabilities	(312)		(341)
Noncurrent liabilities	(3,884)		(2,532)

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Gross revenue	$	2,625	$	2,490	$	2,411
Operating income	508		685		804
Net income	459		598		795

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Provision (Benefit) for Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019		2018
	(Millions)
Current:
Federal	$	(29)	$	(41)	$	(83)
State	—		(5)		1
Foreign	—		2		—
	(29)		(44)		(82)
Deferred:
Federal	98		280		183
State	10		99		37
	108		379		220
Provision (benefit) for income taxes	$	79	$	335	$	138

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,
	2020		2019		2018
	(Millions)
Provision (benefit) at statutory rate	$	58	$	224	$	69
Increases (decreases) in taxes resulting from:
Impact of nontaxable noncontrolling interests	3		29		(73)
State income taxes (net of federal benefit)	6		74		(10)
State deferred income tax rate change	—		—		38
Federal valuation allowance	1		3		105
Other – net	11		5		9
Provision (benefit) for income taxes	$	79	$	335	$	138

Deferred tax liabilities and Deferred tax assets [Table Text Block]

Significant components of Deferred income tax liabilities and Deferred income tax assets are as follows:

	December 31,
	2020		2019
	(Millions)
Deferred income tax liabilities:
Property, plant and equipment	$	2,320	$	1,921
Investments	1,515		1,411
Other	140		82
Total deferred income tax liabilities	3,975		3,414
Deferred income tax assets:
Accrued liabilities	747		729
Minimum tax credit	—		29
Foreign tax credit	140		140
Federal loss carryovers	905		544
State losses and credits	445		362
Other	140		147
Total deferred income tax assets	2,377		1,951
Less valuation allowance	325		319
Net deferred income tax assets	2,052		1,632
Overall net deferred income tax liabilities	$	1,923	$	1,782

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Earnings (Loss) Per Common Share from Continuing Operations (Tables)

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

Earnings (loss) per common share [Table Text Block]

	Year Ended December 31,
	2020		2019		2018
	(Dollars in millions, except per-share amounts; shares in thousands)
Income (loss) from continuing operations available to common stockholders	$	208	$	862	$	(156)
Basic weighted-average shares	1,213,631		1,212,037		973,626
Effect of dilutive securities:
Nonvested restricted stock units	1,531		1,811		—
Stock options	3		163		—
Diluted weighted-average shares (1)	1,215,165		1,214,011		973,626
Earnings (loss) per common share from continuing operations:
Basic	$	.17	$	.71	$	(.16)
Diluted	$	.17	$	.71	$	(.16)

________________

(1)    For the year ended December 31, 2018, 2.0 million weighted-average nonvested restricted stock units and 0.5 million weighted-average stock options have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to The Williams Companies, Inc.

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2020

Retirement Benefits [Abstract]

Changes in benefit obligations and plan assets [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
	2020		2019		2020		2019
	(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,237	$	1,187	$	215	$	186
Service cost	31		45		1		1
Interest cost	36		50		7		8
Plan participants’ contributions	—		—		2		2
Benefits paid	(41)		(111)		(14)		(12)
Net actuarial loss (gain)	47		69		9		30
Settlements	(127)		(3)		—		—
Net increase (decrease) in benefit obligation	(54)		50		5		29
Benefit obligation at end of year	1,183		1,237		220		215
Change in plan assets:
Fair value of plan assets at beginning of year	1,299		1,132		247		214
Actual return on plan assets	212		218		37		38
Employer contributions	14		63		6		5
Plan participants’ contributions	—		—		2		2
Benefits paid	(41)		(111)		(14)		(12)
Settlements	(127)		(3)		—		—
Net increase (decrease) in fair value of plan assets	58		167		31		33
Fair value of plan assets at end of year	1,357		1,299		278		247
Funded status — overfunded (underfunded)	$	174	$	62	$	58	$	32
Accumulated benefit obligation	$	1,167	$	1,221

Overfunded (underfunded) status of our pension plans and other postretirement benefit plans [Table Text Block]

The overfunded (underfunded) status of our pension plans and other postretirement benefit plan presented in the previous table are recognized in the Consolidated Balance Sheet within the following accounts:

	December 31,
	2020		2019
	(Millions)
Overfunded (underfunded) pension plans:
Noncurrent assets	$	203	$	92
Current liabilities	(3)		(3)
Noncurrent liabilities	(26)		(27)
Overfunded (underfunded) other postretirement benefit plan:
Noncurrent assets	64		38
Current liabilities	(6)		(6)

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.

	December 31,
	2020		2019
	(Millions)
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	$	29	$	29
Fair value of plan assets	—		—
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	25		26
Fair value of plan assets	—		—

Pre-tax amounts not yet recognized in net periodic benefit cost (credit)[Table Text Block]

Pre-tax amounts not yet recognized in Net periodic benefit cost (credit) at December 31 are as follows: 

	Pension Benefits				Other Postretirement Benefits
	2020		2019		2020		2019
	(Millions)
Amounts included in Accumulated other comprehensive income (loss):
Net actuarial loss	$	(101)	$	(243)	$	(25)	$	(21)
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Net actuarial gain	N/A		N/A		$	32	$	11

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
	2020		2019		2018		2020		2019		2018
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	31	$	45	$	50	$	1	$	1	$	1
Interest cost	36		50		46		7		8		7
Expected return on plan assets	(53)		(61)		(63)		(11)		(10)		(11)
Amortization of prior service credit	—		—		—		—		—		(2)
Amortization of net actuarial loss	21		15		23		—		—		—
Net actuarial loss from settlements	9		1		23		—		—		—
Reclassification to regulatory liability	—		—		—		2		1		2
Net periodic benefit cost (credit)	$	44	$	50	$	79	$	(1)	$	—	$	(3)

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
	2020		2019		2018		2020		2019		2018
	(Millions)
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	$	112	$	88	$	(18)	$	(4)	$	(9)	$	9
Amortization of net actuarial loss	21		15		23		—		—		—
Net actuarial loss from settlements	9		1		23		—		—		—
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	$	142	$	104	$	28	$	(4)	$	(9)	$	9

Schedule of Regulatory Assets / Liabilities [Table Text Block]

Other changes in plan assets and benefit obligations for our other postretirement benefit plan associated with Transco and Northwest Pipeline are recognized in regulatory assets and liabilities. Amounts recognized in regulatory assets and liabilities for the years ended December 31 consist of the following:

	2020		2019		2018
	(Millions)
Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities:
Net actuarial gain (loss)	$	21	$	7	$	(10)
Amortization of prior service credit	—		—		(2)

Defined Benefit Plan, Assumptions [Table Text Block]

The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows: 

	Pension Benefits				Other Postretirement Benefits
	2020		2019		2020		2019
Discount rate	2.45	%	3.19	%	2.59	%	3.27	%
Rate of compensation increase	3.76		3.68		N/A		N/A
Cash balance interest crediting rate	3.00		3.50		N/A		N/A

The weighted-average assumptions utilized to determine Net periodic benefit cost (credit) for the years ended December 31 are as follows: 

	Pension Benefits						Other Postretirement  Benefits
	2020		2019		2018		2020		2019		2018
Discount rate	3.08	%	4.33	%	3.67	%	3.27	%	4.39	%	3.71	%
Expected long-term rate of return on plan assets	4.67		5.26		5.34		4.39		5.01		4.95
Rate of compensation increase	3.68		4.83		4.93		N/A		N/A		N/A
Cash balance interest crediting rate	3.50		4.25		4.25		N/A		N/A		N/A

Fair values of plan assets [Table Text Block]

The fair values of our pension plan assets at December 31, 2020 and 2019 by asset class are as follows: 

	2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Pension assets:
Cash management fund	$	21	$	—	$	—	$	21
Equity securities	39		22		—		61
Fixed income securities (1):
U.S. Treasury securities	110		—		—		110
Government and municipal bonds	—		32		—		32
Mortgage and asset-backed securities	—		19		—		19
Corporate bonds	—		342		—		342
Other	—		4		—		4
	$	170	$	419	$	—	589
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							137
Equities — Global large and mid cap							121
Equities — International emerging markets							30
Fixed income — U.S. long and intermediate duration							346
Fixed income — Corporate bonds							134
Total assets at fair value at December 31, 2020							$	1,357

	2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Pension assets:
Cash management fund	$	11	$	—	$	—	$	11
Equity securities	41		22		—		63
Fixed income securities (1):
U.S. Treasury securities	62		—		—		62
Government and municipal bonds	—		35		—		35
Mortgage and asset-backed securities	—		11		—		11
Corporate bonds	—		360		—		360
Other	5		4		—		9
	$	119	$	432	$	—	551
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							133
Equities — Global large and mid cap							100
Equities — International emerging markets							26
Fixed income — U.S. long and intermediate duration							380
Fixed income — Corporate bonds							109
Total assets at fair value at December 31, 2019							$	1,299

The fair values of our other postretirement benefits plan assets at December 31, 2020 and 2019 by asset class are as follows:

	2020
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	12	$	—	$	—	$	12
Equity securities	38		10		—		48
Fixed income securities (1):
U.S. Treasury securities	14		—		—		14
Government and municipal bonds	—		4		—		4
Mortgage and asset-backed securities	—		3		—		3
Corporate bonds	—		45		—		45
Mutual fund — Municipal bonds	52		—		—		52
	$	116	$	62	$	—	178
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							18
Equities — Global large and mid cap							16
Equities — International emerging markets							4
Fixed income — U.S. long and intermediate duration							45
Fixed income — Corporate bonds							17
Total assets at fair value at December 31, 2020							$	278

	2019
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	11	$	—	$	—	$	11
Equity securities	35		9		—		44
Fixed income securities (1):
U.S. Treasury securities	8		—		—		8
Government and municipal bonds	—		4		—		4
Mortgage and asset-backed securities	—		1		—		1
Corporate bonds	—		43		—		43
Mutual fund — Municipal bonds	46		—		—		46
	$	100	$	57	$	—	157
Commingled investment funds measured at net asset value practical expedient (2):
Equities — U.S. large cap							16
Equities — Global large and mid cap							12
Equities — International emerging markets							3
Fixed income — U.S. long and intermediate duration							46
Fixed income — Corporate bonds							13
Total assets at fair value at December 31, 2019							$	247

____________

(1)The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a weighted-average duration of approximately 16 years for 2020 and 14 years for 2019.

(2)    The stated intents of the funds vary based on each commingled fund’s investment objective. These objectives generally include strategies to replicate or outperform various market indices. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 1 day to 30 days. Additionally, the fund managers retain the right to restrict withdrawals from and/or purchases into the funds so as not to disadvantage other investors in the funds. Generally, the funds also reserve the right to make all or a portion of the redemption in-kind rather than in cash or a combination of cash and in-kind.

Expected benefit payments [Table Text Block]

Following are the expected benefits to be paid by the plans. These estimates are based on the same assumptions previously discussed and reflect future service as appropriate. The actuarial assumptions are based on long-term expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant behaviors differ significantly from the actuarial assumptions. 

	Pension Benefits		Other Postretirement Benefits
	(Millions)
2021	$	96	$	14
2022	91		14
2023	86		14
2024	82		13
2025	82		13
2026-2030	378		57

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Property, Plant, and Equipment (Tables)

12 Months Ended

Dec. 31, 2020

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,
			2020		2019
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	17,813	$	17,593
Construction in progress	Not applicable		289		354
Other	2 - 45		2,658		2,519
Regulated:
Natural gas transmission facilities		1.25 - 7.13	18,688		18,076
Construction in progress	Not applicable	Not applicable	382		586
Other	5 - 45	0.00 - 33.33	2,659		2,382
Total property, plant, and equipment, at cost			42,489		41,510
Accumulated depreciation and amortization			(13,560)		(12,310)
Property, plant, and equipment — net			$	28,929	$	29,200

__________

(1)    Estimated useful life and depreciation rates are presented as of December 31, 2020. 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 $1.159 billion and $1.117 billion are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 2020 and 2019, respectively.

	December 31,
	2020		2019
	(Millions)
Balance at beginning of year	$	1,165	$	1,032
Liabilities incurred (1)	37		15
Liabilities settled	(19)		(8)
Accretion expense	65		59
Revisions (2)	(26)		67
Balance at end of year	$	1,222	$	1,165

___________

(1)As a result of the global resolution with Chesapeake in 2020, we recorded $31 million of ARO related to natural gas properties transferred to us. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

(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 2020 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, decreases in inflation rates, and decreases in the discount rates used in the annual review process. The 2019 revisions reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets, increases in inflation rates, and decreases in the discount rates used in the annual review process.

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Goodwill and Other Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

Changes in the carrying amount of goodwill, included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, by reportable segment for the periods indicated are as follows:

	Northeast G&P
	(Millions)
December 31, 2018	$	—
UEOM Acquisition (Note 3)	188
December 31, 2019	188
Impairment of goodwill (Note 18)	(187)
Other (Note 3)	(1)
December 31, 2020	$	—

Schedule of Finite-Lived Intangible Assets [Table Text Block]

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

	2020				2019
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
	(Millions)
Other intangible assets	$	9,561	$	(2,117)	$	9,560	$	(1,789)

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Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2020

Accrued Liabilities, Current [Abstract]

Accrued Liabilities [Table Text Block]

	December 31,
	2020		2019
	(Millions)
Interest on debt	$	271	$	288
Employee costs	149		226
Estimated rate refund liabilities	—		189
Contract liabilities (Note 5)	129		158
Asset retirement obligation (Note 11)	63		48
Operating lease liabilities (Note 15)	28		21
Other, including accrued loss contingencies	304		346
	$	944	$	1,276

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Debt and Banking Arrangements (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

Long-Term Debt

	December 31,
	2020		2019
	(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		—
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		—
Other financing obligation - Atlantic Sunrise	847		857
Other financing obligation - Dalton	257		259
Northwest Pipeline:
7.125% Debentures due 2025	85		85
4% Notes due 2027	500		500
Williams:
4.125% Notes due 2020	—		600
5.25% Notes due 2020	—		1,500
4% Notes due 2021	500		500
7.875% Notes due 2021	371		371
3.35% Notes due 2022	750		750
3.6% Notes due 2022	1,250		1,250
3.7% Notes due 2023	850		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		—
7.5% Debentures due 2031	339		339
7.75% Notes due 2031	252		252
8.75% Notes due 2032	445		445
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
Various — 7.7% to 10.25% Notes and Debentures due 2020 to 2027	3		24
Credit facility loans	—		—
Unamortized debt issuance costs	(125)		(119)
Net unamortized debt premium (discount)	(63)		(58)
Total long-term debt, including current portion	22,344		22,288
Long-term debt due within one year	(893)		(2,140)
Long-term debt	$	21,451	$	20,148

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, 2020
	(Millions)
2021	$	894
2022	2,025
2023	1,477
2024	2,280
2025	1,617

Schedule of Line of Credit Facilities [Table Text Block]

Credit Facilities

	December 31, 2020
	Stated Capacity		Outstanding
	(Millions)
Long-term credit facility (1)	$	4,500	$	—
Letters of credit under certain bilateral bank agreements			15

________________

(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.

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Leases (Tables)

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Lease, Cost [Table Text Block]

	Year Ended December 31,
	2020		2019
	(Millions)
Lease Cost:
Operating lease cost	$	37	$	40
Variable lease cost	19		27
Sublease income	(1)		(2)
Total lease cost	$	55	$	65
Cash paid for amounts included in the measurement of operating lease liabilities	$	30	$	39
	December 31,
	2020		2019
	(Millions)
Other Information:
Right-of-use asset (included in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet)	$	182	$	207
Operating lease liabilities:
Current (included in Accrued liabilities in the Consolidated Balance Sheet)	$	28	$	21
Noncurrent (included in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet)	$	161	$	188
Weighted-average remaining lease term – operating leases (years)	13		13
Weighted-average discount rate – operating leases	4.60%		4.61%

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

As of December 31, 2020, 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)
2021	$	34
2022	28
2023	23
2024	19
2025	17
Thereafter	140
Total future lease payments	261
Less amount representing interest	72
Total obligations under operating leases	$	189

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Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2020

Stockholders' Equity Note [Abstract]

Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The following table presents the changes in AOCI by component, net of income taxes:

	Cash Flow Hedges		Foreign Currency Translation		Pension and Other Post Retirement Benefits		Total
	(Millions)
Balance at December 31, 2019	$	(2)	$	(1)	$	(196)	$	(199)
Other comprehensive income (loss) before reclassifications	(2)		—		81		79
Amounts reclassified from accumulated other comprehensive income (loss)	1		—		23		24
Other comprehensive income (loss)	(1)		—		104		103
Balance at December 31, 2020	$	(3)	$	(1)	$	(92)	$	(96)

Reclassifications Out Of Accumulated Other Comprehensive Income [Table Text Block]

Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 2020:

Component	Reclassifications		Classification
	(Millions)
Cash flow hedges:
Energy commodity contracts	$	1	Product sales
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit)	30		Other income (expense) – net below Operating income (loss)
Income tax benefit	(7)		Provision (benefit) for income taxes
Reclassifications during the period	$	24

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Equity-Based Compensation (Tables) - Williams Companies Incentive Plan [Member]

12 Months Ended

Dec. 31, 2020

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Nonvested Restricted Stock Unit Rollforward and related information [Table Text Block]

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2020:

Restricted Stock Units Outstanding	Shares	Weighted- Average Fair Value (1)
	(Millions)
Nonvested at December 31, 2019	5.4	$	28.11
Granted	2.8	$	18.32
Forfeited	(0.5)	$	27.90
Vested	(1.5)	$	29.04
Nonvested at December 31, 2020	6.2	$	23.53

______________

(1)Performance-based restricted stock units are valued considering measures of total shareholder return utilizing a Monte Carlo valuation method, as well as return on capital employed and a ratio of debt to EBITDA. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years.

Other restricted stock unit information [Table Text Block]

Value of Restricted Stock Units	2020		2019		2018
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	18.32	$	25.87	$	30.48
Total fair value of restricted stock units vested during the year (in millions)	$	43	$	29	$	35

Stock Option Rollfoward and related information [Table Text Block]

The following summary reflects stock option activity and related information for the year ended December 31, 2020:

Stock Options	Options	Weighted- Average Exercise Price		Aggregate Intrinsic Value
	(Millions)			(Millions)
Outstanding at December 31, 2019	6.8	$	32.64
Granted	—	$	—
Exercised	(0.3)	$	17.28
Cancelled	(0.5)	$	34.04
Outstanding at December 31, 2020	6.0	$	33.18	$	—
Exercisable at December 31, 2020	5.7	$	33.41	$	—

Cash Proceeds Received and Tax Benefit from Share-based Payment Awards [Table Text Block]

The following table summarizes additional information related to stock option activity during each of the last three years:

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Total intrinsic value of options exercised	$	1	$	6	$	3
Tax benefits realized on options exercised	$	—	$	1	$	—
Cash received from the exercise of options	$	3	$	4	$	9

Stock Options Schedule of Valuation Assumptions [Table Text Block]

The estimated fair value at date of grant of options for our common stock granted in each respective year, using the Black-Scholes option pricing model, is as follows:

	2018
Weighted-average grant date fair value of options for our common stock granted during the year, per share	$	5.49
Weighted-average assumptions:
Dividend yield	4.7		%
Volatility	30.1		%
Risk-free interest rate	2.7		%
Expected life (years)	6.0

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Fair Value Measurements, Guarantees, and Concentration of Credit Risk (Tables)

12 Months Ended

Dec. 31, 2020

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, margin deposits, and accounts payable 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, 2020:
Measured on a recurring basis:
ARO Trust investments	$	235	$	235	$	235	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(22,344)		(27,043)		—		(27,043)		—
Guarantees	(40)		(27)		—		(11)		(16)
Assets (liabilities) at December 31, 2019:
Measured on a recurring basis:
ARO Trust investments	$	201	$	201	$	201	$	—	$	—
Additional disclosures:
Long-term debt, including current portion	(22,288)		(25,319)		—		(25,319)		—
Guarantees	(41)		(27)		—		(11)		(16)

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		2020		2019		2018
			(Millions)
Impairment of certain assets:
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
Certain pipeline project (3)	Transmission & Gulf of Mexico	December 31, 2019	22				$	354
Certain gathering assets (4)	West	December 31, 2019	25				20
Certain gathering assets (4)	West	June 30, 2019	40				59
Certain idle gathering assets (5)	West	March 31, 2019	—				12
Certain gathering assets (6)	West	December 31, 2018	470						$	1,849
Certain idle pipeline assets (7)	Other	June 30, 2018	25						66
Other impairments and write-downs (8)							19
Impairment of certain assets					$	182	$	464	$	1,915

					Impairments
					Year Ended December 31,
	Segment	Date of Measurement	Fair Value		2020		2019		2018
			(Millions)
Impairment of equity-method investments:
RMM (9)	West	December 31, 2020	$	421	$	108
RMM (10)	West	March 31, 2020	557		243
Brazos Permian II (10)	West	March 31, 2020	—		193
Caiman II (11)	Northeast G&P	March 31, 2020	191		229
Appalachia Midstream Investments (11)	Northeast G&P	March 31, 2020	2,700		127
Aux Sable (11)	Northeast G&P	March 31, 2020	7		39
Laurel Mountain (11)	Northeast G&P	March 31, 2020	236		10
Discovery (11)	Transmission & Gulf of Mexico	March 31, 2020	367		97
Laurel Mountain (12)	Northeast G&P	September 30, 2019	242				$	79
Appalachia Midstream Investments (13)	Northeast G&P	September 30, 2019	102				17
Pennant (14)	Northeast G&P	August 31, 2019	11				17
UEOM (15)	Northeast G&P	March 17, 2019	1,210				74
UEOM (15)	Northeast G&P	December 31, 2018	1,293						$	32
Other							(1)
Impairment of equity-method investments					$	1,046	$	186	$	32

______________

(1)Relates to capitalized project development costs for the Northeast Supply Enhancement project. As previously disclosed, 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, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now required impairment. The estimated fair value of the materials within the capitalized project costs 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.

(2)Relates to a gathering system in the Marcellus Shale region, that is more likely than not to be sold in the short term. 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)Relates to the Constitution proposed pipeline project extending from Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems in New York. Although Constitution received a certificate of public convenience and necessity from the FERC to construct and operate the proposed pipeline and obtained, among other approvals, a waiver of the water quality certification under Section 401 of the Clean Water Act for the New York portion of the project, the members of Constitution, following extensive evaluation and discussion, determined that the underlying risk-adjusted return for this greenfield pipeline project had diminished in such a way that further development was no longer supported. The estimated fair value of the Property, plant, and equipment – net was based on probability-weighted third-party quotes. Our partners’ $209 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations.

(4)Relates to a gas gathering system in the Eagle Ford Shale region with expected declines in asset utilization and possible idling of the gathering system. We designated these operations as held for sale, included in Other current assets and deferred charges, as of December 31, 2019. As a result, we measured the fair value of the disposal group using the expected sales price under a contract with a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value of the Property, plant, and equipment – net at June 30, 2019, was determined using a market approach, which incorporated indications of interest from third parties.

(5)Reflects impairment of Property, plant, and equipment – net that is no longer in use for which the fair value was determined to be lower than the carrying value.

(6)Relates to our gathering operations in the Barnett Shale region. Certain of our contractual gathering rates, primarily those in the Barnett Shale region, are based on a percentage of the New York Mercantile Exchange (NYMEX) natural gas prices. During the fourth quarter of 2018, we determined there was a sustained decline in the forward price curves for natural gas. During this same period, a large producer customer in the Barnett Shale region removed their remaining drilling rig. These factors gave rise to an impairment evaluation of these assets, which incorporated management’s projections of future drilling activity and gathering rates, taking into consideration the information previously noted as well as recently available information regarding producer drilling cost assumptions in the basin. The resulting estimate of future undiscounted cash flows was less than our carrying value, necessitating the estimation of the fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization. To arrive at the fair value, we utilized an income approach with a discount rate of 8.5 percent, reflecting an estimated cost of capital and risks associated with the underlying assets.

(7)Relates to certain idle pipelines. The estimated fair value of the Property, plant, and equipment – net was determined by a market approach incorporating information derived from bids received for these assets, which we marketed for sale together with certain other assets. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. We sold these assets in the fourth quarter of 2018. (See Note 3 – Acquisitions and Divestitures.)

(8)Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value.

(9)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.

(10)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 recent market declines previously discussed.

(11)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 Caiman II 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 recent market declines previously discussed.

(12)Relates to a gas gathering system in the Marcellus Shale region that was adversely impacted by lower sustained forward natural gas price expectations and changes in expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 10.2 percent in our analysis.

(13)Relates to a certain gathering system held in Appalachia Midstream Investments that was adversely impacted by changes in the timing of expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 9 percent in our analysis.

(14)The estimated fair value of Pennant Midstream, LLC (Pennant) was determined by a market approach based on recent observable third-party transactions. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

(15)The estimated fair value at March 17, 2019, was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the acquisition in March 2019 (see Note 3 – Acquisitions and Divestitures). These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value at December 31, 2018, was determined by a market approach based on our analysis of inputs in the principal market.

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,
	2020		2019
	(Millions)
NGLs, natural gas, and related products and services	$	638	$	613
Transportation of natural gas and related products	254		277
Accounts Receivable related to revenues from contracts with customers	892		890
Other	107		106
Trade accounts and other receivables - net	$	999	$	996

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Segment Disclosures (Tables)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

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 Operations and Other financial information:

	Transmission & Gulf of Mexico		Northeast G&P		West		Other		Eliminations		Total
	(Millions)
2020
Segment revenues:
Service revenues
External	$	3,207	$	1,416	$	1,280	$	21	$	—	$	5,924
Internal	50		49		—		13		(112)		—
Total service revenues	3,257		1,465		1,280		34		(112)		5,924
Total service revenues – commodity consideration	21		7		101		—		—		129
Product sales
External	144		16		1,506		—		—		1,666
Internal	47		41		56		—		(144)		—
Total product sales	191		57		1,562		—		(144)		1,666
Total revenues	$	3,469	$	1,529	$	2,943	$	34	$	(256)	$	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
2019
Segment revenues:
Service revenues
External	$	3,261	$	1,291	$	1,364	$	17	$	—	$	5,933
Internal	50		47		—		13		(110)		—
Total service revenues	3,311		1,338		1,364		30		(110)		5,933
Total service revenues – commodity consideration	41		12		150		—		—		203
Product sales
External	217		115		1,733		—		—		2,065
Internal	71		35		64		—		(170)		—
Total product sales	288		150		1,797		—		(170)		2,065
Total revenues	$	3,640	$	1,500	$	3,311	$	30	$	(280)	$	8,201
Other financial information:
Additions to long-lived assets	$	1,341	$	1,245	$	304	$	21	$	—	$	2,911
Proportional Modified EBITDA of equity-method investments	177		454		115		—		—		746

	Transmission & Gulf of Mexico		Northeast G&P		West		Other		Eliminations		Total
	(Millions)
2018
Segment revenues:
Service revenues
External	$	2,904	$	935	$	1,641	$	22	$	—	$	5,502
Internal	49		41		—		12		(102)		—
Total service revenues	2,953		976		1,641		34		(102)		5,502
Total service revenues – commodity consideration	59		20		321		—		—		400
Product sales
External	174		245		2,365		—		—		2,784
Internal	261		42		83		—		(386)		—
Total product sales	435		287		2,448		—		(386)		2,784
Total revenues	$	3,447	$	1,283	$	4,410	$	34	$	(488)	$	8,686
Other financial information:
Additions to long-lived assets	$	2,379	$	477	$	279	$	36	$	—	$	3,171
Proportional Modified EBITDA of equity-method investments	183		493		94		—		—		770

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 the Consolidated Statement of Operations:

	Year Ended December 31,
	2020		2019		2018
	(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico	$	2,379	$	2,175	$	2,293
Northeast G&P	1,489		1,314		1,086
West	998		952		38
Other	(15)		6		(29)
	4,851		4,447		3,388
Accretion expense associated with asset retirement obligations for nonregulated operations	(35)		(33)		(33)
Depreciation and amortization expenses	(1,721)		(1,714)		(1,725)
Impairment of goodwill	(187)		—		—
Equity earnings (losses)	328		375		396
Impairment of equity-method investments	(1,046)		(186)		(32)
Other investing income (loss) – net	8		107		219
Proportional Modified EBITDA of equity-method investments	(749)		(746)		(770)
Interest expense	(1,172)		(1,186)		(1,112)
(Provision) benefit for income taxes	(79)		(335)		(138)
Income (loss) from discontinued operations	—		(15)		—
Net income (loss)	$	198	$	714	$	193

Total assets and equity method investments by reporting segment [Table Text Block]

The following table reflects Total assets and Equity-method investments by reportable segments:

	Total Assets				Equity-Method Investments
	December 31, 2020		December 31, 2019		December 31, 2020		December 31, 2019
	(Millions)
Transmission & Gulf of Mexico	$	19,110	$	18,796	$	610	$	741
Northeast G&P	14,569		15,399		3,682		3,973
West	10,558		11,265		867		1,521
Other	927		1,151		—		—
Eliminations (1)	(999)		(571)		—		—
Total	$	44,165	$	46,040	$	5,159	$	6,235

______________

(1)    Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program.

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General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Details) - USD ($) shares in Millions, $ in Millions		1 Months Ended		6 Months Ended	12 Months Ended
	Aug. 10, 2018	Nov. 30, 2020	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
General and Description Of Business [Abstract]
Stock Issued During Period, Value, New Issues						$ 141	$ (4)
Chesapeake Energy Corporation [Member]
Basis Of Presentation [Abstract]
Property, Plant and Equipment, Gross, Period Increase (Decrease)		$ 98
Increase (Decrease) in Contract with Customer, Liability		67
Increase (Decrease) in Asset Retirement Obligations		$ 31
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%
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%
Blue Racer Midstream LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage					50.00%
Williams Companies Inc [Member] | Northeast JV [Member]
General and Description Of Business [Abstract]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			65.00%
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%
Northeast G And P [Member] | Caiman Energy II [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage						58.00%
Northeast G And P [Member] | Williams Companies Inc [Member] | Caiman Energy II [Member]
General and Description Of Business [Abstract]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					99.00%
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]
Basis Of Presentation [Abstract]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest					15.00%
Dividend Reinvestment Program [Member]
General and Description Of Business [Abstract]
Sale of Stock, Consideration Received on Transaction				$ 46
Common Stock [Member]
General and Description Of Business [Abstract]
Stock Issued During Period, Value, New Issues						$ 0	0
Capital in excess of par value [Member]
General and Description Of Business [Abstract]
Stock Issued During Period, Value, New Issues						(426)	14
Accumulated Other Comprehensive Income (Loss)
General and Description Of Business [Abstract]
Stock Issued During Period, Value, New Issues						0	0
Noncontrolling Interests
General and Description Of Business [Abstract]
Stock Issued During Period, Value, New Issues						$ 567	$ (18)
WPZ Merger Agreement [Member]
General and Description Of Business [Abstract]
Limited Partners' Capital Account, Units Outstanding	256
Stock Issued During Period, Shares, New Issues	382
Other Assets, Noncurrent	$ 33
Deferred Tax Liabilities, Net, Noncurrent	(1,829)
WPZ Merger Agreement [Member] | Common Stock [Member]
General and Description Of Business [Abstract]
Stock Issued During Period, Value, New Issues	382
WPZ Merger Agreement [Member] | Capital in excess of par value [Member]
General and Description Of Business [Abstract]
Stock Issued During Period, Value, New Issues	6,112
WPZ Merger Agreement [Member] | Accumulated Other Comprehensive Income (Loss)
General and Description Of Business [Abstract]
Stock Issued During Period, Value, New Issues	(3)
WPZ Merger Agreement [Member] | Noncontrolling Interests
General and Description Of Business [Abstract]
Stock Issued During Period, Value, New Issues	$ (4,629)

XML

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets, Current	$ 64	$ 72
Regulatory Assets, Noncurrent	442	466
Total regulatory assets	506	538
Regulatory Liabilities, Current	59	60
Regulatory Liabilities, Noncurrent	1,314	1,277
Total regulatory liabilities	1,373	1,337
Leases [Abstract]
Operating Lease, Right-of-Use Asset	$ 182	$ 207
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%
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	6 years
Land [Member]
Leases [Abstract]
Lessee, Operating Lease, Term of Contract	108 years
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%
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%

XML

Variable Interest Entities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Variable Interest Entity [Line Items]
Assets	$ 44,165	$ 46,040
Equity-method investments	5,159	6,235
Variable Interest Entity, Primary Beneficiary [Member] | Cash and cash equivalents [Member]
Variable Interest Entity [Line Items]
Assets	107	102
Variable Interest Entity, Primary Beneficiary [Member] | Trade accounts and other receivables [Member]
Variable Interest Entity [Line Items]
Assets	148	167
Variable Interest Entity, Primary Beneficiary [Member] | Other current assets and deferred charges [Member]
Variable Interest Entity [Line Items]
Assets	7	5
Variable Interest Entity, Primary Beneficiary [Member] | Property, plant, and equipment, net [Member]
Variable Interest Entity [Line Items]
Assets	5,514	5,745
Variable Interest Entity, Primary Beneficiary [Member] | Intangible assets - net of accumulated amortization [Member]
Variable Interest Entity [Line Items]
Assets	2,376	2,669
Variable Interest Entity, Primary Beneficiary [Member] | Regulatory assets, deferred charges, and other [Member]
Variable Interest Entity [Line Items]
Assets	15	13
Variable Interest Entity, Primary Beneficiary [Member] | Accounts payable [Member]
Variable Interest Entity [Line Items]
Liabilities	(42)	(58)
Variable Interest Entity, Primary Beneficiary [Member] | Accrued liabilities [Member]
Variable Interest Entity [Line Items]
Liabilities	(34)	(66)
Variable Interest Entity, Primary Beneficiary [Member] | Regulatory liabilities, deferred income, and other [Member]
Variable Interest Entity [Line Items]
Liabilities	$ (289)	$ (283)
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	$ 51
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%

XML

Acquisitions (Details) - USD ($) $ in Millions				1 Months Ended	3 Months Ended		9 Months Ended	12 Months Ended
	Mar. 18, 2019	Dec. 31, 2018		Jun. 30, 2019	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Mar. 18, 2020	Mar. 17, 2019
Business Acquisition [Line Items]
Impairment of equity-method investments (Note 18)								$ 1,046	$ 186	$ 32
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life								30 years
Changes in ownership of consolidated subsidiaries, net									141	(4)
Impairment of goodwill (Note 18)								$ 187	0	0
Northeast JV [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners				35.00%
Noncontrolling Interests [Member]
Business Acquisition [Line Items]
Changes in ownership of consolidated subsidiaries, net									567	(18)
Impairment of goodwill (Note 18)					$ 65
Capital in excess of par value [Member]
Business Acquisition [Line Items]
Changes in ownership of consolidated subsidiaries, net									(426)	14
Northeast JV [Member]
Business Acquisition [Line Items]
Noncontrolling Interest in Joint Ventures				$ 1,330
Increase (Decrease) in Deferred Income Taxes									(141)
Northeast JV [Member] | Noncontrolling Interests [Member]
Business Acquisition [Line Items]
Changes in ownership of consolidated subsidiaries, net									567
Northeast JV [Member] | Capital in excess of par value [Member]
Business Acquisition [Line Items]
Changes in ownership of consolidated subsidiaries, net									(426)
Williams Companies Inc [Member] | Northeast JV [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				65.00%
Selling, general and administrative expenses [Member] | Northeast JV [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs									6
Northeast G And P [Member]
Business Acquisition [Line Items]
Goodwill		$ 0					$ 188	0	188	0
Level 3 [Member] | Fair Value, Nonrecurring [Member]
Business Acquisition [Line Items]
Impairment of goodwill (Note 18)					187
Level 3 [Member] | Fair Value, Nonrecurring [Member] | Impairment Of Equity-Method Investments [Member]
Business Acquisition [Line Items]
Impairment of equity-method investments (Note 18)									(1)
Utica East Ohio Midstream, LLC Acquisition [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 741
Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain (Loss), Net	0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents	13
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets	56
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	1,387
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles	328
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	1,771
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	7
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	7
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	1,764
Goodwill	187										$ 187
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	1,951
Business Acquisition, Goodwill, Expected Tax Deductible Amount	$ 187
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	49.00%
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension	10 years
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual							179
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual							53
Goodwill, Other Increase (Decrease)					$ 1			$ 1
Utica East Ohio Midstream, LLC Acquisition [Member] | Pro Forma [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue									8,233	8,836
Business Acquisition, Pro Forma Net Income (Loss)									$ 928	$ (128)
Utica East Ohio Midstream, LLC Acquisition [Member] | Selling, general and administrative expenses [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs							$ 4
Utica East Ohio Midstream, LLC [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage		62.00%								62.00%
Utica East Ohio Midstream, LLC [Member] | Level 3 [Member] | Fair Value, Nonrecurring [Member] | Northeast G And P [Member] | Impairment Of Equity-Method Investments [Member]
Business Acquisition [Line Items]
Impairment of equity-method investments (Note 18)		$ 32	[1]			$ 74
Utica East Ohio Midstream, LLC [Member] | Utica East Ohio Midstream, LLC Acquisition [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	38.00%
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage												62.00%

[1] The estimated fair value at March 17, 2019, was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the acquisition in March 2019 (see Note 3 – Acquisitions and Divestitures). These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value at December 31, 2018, was determined by a market approach based on our analysis of inputs in the principal market.

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Divestitures (Details) - USD ($) $ in Millions										3 Months Ended		12 Months Ended
		Dec. 31, 2020	[3]	Dec. 31, 2019		Jun. 30, 2019	[1]	Mar. 31, 2019	[5]	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Nov. 30, 2018	Oct. 01, 2018
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Gain on sale of certain assets												$ 0	$ (2)	$ 692
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member] | West [Member]
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Tangible Asset Impairment Charges	[1]			$ 20
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member]
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Tangible Asset Impairment Charges	[2]												$ 19
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | Transmission And Gulf Of Mexico [Member]
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Tangible Asset Impairment Charges		$ 170		$ 354	[4]
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | West [Member]
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Tangible Asset Impairment Charges						$ 59		$ 12
Gulf Coast Pipeline Systems [Member]
Income Statement and Additional Disclosures by Disposal Groups [Line Items]
Disposal Group, Consideration															$ 177
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Gain on sale of certain assets										$ 101
Gulf Coast Pipeline Systems [Member] | Transmission And Gulf Of Mexico [Member]
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Gain on sale of certain assets										81
Gulf Coast Pipeline Systems [Member] | Other [Member]
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Gain on sale of certain assets										20
Gulf Coast Pipeline Systems [Member] | Disposal Group, Not Discontinued Operations [Member] | Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Tangible Asset Impairment Charges											$ 66
Four Corners [Member] | West [Member]
Income Statement and Additional Disclosures by Disposal Groups [Line Items]
Disposal Group, Consideration																$ 1,125
Income (Loss) from Individually Significant Component Disposed of, Attributable to Parent, before Income Tax [Abstract]
Income (Loss) before Income Taxes of Disposal Group														52
Income (Loss) before Income Taxes of Disposal Group Attributable to the Williams Companies, Inc.														$ 43
Gain on sale of certain assets										$ 591

[1] Relates to a gas gathering system in the Eagle Ford Shale region with expected declines in asset utilization and possible idling of the gathering system. We designated these operations as held for sale, included in Other current assets and deferred charges, as of December 31, 2019. As a result, we measured the fair value of the disposal group using the expected sales price under a contract with a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value of the Property, plant, and equipment – net at June 30, 2019, was determined using a market approach, which incorporated indications of interest from third parties.

[2] Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value.

[3] Relates to capitalized project development costs for the Northeast Supply Enhancement project. As previously disclosed, 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, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now required impairment. The estimated fair value of the materials within the capitalized project costs 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.

[4] Relates to the Constitution proposed pipeline project extending from Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems in New York. Although Constitution received a certificate of public convenience and necessity from the FERC to construct and operate the proposed pipeline and obtained, among other approvals, a waiver of the water quality certification under Section 401 of the Clean Water Act for the New York portion of the project, the members of Constitution, following extensive evaluation and discussion, determined that the underlying risk-adjusted return for this greenfield pipeline project had diminished in such a way that further development was no longer supported. The estimated fair value of the Property, plant, and equipment – net was based on probability-weighted third-party quotes. Our partners’ $209 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations.

[5] Reflects impairment of Property, plant, and equipment – net that is no longer in use for which the fair value was determined to be lower than the carrying value.

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Related Party Transactions (Details) - Equity Method Investee [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Product costs	$ 348	$ 304	$ 236
Accounts payable	50	36
OperatingFeesAndCostsBilledToThirdParty	$ 79	$ 103	$ 75

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Revenue by Category (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ 7,653	$ 8,140	$ 8,604
Revenue Not from Contract with Customer	[1]	66	61	82
Total revenues		7,719	8,201	8,686
Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,846	2,780	2,362
NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,756	2,884	2,921
NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		129	203	400
Total revenues		129	203	400
Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		253	210	144
Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		5,984	6,077	5,827
Total revenues		5,924	5,933	5,502
NGL And Natural Gas Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,669	2,063	2,760
Other Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				17
Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				2,777
Total revenues		1,666	2,065	2,784
Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,494	2,453	2,050
Revenue Not from Contract with Customer	[1]	10	1	11
Total revenues		2,504	2,454	2,061
Transco [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,404	2,336	1,921
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	11	2
Transco [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,414	2,347	1,923
Transco [Member] | NGL And Natural Gas Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		80	106	127
Transco [Member] | Other Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				0
Transco [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				127
Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		449	450	443
Revenue Not from Contract with Customer	[1]	0	0	0
Total revenues		449	450	443
Northwest Pipeline [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		449	450	443
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		449	450	443
Northwest Pipeline [Member] | NGL And Natural Gas Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Northwest Pipeline [Member] | Other Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				0
Northwest Pipeline [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				0
Transmission And Gulf Of Mexico Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		510	731	924
Revenue Not from Contract with Customer	[1]	9	8	18
Total revenues		519	739	942
Transmission And Gulf Of Mexico Midstream [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Transmission And Gulf Of Mexico Midstream [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		348	479	541
Transmission And Gulf Of Mexico Midstream [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		21	41	59
Transmission And Gulf Of Mexico Midstream [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		27	26	17
Transmission And Gulf Of Mexico Midstream [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		396	546	617
Transmission And Gulf Of Mexico Midstream [Member] | NGL And Natural Gas Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		114	185	307
Transmission And Gulf Of Mexico Midstream [Member] | Other Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				0
Transmission And Gulf Of Mexico Midstream [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				307
Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,507	1,480	1,262
Revenue Not from Contract with Customer	[1]	22	20	21
Total revenues		1,529	1,500	1,283
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		1,279	1,171	861
Northeast Midstream [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		7	12	20
Northeast Midstream [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		164	147	94
Northeast Midstream [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,450	1,330	975
Northeast Midstream [Member] | NGL And Natural Gas Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		57	150	287
Northeast Midstream [Member] | Other Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				0
Northeast Midstream [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				287
West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,935	3,296	4,399
Revenue Not from Contract with Customer	[1]	8	14	12
Total revenues		2,943	3,310	4,411
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		1,204	1,309	1,590
West Midstream [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		101	150	321
West Midstream [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		65	42	46
West Midstream [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,370	1,501	1,957
West Midstream [Member] | NGL And Natural Gas Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,565	1,795	2,421
West Midstream [Member] | Other Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				21
West Midstream [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				2,442
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1	0	2
Revenue Not from Contract with Customer	[1]	33	30	32
Total revenues		34	30	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	2
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		1	0	0
Other [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1	0	2
Other [Member] | NGL And Natural Gas Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Other [Member] | Other Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				0
Other [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				0
Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(243)	(270)	(476)
Revenue Not from Contract with Customer	[1]	(16)	(12)	(12)
Total revenues		(259)	(282)	(488)
Intersegment Eliminations [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(7)	(6)	(2)
Intersegment Eliminations [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(75)	(75)	(73)
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		(14)	(16)	(15)
Intersegment Eliminations [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(96)	(97)	(90)
Intersegment Eliminations [Member] | NGL And Natural Gas Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ (147)	$ (173)	(382)
Intersegment Eliminations [Member] | Other Product Sales [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				(4)
Intersegment Eliminations [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax				$ (386)

[1] Revenues not within the scope of ASC 606, “Revenue from Contracts with Customers,” consist of leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated equity-method investments, which are reported in Service revenues in the Consolidated Statement of Operations, and amounts associated with our derivative contracts, which are reported in Product sales in the Consolidated Statement of Operations

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Revenue Recognition Contract Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenue Recognition [Abstract]
Contract with Customer, Asset, Net - Beginning of Period	$ 8	$ 4
Contract with Customer, Asset, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	145	62
Contract with Customer, Asset, Reclassified to Receivable	(141)	(58)
Contract with Customer, Asset, Net - End of Period	$ 12	$ 8

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Revenue Recognition Contract Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Contract With Customer, Liability [Line Items]
Contract with Customer, Liability - Beginning of Period	$ 1,215	$ 1,397
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	140	157
Other Significant Noncash Transaction, Value of Consideration Received	11	13
Contract with Customer, Liability, Revenue Recognized	(224)	(352)
Contract with Customer, Liability - End of Period	1,209	1,215
Chesapeake Energy Corporation [Member]
Contract With Customer, Liability [Line Items]
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Estimate of Transaction Price	$ 67	$ 0

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Revenue Recognition Contract Liabilities Performance Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	$ 1,209	$ 1,215	$ 1,397
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	129
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	113
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	118
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	98
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	92
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	$ 659
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
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]: 2022-01-01
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]: 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

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Revenue Recognition Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2020 USD ($)
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 32,455
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,537
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,329
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,076
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	2,443
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	2,310
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 17,760
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
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]: 2022-01-01
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]: 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

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Other Income and Expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | Transmission And Gulf Of Mexico [Member]
Segment Reporting Information [Line Items]
Cost, Direct Labor	$ (22)
Severance and other related costs		$ 39
Noncash Contribution Expense			$ 0
WPZ Merger			0
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | Northeast G And P [Member]
Segment Reporting Information [Line Items]
Cost, Direct Labor	(9)
Severance and other related costs		7
Noncash Contribution Expense			0
WPZ Merger			0
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | West [Member]
Segment Reporting Information [Line Items]
Cost, Direct Labor	(9)
Severance and other related costs		10
Noncash Contribution Expense			0
WPZ Merger			0
Selling, general, and administrative expenses and Operating and maintenance expenses [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Cost, Direct Labor	0
Severance and other related costs		1
Noncash Contribution Expense			35
WPZ Merger			20
Other income (expense) - net [Member] | Transmission And Gulf Of Mexico [Member]
Segment Reporting Information [Line Items]
Allowance for funds used during construction, capitalized cost of equity	15	32	89
Deferred Taxes On Equity Funds Used During Construction [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Allowance for funds used during construction, capitalized cost of equity	$ (13)	$ 9	$ 35

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Investing Activities (Details) - USD ($) $ in Millions				3 Months Ended		12 Months Ended
		Nov. 18, 2020	Dec. 31, 2019	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 15, 2018
Schedule of Investments [Line Items]
Income (Loss) from Equity Method Investments						$ (328)	$ (375)	$ (396)
Impairment of equity-method investments (Note 18)						(1,046)	(186)	(32)
Deconsolidation, Revaluation of Retained Investment, Gain (Loss), Amount						0	(29)	203
Gain on disposition of equity-method investment						0	122	0
Other investing income (loss) - net						8	107	219
Equity-method investment, payments to purchase or contributions						325	453	1,132
Equity-method investments			$ 6,235			5,159	6,235
Proceeds from dispositions of equity-method investments						0	485	0
Equity-method investment, difference between carrying amount and underlying equity			360			1,300	360
Distributions from unconsolidated affiliates						653	657	693
Current assets			1,580			1,429	1,580
Current liabilities			(3,968)			(2,319)	(3,968)
Revenues						7,719	8,201	8,686
Operating income						508	685	804
Net income						198	714	193
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Schedule of Investments [Line Items]
Current assets			581			630	581
Noncurrent assets			11,966			13,424	11,966
Current liabilities			(341)			(312)	(341)
Noncurrent liabilities			(2,532)			(3,884)	(2,532)
Revenues						2,625	2,490	2,411
Net income						459	598	$ 795
Measurement Input, Discount Rate [Member]
Schedule of Investments [Line Items]
Property Plant And Equipment And Intangibles Fair Value Inputs								8.50%
Other Income [Member]
Schedule of Investments [Line Items]
Other investing income (loss) - net						$ 8	14	$ 16
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						116	140	246
Equity-method investments	[1]		3,236			3,087	3,236
Equity-method investment, difference between carrying amount and underlying equity			1,400			1,200	1,400
Distributions from unconsolidated affiliates						$ 357	293	297
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 investment, payments to purchase or contributions						0	145	795
Equity-method investments			881			421	881
Distributions from unconsolidated affiliates						$ 39	38	0
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						$ 0	0	5
Equity-method investments			472			352	472
Distributions from unconsolidated affiliates						$ 21	41	45
Caiman Energy II [Member]
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions							28	0
Equity-method investments			428				428
Distributions from unconsolidated affiliates							42	46
Overland Pass Pipeline Company LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage						50.00%
Equity-method investments			403			$ 395	403
Distributions from unconsolidated affiliates						$ 50	77	73
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 investment, payments to purchase or contributions						5	36	16
Equity-method investments			249			219	249
Distributions from unconsolidated affiliates						$ 31	30	23
Gulfstream Natural Gas System, LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage						50.00%
Equity-method investments			217			$ 204	217
Distributions from unconsolidated affiliates						$ 93	86	$ 93
Brazos Permian II, LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage						15.00%		15.00%
Equity-method investment, payments to purchase or contributions						$ 0	18	$ 27
Equity-method investments			194			0	194
Utica East Ohio Midstream, LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage								62.00%
Distributions from unconsolidated affiliates						0	13	$ 70
Jackalope Gas Gathering Services LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%	50.00%
Gain on disposition of equity-method investment				$ 122
Equity-method investment, payments to purchase or contributions						0	24	42
Proceeds from dispositions of equity-method investments				$ 485
Constitution Pipeline Company LLC [Member]
Schedule of Investments [Line Items]
Deconsolidation, Revaluation of Retained Investment, Gain (Loss), Amount							27
Other [Member]
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions						41	19	1
Equity-method investments			$ 155			124	155
Distributions from unconsolidated affiliates						15	37	46
Total Equity Method Investment [Member]
Schedule of Investments [Line Items]
Distributions from unconsolidated affiliates						653	657	693
Targa Train 7 LLC [Member]
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions						$ 6	$ 43	0
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				157
Equity-method investments						357
Distributions from unconsolidated affiliates						$ 47
Northeast G And P [Member] | Caiman Energy II [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage			58.00%				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%
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] | Brazos Permian II, LLC [Member]
Schedule of Investments [Line Items]
Deconsolidation, Revaluation of Retained Investment, Gain (Loss), Amount								$ 141
West [Member] | Jackalope Gas Gathering Services LLC [Member]
Schedule of Investments [Line Items]
Deconsolidation, Revaluation of Retained Investment, Gain (Loss), Amount					$ 62
Goodwill, Period Increase (Decrease)					47
West [Member] | Targa Train 7 LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage						20.00%
Caiman Energy II Acquisition [Member] | Caiman Energy II [Member]
Schedule of Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		41.00%
Brazos Permian II, LLC [Member] | West [Member]
Schedule of Investments [Line Items]
Investments, Fair Value Disclosure									$ 192
Jackalope Gas Gathering Services LLC [Member] | West [Member]
Schedule of Investments [Line Items]
Investments, Fair Value Disclosure					$ 310
Jackalope Gas Gathering Services LLC [Member] | West [Member] | Measurement Input, Discount Rate [Member]
Schedule of Investments [Line Items]
Property Plant And Equipment And Intangibles Fair Value Inputs					10.90%
Caiman Energy II [Member] | 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 with an approximate average 66 percent interest.(2)See previous discussion in the section Acquisition of Additional Interests in Caiman II above.

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Provision (Benefit) for Income Taxes Tax Provison (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current :
Federal	$ (29)	$ (41)	$ (83)
State	0	(5)	1
Foreign	0	2	0
Total	(29)	(44)	(82)
Deferred:
Federal	98	280	183
State	10	99	37
Total	108	379	220
Less: Provision (benefit) for income taxes	$ 79	$ 335	$ 138

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Provision (Benefit) for Income Taxes Reconciliations to Recorded Tax Provision (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Effective Income Tax Rate Reconciliation [Abstract]
Provision (benefit) at statutory rate	$ 58	$ 224	$ 69
Increases (decreases) in taxes resulting from:
Impact of nontaxable noncontrolling interests	3	29	(73)
State income taxes (net of federal benefit)	6	74	(10)
State deferred income tax rate change	0	0	38
Federal valuation allowance	1	3	105
Other – net	11	5	9
Less: Provision (benefit) for income taxes	$ 79	$ 335	$ 138

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Provision (Benefit) for Income Taxes Deferred Tax Table (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred income tax liabilities:
Property, plant and equipment	$ 2,320	$ 1,921
Investments	1,515	1,411
Other	140	82
Total deferred income tax liabilities	3,975	3,414
Deferred income tax assets:
Accrued liabilities	747	729
Minimum tax credit	0	29
Foreign tax credit	140	140
Federal loss carryovers	905	544
State losses and credits	445	362
Other	140	147
Total deferred income tax assets	2,377	1,951
Less valuation allowance	325	319
Net deferred income tax assets	2,052	1,632
Overall net deferred income tax liabilities	$ 1,923	$ 1,782

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Provision (Benefit) for Income Taxes Textuals (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Contingency [Line Items]
Foreign income (loss) in Income from continuing operations before income taxes	$ (1,000)	$ (6,000)	$ (3,000)
Proceeds from Income Tax Refunds	40,000	86,000
Income Taxes Paid, Net			11,000
Unrecognized tax benefits	51,000
Unrecognized Tax Benefits, Period Increase (Decrease)	0	0
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	51,000	51,000
Total interest and penalties recognized as part of income tax provision	900	500	$ 800
Total interest and penalties accrued as uncertain tax positions	4,000	$ 3,000
Internal Revenue Service (IRS) [Member] | Expiration None [Member]
Income Tax Contingency [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards	$ 905,000

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Earnings (Loss) Per Common Share from Continuing Operations (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Earnings (loss) per common share
Income (loss) from continuing operations available to common stockholders	$ 208	$ 862	$ (156)
Basic weighted-average shares	1,213,631	1,212,037	973,626
Effect of dilutive securities:
Diluted weighted-average shares	1,215,165	1,214,011	973,626	[1]
Earnings (loss) per common share:
Basic	$ 0.17	$ 0.71	$ (0.16)
Diluted	$ 0.17	$ 0.71	$ (0.16)
Nonvested restricted stock units [Member]
Effect of dilutive securities:
Incremental common shares attributable to share-based payment arrangements under effects of dilutive securities item	1,531	1,811	0
Earnings (loss) per common share from continuing operations (Textuals) [Abstract]
Number of weighted-average shares excluded from computation of diluted earnings per common share			2,000
Stock options [Member]
Effect of dilutive securities:
Incremental common shares attributable to share-based payment arrangements under effects of dilutive securities item	3	163	0
Earnings (loss) per common share from continuing operations (Textuals) [Abstract]
Number of weighted-average shares excluded from computation of diluted earnings per common share			500

[1] For the year ended December 31, 2018, 2.0 million weighted-average nonvested restricted stock units and 0.5 million weighted-average stock options have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to The Williams Companies, Inc.

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EBPs Front Section and Obligation Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 42	$ 36	$ 35
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Pre-tax, noncash settlement charge	9	1	23
Change in benefit obligation:
Benefit obligation at beginning of year	1,237	1,187
Service cost	31	45	50
Interest cost	36	50	46
Plan participants’ contributions	0	0
Benefits paid	(41)	(111)
Net actuarial loss (gain)	47	69
Settlements	(127)	(3)
Net increase (decrease) in benefit obligation	(54)	50
Benefit obligation at end of year	1,183	1,237	1,187
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Pre-tax, noncash settlement charge	0	0	0
Change in benefit obligation:
Benefit obligation at beginning of year	215	186
Service cost	1	1	1
Interest cost	7	8	7
Plan participants’ contributions	2	2
Benefits paid	(14)	(12)
Net actuarial loss (gain)	9	30
Settlements	0	0
Net increase (decrease) in benefit obligation	5	29
Benefit obligation at end of year	$ 220	$ 215	$ 186

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EBP Asset rollforward and B.S. classification (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	$ 1,299	$ 1,132
Actual return on plan assets	212	218
Employer contributions	14	63
Plan participants’ contributions	0	0
Benefits paid	(41)	(111)
Settlements	(127)	(3)
Net increase (decrease) in fair value of plan assets	58	167
Fair value of plan assets at end of year	1,357	1,299
Funded status — overfunded (underfunded)	174	62
Accumulated benefit obligation	1,167	1,221
Overfunded/(underfunded) status of our pension plans and other postretirement benefit plans:
Noncurrent assets	203	92
Current liabilities	(3)	(3)
Noncurrent liabilities	(26)	(27)
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	29	29
Fair value of plan assets	0	0
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	25	26
Fair value of plan assets	0	0
Amounts included in Accumulated other comprehensive income (loss):
Net actuarial loss	(101)	(243)
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Net regulatory liabilities	39	43
Other Postretirement Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	247	214
Actual return on plan assets	37	38
Employer contributions	6	5
Plan participants’ contributions	2	2
Benefits paid	(14)	(12)
Settlements	0	0
Net increase (decrease) in fair value of plan assets	31	33
Fair value of plan assets at end of year	278	247
Funded status — overfunded (underfunded)	58	32
Overfunded/(underfunded) status of our pension plans and other postretirement benefit plans:
Noncurrent assets	64	38
Current liabilities	(6)	(6)
Amounts included in Accumulated other comprehensive income (loss):
Net actuarial loss	(25)	(21)
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Net actuarial gain	32	11
Net regulatory liabilities	$ 100	$ 106

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EBP Net Periodic Benefit Cost & OCI (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost	$ 31	$ 45	$ 50
Interest cost	36	50	46
Expected return on plan assets	(53)	(61)	(63)
Amortization of prior service credit	0	0	0
Amortization of net actuarial loss	21	15	23
Net actuarial loss from settlements	9	1	23
Reclassification to regulatory liability	0	0	0
Net periodic benefit cost (credit)	44	50	79
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	112	88	(18)
Amortization of net actuarial loss	21	15	23
Net actuarial loss from settlements	9	1	23
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	142	104	28
Other Postretirement Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost	1	1	1
Interest cost	7	8	7
Expected return on plan assets	(11)	(10)	(11)
Amortization of prior service credit	0	0	(2)
Amortization of net actuarial loss	0	0	0
Net actuarial loss from settlements	0	0	0
Reclassification to regulatory liability	2	1	2
Net periodic benefit cost (credit)	(1)	0	(3)
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	(4)	(9)	9
Amortization of net actuarial loss	0	0	0
Net actuarial loss from settlements	0	0	0
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	(4)	(9)	9
Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities:
Net actuarial gain (loss)	21	7	(10)
Amortization of prior service credit	$ 0	$ 0	(2)
Other Nonoperating Income (Expense) [Member] | Pension Benefits [Member]
Components of net periodic benefit cost (credit):
Net actuarial loss from settlements			$ 23

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EBP Key Assumptions (Details 3)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	2.45%	3.19%
Rate of compensation increase	3.76%	3.68%
Cash balance interest crediting rate	3.00%	3.50%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	3.08%	4.33%	3.67%
Expected long-term rate of return on plan assets	4.67%	5.26%	5.34%
Rate of compensation increase	3.68%	4.83%	4.93%
Cash balance interest crediting rate	3.50%	4.25%	4.25%
Other Postretirement Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	2.59%	3.27%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	3.27%	4.39%	3.71%
Expected long-term rate of return on plan assets	4.39%	5.01%	4.95%
Health care cost trend rate assumed for next fiscal year	7.00%
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	2027

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EBP Plan Assets (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Maximum percentage of total stock portfolio invested in the common stock of any one corporation	5.00%
Maximum percentage of portfolio invested in fixed income securities of any one issuer with exception of bond index funds and U. S. government guaranteed and agency securities	5.00%
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	30 days
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	1 day
Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average duration of fixed income security portfolio	16 years	14 years
Pension Benefits [Member]
Fair values of plan assets
Total assets at fair value	$ 1,357	$ 1,299	$ 1,132
Pension Benefits [Member] | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Plan asset target allocation	25.00%
Pension Benefits [Member] | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan asset target allocation	75.00%
Pension Benefits [Member] | Level 1 [Member]
Fair values of plan assets
Total assets at fair value	$ 170	119
Pension Benefits [Member] | Level 1 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	21	11
Pension Benefits [Member] | Level 1 [Member] | Equity Securities
Fair values of plan assets
Total assets at fair value	39	41
Pension Benefits [Member] | Level 1 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	110	62
Pension Benefits [Member] | Level 1 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 1 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 1 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 1 [Member] | Other
Fair values of plan assets
Total assets at fair value	0	5
Pension Benefits [Member] | Level 2 [Member]
Fair values of plan assets
Total assets at fair value	419	432
Pension Benefits [Member] | Level 2 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 2 [Member] | Equity Securities
Fair values of plan assets
Total assets at fair value	22	22
Pension Benefits [Member] | Level 2 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 2 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	32	35
Pension Benefits [Member] | Level 2 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	19	11
Pension Benefits [Member] | Level 2 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	342	360
Pension Benefits [Member] | Level 2 [Member] | Other
Fair values of plan assets
Total assets at fair value	4	4
Pension Benefits [Member] | Level 3 [Member]
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Equity Securities
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Level 3 [Member] | Other
Fair values of plan assets
Total assets at fair value	0	0
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Fair values of plan assets
Total assets at fair value	589	551
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	21	11
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Equity Securities
Fair values of plan assets
Total assets at fair value	61	63
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	110	62
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	32	35
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	19	11
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	342	360
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Other
Fair values of plan assets
Total assets at fair value	4	9
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - U.S. large cap
Fair values of plan assets
Total assets at fair value	137	133
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - Global large and mid cap
Fair values of plan assets
Total assets at fair value	121	100
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - International emerging markets
Fair values of plan assets
Total assets at fair value	30	26
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - fixed income - U.S. long and intermediate duration
Fair values of plan assets
Total assets at fair value	346	380
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - fixed income - Corporate bonds
Fair values of plan assets
Total assets at fair value	134	109
Other Postretirement Benefits [Member]
Fair values of plan assets
Total assets at fair value	278	247	$ 214
Other Postretirement Benefits [Member] | Level 1 [Member]
Fair values of plan assets
Total assets at fair value	116	100
Other Postretirement Benefits [Member] | Level 1 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	12	11
Other Postretirement Benefits [Member] | Level 1 [Member] | Equity Securities
Fair values of plan assets
Total assets at fair value	38	35
Other Postretirement Benefits [Member] | Level 1 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	14	8
Other Postretirement Benefits [Member] | Level 1 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 1 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 1 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 1 [Member] | Mutual fund - Municipal bonds
Fair values of plan assets
Total assets at fair value	52	46
Other Postretirement Benefits [Member] | Level 2 [Member]
Fair values of plan assets
Total assets at fair value	62	57
Other Postretirement Benefits [Member] | Level 2 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 2 [Member] | Equity Securities
Fair values of plan assets
Total assets at fair value	10	9
Other Postretirement Benefits [Member] | Level 2 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 2 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	4	4
Other Postretirement Benefits [Member] | Level 2 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	3	1
Other Postretirement Benefits [Member] | Level 2 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	45	43
Other Postretirement Benefits [Member] | Level 2 [Member] | Mutual fund - Municipal bonds
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member]
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Equity Securities
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Level 3 [Member] | Mutual fund - Municipal bonds
Fair values of plan assets
Total assets at fair value	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Fair values of plan assets
Total assets at fair value	178	157
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Cash management fund
Fair values of plan assets
Total assets at fair value	12	11
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Equity Securities
Fair values of plan assets
Total assets at fair value	48	44
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - U.S. Treasury securities
Fair values of plan assets
Total assets at fair value	14	8
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Government and municipal bonds
Fair values of plan assets
Total assets at fair value	4	4
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Mortgage and asset-backed securities
Fair values of plan assets
Total assets at fair value	3	1
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fixed income securities - Corporate bonds
Fair values of plan assets
Total assets at fair value	45	43
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Mutual fund - Municipal bonds
Fair values of plan assets
Total assets at fair value	52	46
Other Postretirement Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - U.S. large cap
Fair values of plan assets
Total assets at fair value	18	16
Other Postretirement Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - Global large and mid cap
Fair values of plan assets
Total assets at fair value	16	12
Other Postretirement Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - equities - International emerging markets
Fair values of plan assets
Total assets at fair value	4	3
Other Postretirement Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - fixed income - U.S. long and intermediate duration
Fair values of plan assets
Total assets at fair value	45	46
Other Postretirement Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Commingled investment funds - fixed income - Corporate bonds
Fair values of plan assets
Total assets at fair value	$ 17	$ 13

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EBP Benefit Pymts & Employer Contributions (Details 5) $ in Millions	Dec. 31, 2020 USD ($)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected total plans contribution, approximate	$ 6
Expected benefit payments
2021	14
2022	14
2023	14
2024	13
2025	13
2026-2030	57
Pension Benefits [Member]
Expected benefit payments
2021	96
2022	91
2023	86
2024	82
2025	82
2026-2030	378
Nonqualified Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected total plans contribution, approximate	$ 2

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Property, Plant, and Equipment (Details PPE) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Mar. 18, 2019
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 42,489	$ 41,510
Accumulated depreciation and amortization		(13,560)	(12,310)
Property, plant, and equipment - net		28,929	29,200
Depreciation and amortization expenses		1,393	1,390	$ 1,392
Utica East Ohio Midstream, LLC Acquisition [Member]
Property, Plant, and Equipment
Business Acquisition, Goodwill, Expected Tax Deductible Amount					$ 187
Nonregulated [Member] | Natural gas gathering and processing facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		17,813	17,593
Nonregulated [Member] | Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		289	354
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		2,658	2,519
Regulated [Member] | Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		18,688	18,076
Regulated [Member] | Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		382	586
Regulated [Member] | Acquisition Adjustment Of Regulated Facilities [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Plant Acquisition Adjustments for Intangible Utility Plants		$ 507	547
Period of straight-line amortization		40 years
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 2,659	$ 2,382
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]	2 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, 2020. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

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Property, Plant, and Equipment (Details ARO) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
		Nov. 30, 2020	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligations
Asset Retirement Obligations, Noncurrent			$ 1,159	$ 1,117
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance			1,165	1,032
Liabilities incurred	[1]		37	15
Liabilities settled			(19)	(8)
Accretion expense			65	59
Revisions (1)	[2]		(26)	67
Ending balance			1,222	$ 1,165
Chesapeake Energy Corporation [Member]
Unusual or Infrequent Item [Line Items]
Increase (Decrease) in Asset Retirement Obligations		$ 31
Asset Retirement Obligation Costs [Member]
Unusual or Infrequent Item [Line Items]
Transco's annual funding commitment for ARO			$ 16

[1] As a result of the global resolution with Chesapeake in 2020, we recorded $31 million of ARO related to natural gas properties transferred to us. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

[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 2020 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, decreases in inflation rates, and decreases in the discount rates used in the annual review process. The 2019 revisions reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets, increases in inflation rates, and decreases in the discount rates used in the annual review process.

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Goodwill (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2020	Jun. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Mar. 18, 2020	Mar. 18, 2019	Dec. 31, 2018
Utica East Ohio Midstream, LLC Acquisition [Member]
Goodwill [Line Items]
Goodwill					$ 187	$ 187
Goodwill, Other Increase (Decrease)	$ (1)		$ (1)
West [Member] | Jackalope Gas Gathering Services LLC [Member]
Goodwill [Line Items]
Goodwill, Period Increase (Decrease)		$ 47
Northeast G And P [Member]
Goodwill [Line Items]
Goodwill			0	$ 188			$ 0
Northeast G And P [Member] | Utica East Ohio Midstream, LLC Acquisition [Member]
Goodwill [Line Items]
Goodwill, Period Increase (Decrease)			$ (187)	$ 188

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Other Intangible Assets (Details) - USD ($) $ in Millions		12 Months Ended
	Mar. 18, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross		$ 9,561	$ 9,560
Finite-Lived Intangible Assets, Accumulated Amortization		$ (2,117)	(1,789)
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life		30 years
Amortization of Intangible Assets		$ 328	$ 324	$ 333
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months		328
Finite-Lived Intangible Assets, Amortization Expense, Year Two		328
Finite-Lived Intangible Assets, Amortization Expense, Year Three		328
Finite-Lived Intangible Assets, Amortization Expense, Year Four		328
Finite-Lived Intangible Assets, Amortization Expense, Year Five		$ 328
Utica East Ohio Midstream, LLC Acquisition [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	20 years
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension	10 years

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Accrued Liabilities Table (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Accrued Liabilities [Line Items]
Interest on debt	$ 271	$ 288
Employee costs	149	226
Estimated rate refund liabilities	0	189
Contract liabilities (Note 5)	129	158
Asset retirement obligation (Note 11)	63	48
Other, including accrued loss contingencies	304	346
Other accrued liabilities	944	1,276
Accounts Payable and Accrued Liabilities
Accrued Liabilities [Line Items]
Operating lease liabilities (Note 15)	$ 28	$ 21

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Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2020	Aug. 17, 2020	May 14, 2020	May 08, 2020	Mar. 15, 2020	Dec. 31, 2019
Long-term Debt
Unamortized debt issuance costs	$ (125)					$ (119)
Net unamortized debt premium (discount)	(63)					(58)
Total long-term debt, including current portion	22,344					22,288
Long-term debt due within one year	(893)					(2,140)
Long-term debt	21,451					20,148
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					0
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					0
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	$ 847					857
Transcontinental Gas Pipe Line Company, LLC [Member] | Dalton [Member]
Long-term Debt
Other financing obligations	$ 257					259
Transcontinental Gas Pipe Line Company, LLC [Member] | Financing Obligations Approx Int Rate [Member]
Long-term Debt
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					0
The Williams Companies, Inc. [Member] | 4.125% Senior Unsecured Notes Due 2020 [Member]
Long-term Debt
Long-term debt	$ 0					600
Long-term debt interest rate	4.125%	4.125%
The Williams Companies, Inc. [Member] | 5.25% Senior Unsecured Notes Due 2020 [Member]
Long-term Debt
Long-term debt	$ 0					1,500
Long-term debt interest rate	5.25%				5.25%
The Williams Companies, Inc. [Member] | 4% Senior Unsecured Notes Due 2021 [Member]
Long-term Debt
Long-term debt	$ 500					500
Long-term debt interest rate	4.00%
The Williams Companies, Inc. [Member] | 7.875% Senior Unsecured Notes Due 2021 [Member]
Long-term Debt
Long-term debt	$ 371					371
Long-term debt interest rate	7.875%
The Williams Companies, Inc. [Member] | 3.35% Senior Unsecured Notes Due 2022 [Member]
Long-term Debt
Long-term debt	$ 750					750
Long-term debt interest rate	3.35%
The Williams Companies, Inc. [Member] | 3.6% Senior Unsecured Notes Due 2022 [Member]
Long-term Debt
Long-term debt	$ 1,250					1,250
Long-term debt interest rate	3.60%
The Williams Companies, Inc. [Member] | 3.7% Senior Unsecured Notes Due 2023 [Member]
Long-term Debt
Long-term debt	$ 850					850
Long-term debt interest rate	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					0
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] | Various - 7.7% to 10.25% Senior Unsecured Notes and Debentures Due 2019 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 10.25% Senior Unsecured Notes and Debentures Due 2019 to 2027 Maximum Interest Rate [Member]
Long-term Debt
Long-term debt interest rate	10.25%
The Williams Companies, Inc. [Member] | Various - 7.7 Percent To 10.25 Percent Senior Unsecured Notes And Debentures Due 2019 To 2027 [Member]
Long-term Debt
Long-term debt	$ 3					$ 24

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Long-Term Debt Maturities (Details) $ in Millions	Dec. 31, 2020 USD ($)
Aggregate minimum maturities of long-term debt
2021	$ 894
2022	2,025
2023	1,477
2024	2,280
2025	$ 1,617

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Long-Term Debt Issuances and Retirements (Details) - USD ($) $ in Millions	Aug. 17, 2020	Mar. 15, 2020	Jan. 15, 2020	Jul. 15, 2019	Dec. 31, 2020	May 14, 2020	May 08, 2020	Dec. 31, 2019
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%				4.125%
Long-term debt					$ 0			$ 600
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			0
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%			5.25%
Long-term debt					$ 0			1,500
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%
The Williams Companies, Inc. [Member] | 7.625% Senior Unsecured Notes Due 2019 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount				$ 32
Long-term debt interest rate				7.625%
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			0
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			$ 0

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Credit Facilities and Commercial Paper (Details) $ in Millions	Aug. 10, 2018 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Williams Companies Inc [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 4,500	$ 4,500
Credit facility, loans outstanding		0	$ 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] | SwingLineLoan [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	$ 4,000
Commercial paper, outstanding		0	$ 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	$ 1,000
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		$ 15
Transcontinental Gas Pipe Line Company, LLC [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 500
Maximum ratio of debt to capitalization	65.00%
Northwest Pipeline LLC [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 500
Maximum ratio of debt to capitalization	65.00%
Mar20 And Subsequent Quarters [Member] | Williams Companies Inc [Member]
Credit Facility and Commercial Paper [Line Items]
Maximum ratio of debt to EBITDA	5.0

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Cash Payments For Interest (Net of Amounts Capitalized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
Cash payments for interest (net of amounts capitalized)	$ 1,149	$ 1,153	$ 1,064

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Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Operating Leases, Rent Expense			$ 73
Operating Lease, Cost	$ 37	$ 40
Variable Lease, Cost	19	27
Sublease Income	(1)	(2)
Lease, Cost	55	65
Operating Lease, Payments	30	39
Operating Lease, Right-of-Use Asset	$ 182	$ 207
Operating Lease, Weighted Average Remaining Lease Term	13 years	13 years
Operating Lease, Weighted Average Discount Rate, Percent	4.60%	4.61%
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 34
Lessee, Operating Lease, Liability, Payments, Due Year Two	28
Lessee, Operating Lease, Liability, Payments, Due Year Three	23
Lessee, Operating Lease, Liability, Payments, Due Year Four	19
Lessee, Operating Lease, Liability, Payments, Due Year Five	17
Lessee, Operating Lease, Liability, Payments, Due after Year Five	140
Lessee, Operating Lease, Liability, Payments, Due	261
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	72
Accounts Payable and Accrued Liabilities
Lessee, Lease, Description [Line Items]
Operating Lease, Liability, Current	28	$ 21
Regulatory liabilities, deferred income, and other [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability, Noncurrent	161	$ 188
Other Liabilities
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	$ 189

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Stockholders' Equity Stockholders' Equity (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	12 Months Ended
	Jan. 26, 2021	Jul. 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Mar. 19, 2020
Class of Stock [Line Items]
Common Stock, Dividends, Per Share, Declared			$ 1.60	$ 1.52	$ 1.36
Preferred Stock, Value, Issued			$ 35	$ 35
Series C Preferred Stock [Member]
Class of Stock [Line Items]
Class of Warrant or Right, Number of Securities Called by Each Warrant or Right						0.001
Preferred Stock, Par or Stated Value Per Share						$ 1.00
Series C Preferred Stock [Member] | Dividend Declared [Member]
Class of Stock [Line Items]
Class of Warrant or Right, Outstanding						1
Series B Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share		$ 1
Stock Issued During Period, Shares, New Issues		35,000
Preferred Stock, Value, Issued		$ 35
Preferred Stock, Dividend Rate, Percentage		7.25%
Preferred Stock, Shares Authorized		30,000,000
Subsequent Event [Member]
Class of Stock [Line Items]
Common Stock, Dividends, Per Share, Declared	$ 0.41

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Stockholders' Equity Table of Changes in AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance	$ (199)
Other comprehensive income (loss)	103	$ 71	$ 30
Total, Ending Balance	(96)	(199)
Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance	(2)
Other comprehensive income (loss) before reclassifications	(2)
Amounts reclassified from accumulated other comprehensive income (loss)	1
Other comprehensive income (loss)	(1)
Total, Ending Balance	(3)	(2)
Foreign Currency Translation [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance	(1)
Other comprehensive income (loss) before reclassifications	0
Amounts reclassified from accumulated other comprehensive income (loss)	0
Other comprehensive income (loss)	0
Total, Ending Balance	(1)	(1)
Pension and Other Post Retirement Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance	(196)
Other comprehensive income (loss) before reclassifications	81
Amounts reclassified from accumulated other comprehensive income (loss)	23
Other comprehensive income (loss)	104
Total, Ending Balance	(92)	(196)
Total AOCI Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Total, Beginning Balance	(199)
Other comprehensive income (loss) before reclassifications	79
Amounts reclassified from accumulated other comprehensive income (loss)	24
Other comprehensive income (loss)	103	71	$ 32
Total, Ending Balance	$ (96)	$ (199)

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Stockholders' Equity Stockholders' Equity Reclassifications from AOCI (Details) - Reclassification out of Accumulated Other Comprehensive Income [Member] $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax benefit	$ (7)
Reclassifications during the period	24
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Energy commodity contracts	1
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit)	$ 30

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Equity-Based Compensation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2020		Dec. 31, 2019	Dec. 31, 2018	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		31,000
Shares available for future grants		19,000
Equity-based compensation expense		$ 52		$ 57	$ 54
Tax benefit from equity-based compensation expense		13		$ 14	$ 14
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized [Abstract]
Unrecognized equity-based compensation expense		$ 57
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]
Equity-Based Compensation (Textuals) [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		3 years
Rollforward of nonvested restricted stock unit activity and related information
Restricted Stock Units, Nonvested shares, Beginning Balance		5,400
Restricted Stock Units, Granted		2,800
Restricted Stock Units, Forfeited		(500)
Restricted Stock Units, Vested		(1,500)
Restricted Stock Units, Nonvested shares, Ending Balance		6,200		5,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Restricted Stock Units, Nonvested, Weighted-Average Fair Value, Beginning Balance	[1]	$ 28.11
Weighted-average grant date fair value of restricted stock units granted during the year, per share		18.32	[1]	$ 25.87	$ 30.48
Restricted Stock Units, Forfeited, Weighted-Average Fair Value	[1]	27.90
Restricted Stock Units, Vested, Weighted-Average Fair Value	[1]	29.04
Restricted Stock Units, Nonvested, Weighted-Average Fair Value, Ending Balance	[1]	$ 23.53		$ 28.11
Restricted Stock Units, Vested in Period, Fair Value		$ 43		$ 29	$ 35
Williams Companies Incentive Plan [Member] | Performance Shares [Member]
Rollforward of nonvested restricted stock unit activity and related information
Performance based nonvested restricted stock units as a percent of total nonvested restricted stock units outstanding		41.00%
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 Outstanding, Beginning Balance		6,800
Options, Granted		0
Options, Exercised		(300)
Options, Cancelled		(500)
Options Outstanding, Ending Balance		6,000		6,800
Options Exercisable at Period End		5,700
Options, Aggregate Intrinsic Value, Ending Balance		$ 0
Options, Aggregate Intrinsic Value, Exercisable at Period End		0
Total intrinsic value of options exercised		1		$ 6	3
Tax benefits realized on options exercised		0		1	0
Cash received from the exercise of options		$ 3		$ 4	$ 9
Stock Options Outstanding, Weighted Average Remaining Contractual Life		3 years 6 months
Stock Options Exercisable, Weighted Average Remaining Contractual Life		3 years 3 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Options, Weighted Average Exercise Price, Beginning Balance		$ 32.64
Options, Weighted Average Exercise Price, Granted		0
Options, Weighted Average Exercise Price, Exercised		17.28
Options, Weighted Average Exercise Price, Cancelled		34.04
Options, Weighted Average Exercise Price, Ending Balance		33.18		$ 32.64
Options, Weighted Average Exercise Price, Exercisable at Period End		$ 33.41
Estimated fair value at date of grant of options for common stock granted
Weighted-average grant date fair value of options for our common stock granted during the year, per share					$ 5.49
Weighted-average assumptions:
Dividend yield					4.70%
Volatility					30.10%
Risk-free interest rate					2.70%
Expected life (years)					6 years
Duration Of Base Term For Peer Group Historical Volatility Measurement		10 years
Employee Stock Purchase Plan [Member]
Equity-Based Compensation (Textuals) [Abstract]
Shares authorized for issuance		5,200				1,600
Shares available for future grants		1,700
No. of shares purchases by employees		347
Average price of shares purchased		$ 16.07

[1] Performance-based restricted stock units are valued considering measures of total shareholder return utilizing a Monte Carlo valuation method, as well as return on capital employed and a ratio of debt to EBITDA. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years.

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Fair Value Measurements and Guarantees Recurring Measurements and Additional (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Carrying Amount [Member]
Additional disclosures:
Long-term debt, including current portion	$ (22,344)	$ (22,288)
Guarantees	(40)	(41)
Fair Value [Member]
Additional disclosures:
Long-term debt, including current portion	(27,043)	(25,319)
Guarantees	(27)	(27)
Level 1 [Member]
Additional disclosures:
Long-term debt, including current portion	0	0
Guarantees	0	0
Level 2 [Member]
Additional disclosures:
Long-term debt, including current portion	(27,043)	(25,319)
Guarantees	(11)	(11)
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	235	201
Fair Value, Recurring [Member] | Fair Value [Member]
Measured on a recurring basis
ARO Trust investments	235	201
Fair Value, Recurring [Member] | Level 1 [Member]
Measured on a recurring basis
ARO Trust investments	235	201
Fair Value, Recurring [Member] | Level 2 [Member]
Measured on a recurring basis
ARO Trust investments	0	0
Fair Value, Recurring [Member] | Level 3 [Member]
Measured on a recurring basis
ARO Trust investments	0	$ 0
Wiltel Guarantee [Member]
Additional disclosures:
Guarantor Obligations, Maximum Exposure, Undiscounted	27
Indemnification Agreement [Member] | Carrying Amount [Member]
Additional disclosures:
Guarantees	$ 0

XML

Fair Value Measurements Nonrecurring Measurements (Details) - USD ($) $ in Millions																			1 Months Ended		3 Months Ended				12 Months Ended
		Dec. 31, 2020		Mar. 31, 2020		Dec. 31, 2019		Sep. 30, 2019		Aug. 31, 2019	Jun. 30, 2019	[2]	Mar. 31, 2019	[8]	Mar. 17, 2019	Dec. 31, 2018		Jun. 30, 2018	Mar. 31, 2020		Mar. 31, 2020		Mar. 31, 2019		Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets (Note 18)																									$ 182		$ 464		$ 1,915
Impairment of equity-method investments																									1,046		186		32
Share Price Change																			26.00%		40.00%
Goodwill, Impairment Loss																									187		0		0
Noncontrolling Interests
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets						$ 209
Goodwill, Impairment Loss																					$ 65
Fair Value, Nonrecurring [Member] | Level 2 [Member] | Property, plant, and equipment, net [Member] | Other [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of property, plant, and equipment	[1]																	$ 25
Fair Value, Nonrecurring [Member] | Level 2 [Member] | Assets Held For Sale [Member] | West [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Assets Held-for-sale, Long Lived, Fair Value Disclosure	[2]					25																					25
Fair Value, Nonrecurring [Member] | Level 2 [Member] | Property Plant And Equipment, Net And Intangible Assets, Net Of Accumulated Amortization [Member] | Northeast G And P [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Property Plant And Equipment And Intangibles, Fair Value Disclosure	[3]	$ 5																							5
Fair Value, Nonrecurring [Member] | Level 2 [Member] | Investments [Member] | Northeast G And P [Member] | Pennant Midstream, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[4]									$ 11
Fair Value, Nonrecurring [Member] | Level 2 [Member] | Investments [Member] | Northeast G And P [Member] | Utica East Ohio Midstream, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[5]														$ 1,210
Fair Value, Nonrecurring [Member] | Level 3 [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Goodwill, Impairment Loss																					187
Fair Value, Nonrecurring [Member] | Level 3 [Member] | Property, plant, and equipment, net [Member] | Transmission And Gulf Of Mexico [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of property, plant, and equipment		42	[6]			22	[7]																		42	[6]	22	[7]
Fair Value, Nonrecurring [Member] | Level 3 [Member] | Property, plant, and equipment, net [Member] | West [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of property, plant, and equipment											$ 40		$ 0										$ 0	[8]
Fair Value, Nonrecurring [Member] | Level 3 [Member] | Property Plant And Equipment, Net And Intangible Assets, Net Of Accumulated Amortization [Member] | West [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Property Plant And Equipment And Intangibles, Fair Value Disclosure	[9]															$ 470													470
Fair Value, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Transmission And Gulf Of Mexico [Member] | Discovery Producer Services LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[10]			$ 367															$ 367		367
Fair Value, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | West [Member] | Rocky Mountain Midstream Holdings LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment		421	[11]	557	[12]														557	[12]	557	[12]			421	[11]
Fair Value, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | West [Member] | Brazos Permian II, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[12]			0															0		0
Fair Value, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment				236	[10]			$ 242	[13]										236	[10]	236	[10]
Fair Value, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Utica East Ohio Midstream, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[5]															1,293													1,293
Fair Value, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Caiman Energy II [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[10]			191															191		191
Fair Value, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Aux Sable Liquid Products LP [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[10]			7															$ 7		$ 7
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets (Note 18)																									182		464		1,915
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member] | Level 2 [Member] | West [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets	[2]					20
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member] | Level 2 [Member] | Other [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets	[1]																	$ 66
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member] | Level 2 [Member] | Northeast G And P [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets (Note 18)	[3]	12
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets	[14]																										19
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | Transmission And Gulf Of Mexico [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets		170	[6]			$ 354	[7]
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | West [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets											$ 59		$ 12
Impairment of certain assets (Note 18)	[9]															1,849
Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Level 2 [Member] | Northeast G And P [Member] | Pennant Midstream, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[4]									$ 17
Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Level 2 [Member] | Northeast G And P [Member] | Utica East Ohio Midstream, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[5]														$ 74
Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments																											(1)
Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | Transmission And Gulf Of Mexico [Member] | Discovery Producer Services LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[10]			97
Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | West [Member] | Rocky Mountain Midstream Holdings LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments		$ 108	[11]	243	[12]
Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | West [Member] | Brazos Permian II, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[12]			193
Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments				10	[10]			$ 79	[13]
Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | Northeast G And P [Member] | Utica East Ohio Midstream, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments																$ 32	[5]						$ 74
Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | Northeast G And P [Member] | Caiman Energy II [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[10]			229
Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | Northeast G And P [Member] | Aux Sable Liquid Products LP [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[10]			$ 39
Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments																									$ 1,046		$ 186		$ 32
Measurement Input, Discount Rate [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Property Plant And Equipment And Intangibles Fair Value Inputs																8.50%													8.50%
Measurement Input, Discount Rate [Member] | Laurel Mountain Midstream, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Investments Fair Value Inputs								10.20%
Measurement Input, Discount Rate [Member] | Rocky Mountain Midstream Holdings LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Investments Fair Value Inputs		18.00%		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] | Caiman Energy II And Aux Sable Liquid Products LP [Member] | 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] | Caiman Energy II And Aux Sable Liquid Products LP [Member] | 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] | Caiman Energy II And Aux Sable Liquid Products LP [Member] | 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] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Appalachia Midstream Services, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment				$ 2,700	[10]			$ 102	[15]										$ 2,700	[10]	$ 2,700	[10]
Williams Companies Inc [Member] | Impairment Of Equity-Method Investments [Member] | Fair Value, Nonrecurring [Member] | Level 3 [Member] | Northeast G And P [Member] | Appalachia Midstream Services, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments				$ 127	[10]			$ 17	[15]
Williams Companies Inc [Member] | Measurement Input, Discount Rate [Member] | Appalachia Midstream Services, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Investments Fair Value Inputs								9.00%

[1] Relates to certain idle pipelines. The estimated fair value of the Property, plant, and equipment – net was determined by a market approach incorporating information derived from bids received for these assets, which we marketed for sale together with certain other assets. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. We sold these assets in the fourth quarter of 2018. (See Note 3 – Acquisitions and Divestitures.)

[2] Relates to a gas gathering system in the Eagle Ford Shale region with expected declines in asset utilization and possible idling of the gathering system. We designated these operations as held for sale, included in Other current assets and deferred charges, as of December 31, 2019. As a result, we measured the fair value of the disposal group using the expected sales price under a contract with a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value of the Property, plant, and equipment – net at June 30, 2019, was determined using a market approach, which incorporated indications of interest from third parties.

[3] Relates to a gathering system in the Marcellus Shale region, that is more likely than not to be sold in the short term. 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.

[4] The estimated fair value of Pennant Midstream, LLC (Pennant) was determined by a market approach based on recent observable third-party transactions. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

[5] The estimated fair value at March 17, 2019, was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the acquisition in March 2019 (see Note 3 – Acquisitions and Divestitures). These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value at December 31, 2018, was determined by a market approach based on our analysis of inputs in the principal market.

[6] Relates to capitalized project development costs for the Northeast Supply Enhancement project. As previously disclosed, 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, recent developments in the political and regulatory environments have caused us to slightly lower that assessed probability such that the capitalized project costs now required impairment. The estimated fair value of the materials within the capitalized project costs 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.

[7] Relates to the Constitution proposed pipeline project extending from Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems in New York. Although Constitution received a certificate of public convenience and necessity from the FERC to construct and operate the proposed pipeline and obtained, among other approvals, a waiver of the water quality certification under Section 401 of the Clean Water Act for the New York portion of the project, the members of Constitution, following extensive evaluation and discussion, determined that the underlying risk-adjusted return for this greenfield pipeline project had diminished in such a way that further development was no longer supported. The estimated fair value of the Property, plant, and equipment – net was based on probability-weighted third-party quotes. Our partners’ $209 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations.

[8] Reflects impairment of Property, plant, and equipment – net that is no longer in use for which the fair value was determined to be lower than the carrying value.

[9] Relates to our gathering operations in the Barnett Shale region. Certain of our contractual gathering rates, primarily those in the Barnett Shale region, are based on a percentage of the New York Mercantile Exchange (NYMEX) natural gas prices. During the fourth quarter of 2018, we determined there was a sustained decline in the forward price curves for natural gas. During this same period, a large producer customer in the Barnett Shale region removed their remaining drilling rig. These factors gave rise to an impairment evaluation of these assets, which incorporated management’s projections of future drilling activity and gathering rates, taking into consideration the information previously noted as well as recently available information regarding producer drilling cost assumptions in the basin. The resulting estimate of future undiscounted cash flows was less than our carrying value, necessitating the estimation of the fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization. To arrive at the fair value, we utilized an income approach with a discount rate of 8.5 percent, reflecting an estimated cost of capital and risks associated with the underlying assets.

[10] 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 Caiman II 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 recent market declines previously discussed.

[11] 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

[12] 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 recent market declines previously discussed.

[13] Relates to a gas gathering system in the Marcellus Shale region that was adversely impacted by lower sustained forward natural gas price expectations and changes in expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 10.2 percent in our analysis.

[14] Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value.

[15] Relates to a certain gathering system held in Appalachia Midstream Investments that was adversely impacted by changes in the timing of expected producer activity. The estimated fair value was determined using an income approach. We utilized a discount rate of 9 percent in our analysis.

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Fair Value Measurements Concentration of Credit Risk (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Concentration Risk [Line Items]
Trade accounts and other receivables - net	$ 999	$ 996
NGLs, natural gas, and related products and services [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables - net	638	613
Transportation of natural gas and related products [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables - net	254	277
Accounts Receivable related to revenues from contracts with customers [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables - net	892	890
Other Receivable [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables - net	$ 107	$ 106

XML

Contingent Liabilities and Commitments (Details) - USD ($) $ in Millions		1 Months Ended
	May 20, 2016	Jan. 31, 2020	Dec. 31, 2020
Loss Contingencies [Line Items]
Accrued environmental loss liabilities			$ 33
Capital Addition Purchase Commitments [Member]
Loss Contingencies [Line Items]
Commitments for construction and acquisition of property, plant, and equipment			262
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
Gas Pipeline [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities			4
Natural Gas Underground Storage Facilities [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities			8
Former Operations [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities			$ 21

XML

Segment Disclosures Recon from Segment to Consolidated - Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment revenues [Line Items]
Revenues	$ 7,719	$ 8,201	$ 8,686
Other financial information:
Additions to long-lived assets	1,283	2,911	3,171
Proportional Modified EBITDA Equity Method Investments	749	746	770
Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues	(256)	(280)	(488)
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	3,469	3,640	3,447
Other financial information:
Additions to long-lived assets	706	1,341	2,379
Proportional Modified EBITDA Equity Method Investments	166	177	183
Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues	1,529	1,500	1,283
Other financial information:
Additions to long-lived assets	137	1,245	477
Proportional Modified EBITDA Equity Method Investments	473	454	493
Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues	2,943	3,311	4,410
Other financial information:
Additions to long-lived assets	318	304	279
Proportional Modified EBITDA Equity Method Investments	110	115	94
Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenues	34	30	34
Other financial information:
Additions to long-lived assets	122	21	36
Proportional Modified EBITDA Equity Method Investments	0	0	0
Service [Member]
Segment revenues [Line Items]
Revenues	5,924	5,933	5,502
Service [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues	3,207	3,261	2,904
Service [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues	1,416	1,291	935
Service [Member] | West [Member]
Segment revenues [Line Items]
Revenues	1,280	1,364	1,641
Service [Member] | Other [Member]
Segment revenues [Line Items]
Revenues	21	17	22
Service [Member] | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues	(112)	(110)	(102)
Service [Member] | Intersegment Eliminations [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues	(50)	(50)	(49)
Service [Member] | Intersegment Eliminations [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues	(49)	(47)	(41)
Service [Member] | Intersegment Eliminations [Member] | West [Member]
Segment revenues [Line Items]
Revenues	0	0	0
Service [Member] | Intersegment Eliminations [Member] | Other [Member]
Segment revenues [Line Items]
Revenues	(13)	(13)	(12)
Service [Member] | Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues	3,257	3,311	2,953
Service [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues	1,465	1,338	976
Service [Member] | Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues	1,280	1,364	1,641
Service [Member] | Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenues	34	30	34
NonRegulated Service Commodity Consideration [Member]
Segment revenues [Line Items]
Revenues	129	203	400
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	21	41	59
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues	7	12	20
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues	101	150	321
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	1,666	2,065	2,784
Product [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues	144	217	174
Product [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues	16	115	245
Product [Member] | West [Member]
Segment revenues [Line Items]
Revenues	1,506	1,733	2,365
Product [Member] | Other [Member]
Segment revenues [Line Items]
Revenues	0	0	0
Product [Member] | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues	(144)	(170)	(386)
Product [Member] | Intersegment Eliminations [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues	(47)	(71)	(261)
Product [Member] | Intersegment Eliminations [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues	(41)	(35)	(42)
Product [Member] | Intersegment Eliminations [Member] | West [Member]
Segment revenues [Line Items]
Revenues	(56)	(64)	(83)
Product [Member] | Intersegment Eliminations [Member] | Other [Member]
Segment revenues [Line Items]
Revenues	0	0	0
Product [Member] | Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues	191	288	435
Product [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues	57	150	287
Product [Member] | Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues	1,562	1,797	2,448
Product [Member] | Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenues	$ 0	$ 0	$ 0

XML

Segment Disclosures Recon from Modified EBITDA to Net Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	$ 4,851	$ 4,447	$ 3,388
Accretion expense associated with asset retirement obligations for nonregulated operations	(35)	(33)	(33)
Depreciation and amortization expenses	(1,721)	(1,714)	(1,725)
Impairment of goodwill (Note 18)	(187)	0	0
Equity earnings (losses) (Note 7)	328	375	396
Impairment of equity-method investments (Note 18)	(1,046)	(186)	(32)
Other investing income (loss) – net (Note 7)	8	107	219
Proportional Modified EBITDA Equity Method Investments	(749)	(746)	(770)
Interest Expense	(1,172)	(1,186)	(1,112)
(Provision) benefit for income taxes	(79)	(335)	(138)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	0	(15)	0
Net income (loss)	198	714	193
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	2,379	2,175	2,293
Proportional Modified EBITDA Equity Method Investments	(166)	(177)	(183)
Operating Segments [Member] | Northeast G And P [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	1,489	1,314	1,086
Proportional Modified EBITDA Equity Method Investments	(473)	(454)	(493)
Operating Segments [Member] | West [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	998	952	38
Proportional Modified EBITDA Equity Method Investments	(110)	(115)	(94)
Operating Segments [Member] | Other [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	(15)	6	(29)
Proportional Modified EBITDA Equity Method Investments	$ 0	$ 0	$ 0

XML

Segment Disclosures Recon from Segment to Consolidated - Assets and Investments (Details) - USD ($) $ in Millions		Dec. 31, 2020	Dec. 31, 2019
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		$ 44,165	$ 46,040
Equity-method investments		5,159	6,235
Transmission And Gulf Of Mexico [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		19,110	18,796
Northeast G And P [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		14,569	15,399
West [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		10,558	11,265
Other [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets		927	1,151
Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Equity-method investments		610	741
Operating Segments [Member] | Northeast G And P [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Equity-method investments		3,682	3,973
Operating Segments [Member] | West [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Equity-method investments		867	1,521
Operating Segments [Member] | Other [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Equity-method investments		0	0
Intersegment Eliminations [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	[1]	(999)	(571)
Equity-method investments		$ 0	$ 0

[1] Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program.

XML

Subsequent Event (Details) $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Feb. 01, 2021 wells
Subsequent Event [Line Items]
Payments to Acquire Productive Assets		$ 1,283	$ 2,911	$ 3,171
Subsequent Event [Member]
Subsequent Event [Line Items]
Gas, Productive Well, Number of Wells, Gross | wells					2,000
Payments to Acquire Productive Assets	$ 79

XML

Schedule II Valuation and Qualifying Accounts (Details) - Deferred Tax Asset Valuation Allowance [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Valuation And Qualifying Accounts
Beginning Balance	[1]	$ 319	$ 320	$ 224
Additions Charged (Credited) To Cost and Expenses		6	(1)	96
Additions Other		0	0	0
Deductions		0	0	0
Ending Balance	[1]	$ 325	$ 319	$ 320

[1] Deducted from related assets.