The Williams Companies, Inc. (WMB) 10-K 27 Feb 23 2022 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2022	Feb. 17, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-4174
Entity Registrant Name	Williams Companies, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	73-0569878
Entity Address, Address Line One	One Williams Center
Entity Address, City or Town	Tulsa
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	74172
City Area Code	800
Local Phone Number	945-5426
Title of 12(b) Security	Common Stock, $1.00 par value
Trading Symbol	WMB
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
DocumentFinStmtErrorCorrectionFlag	false
Entity Shell Company	false
Entity Public Float			$ 36,889,420,649
Entity Common Stock, Shares Outstanding		1,218,562,959
Documents Incorporated by Reference [Text Block]	Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s Annual Meeting of Stockholders to be held on April 25, 2023, are incorporated into Part III, as specifically set forth in Part III.
Entity Central Index Key	0000107263
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP
Auditor Location	Tulsa, Oklahoma
Auditor Firm ID	42

Consolidated Statement of Incom

Consolidated Statement of Income - USD ($) shares in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Revenues		$ 10,965	$ 10,627	$ 7,719
Costs and expenses:
Operating and maintenance expenses		1,817	1,548	1,326
Depreciation and amortization expenses		2,009	1,842	1,721
Selling, general, and administrative expenses		636	558	466
Impairment of certain assets (Note 15)		0	2	182
Impairment of goodwill (Note 15)		0	0	187
Other (income) expense – net		28	14	22
Total costs and expenses		7,947	7,996	5,517
Operating income (loss)		3,018	2,631	2,202
Equity earnings (losses) (Note 8)		637	608	328
Impairment of equity-method investments (Note 15)		0	0	(1,046)
Other investing income (loss) – net		16	7	8
Interest incurred		(1,167)	(1,190)	(1,192)
Interest capitalized		20	11	20
Other income (expense) – net		18	6	(43)
Income (loss) before income taxes		2,542	2,073	277
Less: Provision (benefit) for income taxes		425	511	79
Net income (loss)		2,117	1,562	198
Less: Net income (loss) attributable to noncontrolling interests		68	45	(13)
Amounts attributable to The Williams Companies, Inc. available to common stockholders:
Net income (loss) attributable to The Williams Companies, Inc.		2,049	1,517	211
Less: Preferred stock dividends		3	3	3
Net income (loss) available to common stockholders		$ 2,046	$ 1,514	$ 208
Basic earnings (loss) per common share:
Net income (loss)		$ 1.68	$ 1.25	$ 0.17
Weighted-average shares (thousands)		1,218,362	1,215,221	1,213,631
Diluted earnings (loss) per common share:
Net income (loss)		$ 1.67	$ 1.24	$ 0.17
Weighted-average shares (thousands)		1,222,672	1,218,215	1,215,165
Service [Member]
Revenues:
Revenues		$ 6,536	$ 6,001	$ 5,924
NonRegulated Service Commodity Consideration [Member]
Revenues:
Revenues		260	238	129
Product [Member]
Revenues:
Revenues		4,556	4,536	1,671
Energy Commodities and Service
Revenues:
Revenues	[1]	(387)	(148)	(5)
Oil and Gas, Purchased [Member]
Costs and expenses:
Cost of Goods and Service, Excluding Depreciation, Depletion, and Amortization		3,369	3,931	1,545
Natural Gas Purchased For Shrink [Member]
Costs and expenses:
Cost of Goods and Service, Excluding Depreciation, Depletion, and Amortization		$ 88	$ 101	$ 68
[1]We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.

Consolidated Statement of Compr

Consolidated Statement of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Comprehensive income (loss):
Net income (loss)	$ 2,117	$ 1,562	$ 198
Designated cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $1, $14, and $— in 2022, 2021, and 2020, respectively	(3)	(40)	(2)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $—, ($14), and $— in 2022, 2021, and 2020, respectively	0	41	1
Pension and other postretirement benefits:
Net actuarial gain (loss) arising during the year, net of taxes of $1, ($18), and ($27) in 2022, 2021, and 2020, respectively	1	51	81
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($4), ($4), and ($7) in 2022, 2021, and 2020, respectively	11	11	23
Other comprehensive income (loss)	9	63	103
Comprehensive income (loss)	2,126	1,625	301
Less: Comprehensive income (loss) attributable to noncontrolling interests	68	45	(13)
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$ 2,058	$ 1,580	$ 314

Consolidated Statement of Com_2

Consolidated Statement of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flow hedging activities:
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, Tax	$ 1	$ 14	$ 0
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	0	(14)	0
Pension and other postretirement benefits:
Other Comprehensive Income (Loss), Defined Benefit Plan, Net Actuarial Gain (Loss) Arising During Period, Tax	1	(18)	(27)
Other Comprehensive Income Loss, Reclassification Pension And Other Postretirement Benefit Plans Net Gain Loss Included In Net Periodic Benefit Cost (Credit), Tax	$ (4)	$ (4)	$ (7)

Consolidated Balance Sheet

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 152	$ 1,680
Trade accounts and other receivables	2,729	1,986
Allowance for doubtful accounts	(6)	(8)
Trade accounts and other receivables – net	2,723	1,978
Inventories	320	379
Derivative assets	323	301
Other current assets and deferred charges	279	211
Total current assets	3,797	4,549
Investments	5,065	5,127
Property, plant, and equipment – net	30,889	29,258
Intangible assets – net of accumulated amortization	7,363	7,402
Regulatory assets, deferred charges, and other	1,319	1,276
Total assets	48,433	47,612
Current liabilities:
Accounts payable	2,327	1,746
Derivative Liability, Current	316	166
Accrued and other current liabilities	1,270	1,035
Commercial Paper	350	0
Long-term debt due within one year	627	2,025
Total current liabilities	4,890	4,972
Long-term debt	21,927	21,650
Deferred income tax liabilities	2,887	2,453
Regulatory liabilities, deferred income, and other	4,684	4,436
Contingent liabilities and commitments (Note 17)
Stockholders’ equity:
Preferred stock ($1 par value; 30 million shares authorized at December 31, 2022 and December 31, 2021; 35,000 shares issued at December 31, 2022 and December 31, 2021)	35	35
Common stock ($1 par value; 1,470 million shares authorized at December 31, 2022 and December 31, 2021; 1,253 million shares issued at December 31, 2022 and 1,250 million shares issued at December 31, 2021)	1,253	1,250
Capital in excess of par value	24,542	24,449
Retained deficit	(13,271)	(13,237)
Accumulated other comprehensive income (loss)	(24)	(33)
Treasury stock, at cost (35 million shares of common stock)	(1,050)	(1,041)
Total stockholders’ equity	11,485	11,423
Noncontrolling interests in consolidated subsidiaries	2,560	2,678
Total equity	14,045	14,101
Total liabilities and equity	$ 48,433	$ 47,612

Consolidated Balance Sheet (Par

Consolidated Balance Sheet (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
Common Stock, Par or Stated Value Per Share	$ 1	$ 1
Common Stock, Shares Authorized	1,470,000,000	1,470,000,000
Common Stock, Shares, Issued	1,253,000,000	1,250,000,000
Treasury Stock, Shares	35,000,000	35,000,000
Series B Preferred Stock [Member]
Preferred Stock, Par or Stated Value Per Share	$ 1	$ 1
Preferred Stock, Shares Authorized	30,000,000	30,000,000
Preferred Stock, Shares Issued	35,000	35,000

Consolidated Statement of Chang

Consolidated Statement of Changes in Equity - USD ($) $ in Millions	Total	Preferred Stock	Common Stock	Capital in Excess of Par Value	Retained Deficit	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Total Stockholders' Equity	Noncontrolling Interests
Beginning balance at Dec. 31, 2019	$ 16,364	$ 35	$ 1,247	$ 24,323	$ (11,002)	$ (199)	$ (1,041)	$ 13,363	$ 3,001
Net income (loss)	198	0	0	0	211	0	0	211	(13)
Other comprehensive income (loss)	103	0	0	0	0	103	0	103	0
Dividends, Common Stock, Cash	(1,941)	0	0	0	(1,941)	0	0	(1,941)	0
Dividends and distributions to noncontrolling interests	(185)	0	0	0	0	0	0	0	(185)
Stock-based compensation and related common stock issuances, net of tax	51	0	1	50	0	0	0	51	0
Contributions from noncontrolling interests	7	0	0	0	0	0	0	0	7
Other	(14)	0	0	(2)	(16)	0	0	(18)	4
Net increase (decrease) in equity	(1,781)	0	1	48	(1,746)	103	0	(1,594)	(187)
Ending balance at Dec. 31, 2020	14,583	35	1,248	24,371	(12,748)	(96)	(1,041)	11,769	2,814
Net income (loss)	1,562	0	0	0	1,517	0	0	1,517	45
Other comprehensive income (loss)	63	0	0	0	0	63	0	63	0
Dividends, Common Stock, Cash	(1,992)	0	0	0	(1,992)	0	0	(1,992)	0
Dividends and distributions to noncontrolling interests	(187)	0	0	0	0	0	0	0	(187)
Stock-based compensation and related common stock issuances, net of tax	80	0	2	78	0	0	0	80	0
Contributions from noncontrolling interests	9	0	0	0	0	0	0	0	9
Purchase of partial interest in consolidated subsidiary (Note 8)	(3)	0	0	0	0	0	0	0	(3)
Purchase of treasury stock	0
Other	(14)	0	0	0	(14)	0	0	(14)	0
Net increase (decrease) in equity	(482)	0	2	78	(489)	63	0	(346)	(136)
Ending balance at Dec. 31, 2021	14,101	35	1,250	24,449	(13,237)	(33)	(1,041)	11,423	2,678
Net income (loss)	2,117	0	0	0	2,049	0	0	2,049	68
Other comprehensive income (loss)	9	0	0	0	0	9	0	9	0
Dividends, Common Stock, Cash	(2,071)	0	0	0	(2,071)	0	0	(2,071)	0
Dividends and distributions to noncontrolling interests	(204)	0	0	0	0	0	0	0	(204)
Stock-based compensation and related common stock issuances, net of tax	96	0	3	93	0	0	0	96	0
Contributions from noncontrolling interests	18	0	0	0	0	0	0	0	18
Purchase of treasury stock	(9)	0	0	0	0	0	(9)	(9)	0
Other	(12)	0	0	0	(12)	0	0	(12)	0
Net increase (decrease) in equity	(56)	0	3	93	(34)	9	(9)	62	(118)
Ending balance at Dec. 31, 2022	$ 14,045	$ 35	$ 1,253	$ 24,542	$ (13,271)	$ (24)	$ (1,050)	$ 11,485	$ 2,560

Consolidated Statement of Cha_2

Consolidated Statement of Changes in Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Stockholders' Equity [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 1.70	$ 1.64	$ 1.60

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
OPERATING ACTIVITIES:
Net income (loss)	$ 2,117	$ 1,562	$ 198
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	2,009	1,842	1,721
Provision (benefit) for deferred income taxes	431	509	108
Equity (earnings) losses	(637)	(608)	(328)
Distributions from equity-method investees (Note 8)	865	757	653
Impairment of goodwill (Note 15)	0	0	187
Impairment of equity-method investments (Note 15)	0	0	1,046
Impairment of certain assets (Note 15)	0	2	182
Net unrealized (gain) loss from derivative instruments	249	109	0
Inventory write-downs	161	15	17
Amortization of stock-based awards	73	81	52
Cash provided (used) by changes in current assets and liabilities:
Accounts receivable	(733)	(545)	(2)
Inventories	(110)	(139)	(28)
Other current assets and deferred charges	(33)	(63)	11
Accounts payable	410	643	(7)
Accrued and other current liabilities	209	58	(309)
Changes in current and noncurrent derivative assets and liabilities	94	(277)	(4)
Other, including changes in noncurrent assets and liabilities	(216)	(1)	(1)
Net cash provided (used) by operating activities	4,889	3,945	3,496
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	345	0	0
Proceeds from long-term debt	1,755	2,155	3,899
Payments of long-term debt	(2,876)	(894)	(3,841)
Proceeds from issuance of common stock	54	9	9
Common dividends paid	(2,071)	(1,992)	(1,941)
Dividends and distributions paid to noncontrolling interests	(204)	(187)	(185)
Contributions from noncontrolling interests	18	9	7
Payments for debt issuance costs	(17)	(26)	(20)
Other – net	(46)	(16)	(13)
Net cash provided (used) by financing activities	(3,042)	(942)	(2,085)
INVESTING ACTIVITIES:
Capital expenditures (1)	(2,253)	(1,239)	(1,239)
Dispositions – net	(30)	(8)	(36)
Contributions in aid of construction	12	52	37
Purchases of businesses, net of cash acquired (Note 3)	(933)	(151)	0
Purchases of and contributions to equity-method investments (Note 8)	(166)	(115)	(325)
Other – net	(5)	(4)	5
Net cash provided (used) by investing activities	(3,375)	(1,465)	(1,558)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect, Total	(1,528)	1,538	(147)
Cash and cash equivalents at beginning of year	1,680	142	289
Cash and cash equivalents at end of year	152	1,680	142
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
(1) Increases to property, plant, and equipment	(2,394)	(1,305)	(1,160)
Changes in related accounts payable and accrued liabilities	141	66	(79)
Capital expenditures	$ (2,253)	$ (1,239)	$ (1,239)

General, Description of Busines

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies [Text Block]	Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies General Unless the context clearly indicates otherwise, references in this report to “Williams,” “we,” “our,” “us,” or like terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references to “Williams,” “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations. Share Repurchase Program In September 2021, our Board of Directors authorized a share repurchase program with a maximum dollar limit of $1.5 billion. Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions, or in such other manner as determined by our management. Our management will also determine the timing and amount of any repurchases based on market conditions and other factors. The share repurchase program does not obligate us to acquire any particular amount of common stock, and it may be suspended or discontinued at any time. This share repurchase program does not have an expiration date. There were $9 million and no repurchases under the program in 2022 and 2021, respectively. Description of Business We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United States and are presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities, including our upstream operations, as well as corporate activities are included in Other. Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), and their related natural gas storage facilities, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated variable interest entity, or VIE), a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery). Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas. Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 50 percent equity-method investment in Blue Racer Midstream LLC (Blue Racer), and Appalachia Midstream Services, LLC, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region (Appalachia Midstream Investments). West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of east Texas and northwest Louisiana, and the Mid-Continent region which includes the Anadarko and Permian basins. This segment also includes our NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in Overland Pass Pipeline Company LLC (OPPL), a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC (RMM), a 20 percent equity-method investment in Targa Train 7 LLC (Targa Train 7) (a nonconsolidated VIE), and a 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II) (a nonconsolidated VIE). Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations, which includes risk management and transactions related to the storage and transportation of natural gas and natural gas liquids (NGLs) on strategically positioned assets. Basis of Presentation Discontinued operations Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations. Significant risks and uncertainties We believe that the carrying value of certain of our property, plant, and equipment and intangible assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess of current fair value. However, the carrying value of these assets, in our judgment, continues to be recoverable. It is reasonably possible that future strategic decisions, including transactions such as monetizing assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities, could impact our assumptions and ultimately result in impairments of these assets. Such transactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could result in impairment. Summary of Significant Accounting Policies Principles of consolidation The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Our judgment is required to evaluate whether we control an entity. Key areas of that evaluation include: • Determining whether an entity is a VIE (see Note 2 – Variable Interest Entities); • Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests; • Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary; • Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities. We apply the equity method of accounting to investments over which we exercise significant influence but do not control. Distributions received from equity-method investees are presented in our Consolidated Statement of Cash Flows according to the nature of the distributions approach, which classifies distributions received from equity-method investees as either returns on investment (cash inflows from operating activities) or returns of investment (cash inflows from investing activities) based on the nature of the activities of the equity-method investee that generated the distribution. Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Significant estimates and assumptions include: • Impairment assessments of investments, property, plant, and equipment, and intangible assets; • Litigation-related contingencies; • Environmental remediation obligations; • Depreciation and/or amortization of long-lived assets, which are comprised of property, plant, and equipment, and intangible assets; • Depreciation and/or amortization of equity-method investment basis differences; • Asset retirement obligations (AROs); • Measurement of fair value of derivatives; • Pension and postretirement valuation variables; • Measurement of regulatory liabilities; • Measurement of deferred income tax assets and liabilities, including assumptions related to the realization of deferred income tax assets; • Revenue recognition, including estimates utilized in recognition of deferred revenue; • Purchase price accounting. These estimates are discussed further throughout these notes. Regulatory accounting Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC), and their rates are established by the FERC. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates. Management’s expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. We record certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refunded in future rates. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, AROs, shipper imbalance activity, fuel and power cost differentials, depreciation, negative salvage, pension and other postretirement benefits, customer tax refunds, and rate allowances for deferred income taxes at a historically higher federal income tax rate. Our current and noncurrent regulatory asset and liability balances at December 31, 2022 and 2021 are as follows: December 31, 2022 2021 (Millions) Current assets reported within Other current assets and deferred charges $ 138 $ 111 Noncurrent assets reported within Regulatory assets, deferred charges, and other 459 415 Total regulated assets $ 597 $ 526 Current liabilities reported within Accrued and other current liabilities $ 201 $ 56 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,233 1,324 Total regulated liabilities $ 1,434 $ 1,380 Revenue recognition Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users. Service revenue contracts from our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer. Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipeline businesses and are not within the scope of ASC Topic 606, “Revenue from Contracts with Customers”. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset, which are referred to as Contributions in aid of construction in our Consolidated Statement of Cash Flows. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied. Service Revenues Gas pipeline businesses: Revenues from our regulated interstate natural gas pipeline businesses, which are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a daily or monthly reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one-month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following: • Firm transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities; • Interruptible transportation or storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities. In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation. We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks. Midstream businesses: Revenues from our non-regulated gathering, processing, transportation, and storage midstream businesses include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ natural gas and NGLs, generally under prepaid contracted storage capacity contracts. In situations where, in our judgment, we provide an integrated package of services combined into a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available. We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer. We generally earn a contractually stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our contracts, we allocate the transaction price to each performance obligation based on the judgmentally determined relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology as these methods appropriately match the consumption of services provided to the customer. The units of production methodology requires the use of production estimates that are uncertain and the use of judgment when developing estimates of future production volumes, thus impacting the rate of revenue recognition. Production estimates are monitored as circumstances and events warrant. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude, based on management’s judgment, it is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period. Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized in our Consolidated Statement of Income both at the time the processing service is provided in Service revenues – commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product sales . The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale. Product Sales In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances. In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers which we remarket. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We also market natural gas and NGLs from the production at our upstream properties. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction. We purchase natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future, resulting in positive net product sales. Commodity-based exchange-traded futures contracts and over-the-counter (OTC) contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. The physical purchase, transportation, storage, and sale of natural gas are accounted for on a weighted-average cost or accrual basis, as appropriate, unlike the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized in our Consolidated Statement of Income in the period they are incurred. As we are acting as an agent for our natural gas marketing customers and engage in energy trading activities, our natural gas marketing revenues are presented net of the related costs of those activities. Prior to the 2022 integration of our legacy gas marketing operations with the acquired Sequent Acquisition operations (see Note 3 – Acquisitions), our legacy gas marketing operations were reported on a gross basis. Contract Assets Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within Other current assets and deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer. Contract Liabilities Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings and transactions for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within Accrued and other current liabilities and Regulatory liabilities, deferred income, and other , respectively, in our Consolidated Balance Sheet. Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined, in our judgment, that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract. Derivative instruments and hedging activities We are exposed to commodity price risk. We utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We purchase natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. Commodity-based exchange-traded futures contracts and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between receipt and delivery points occurs. Some commodity-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the natural gas marketing operations. These contracts generally meet the definition of derivatives and are typically not designated as hedges for accounting purposes. When a commodity-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed, and the contract price is recognized in the respective line item in our Consolidated Statement of Income representing the actual price of the underlying goods being delivered. Unrealized gains and losses on physically settled commodity-related derivative contracts for commodity sales transactions are recognized in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income. Realized and unrealized gains and losses on non-designated commodity-related derivative contracts for commodity sales transactions that are financially settled are reported in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income. Net gains and losses on derivatives for shrink gas purchases for processing plants are reported in Net processing commodity expenses in our Consolidated Statement of Income. We experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio as well as upstream related production. However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying production or transportation and storage contracts, which is not recognized until the underlying transaction occurs. (See Note 16 – Derivatives.) We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Derivative assets; Regulatory assets, deferred charges, and other; Derivative liabilities ; or Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. These amounts are presented on a net basis and reflect the netting of asset and liability positions permitted under the terms of master netting arrangements and cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The accounting for the changes in fair value of a commodity derivative can be summarized as follows: Derivative Treatment Accounting Method Normal purchases and normal sales exception Accrual accounting Designated in a qualifying hedging relationship Hedge accounting All other derivatives Mark-to-market accounting We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected in our Consolidated Balance Sheet after the initial election of the exception. We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting chan

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2022
Variable Interest Entity Disclosures [Abstract]
Variable Interest Entities [Text Block]	Note 2 – Variable Interest Entities Consolidated VIEs As of December 31, 2022, we consolidate the following VIEs: Northeast JV We own a 65 percent interest in the Northeast JV, a subsidiary that is a VIE due to certain of our voting rights being disproportionate to our obligation to absorb losses and substantially all of the Northeast JV’s activities being performed on our behalf. We are the primary beneficiary because we have the power to direct the activities that most significantly impact the Northeast JV’s economic performance. The Northeast JV provides midstream services for producers in the Marcellus Shale and Utica Shale regions. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis. Gulfstar One We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines that provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance. Cardinal We own a 66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner. The following table presents amounts included in the Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs: December 31, 2022 2021 (Millions) Assets (liabilities): Cash and cash equivalents $ 49 $ 78 Trade accounts and other receivables – net 136 132 Inventories 4 3 Other current assets and deferred charges 7 7 Property, plant, and equipment – net 5,154 5,295 Intangible assets – net of accumulated amortization 2,158 2,267 Regulatory assets, deferred charges, and other 29 20 Accounts payable (76) (61) Accrued and other current liabilities (34) (29) Regulatory liabilities, deferred income, and other (275) (287) Nonconsolidated VIEs Targa Train 7 We own a 20 percent interest in Targa Train 7, which provides fractionation services at Mont Belvieu, Texas, and is a VIE due primarily to our limited participating rights as the minority equity holder. At December 31, 2022, the carrying value of our investment in Targa Train 7 was $46 million. Our maximum exposure to loss is limited to the carrying value of our investment. Brazos Permian II We own a 15 percent interest in Brazos Permian II, which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder. At December 31, 2022, the carrying value of our investment in Brazos Permian II was $16 million. Our maximum exposure to loss is limited to the carrying value of our investment.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2022
Business Combinations [Abstract]
Acquisitions [Text Block]	Note 3 – Acquisitions Trace Acquisition On April 29, 2022, we closed on the acquisition of 100 percent of Gemini Arklatex, LLC through which we acquired the Haynesville Shale region gas gathering and related assets of Trace Midstream (Trace) for $972 million of cash funded with cash on hand and proceeds from issuance of commercial paper (Trace Acquisition). The purpose of the Trace Acquisition was to expand our footprint into the east Texas area of the Haynesville Shale region, increasing in-basin scale in one of the largest growth basins in the country. During the period from the acquisition date of April 29, 2022 to December 31, 2022, the operations acquired in the Trace Acquisition contributed Revenues of $148 million and Modified EBITDA (as defined in Note 18 – Segment Disclosures) of $73 million. Acquisition-related costs for the Trace Acquisition for the period from the acquisition date of April 29, 2022 to December 31, 2022 of $8 million are reported within our West segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income. We accounted for the Trace Acquisition as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values. The valuation techniques used consisted of the income approach (excess earnings method) for valuation of intangible assets and depreciated replacement costs for property, plant, and equipment. The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the West segment, and liabilities assumed at April 29, 2022. The fair value of accounts receivable acquired equals contractual amounts receivable. (Millions) Cash and cash equivalents $ 39 Trade accounts and other receivables – net 18 Property, plant, and equipment – net 448 Intangible assets – net of accumulated amortization 472 Other noncurrent assets 20 Total assets acquired $ 997 Accounts payable $ 12 Accrued and other current liabilities 5 Other noncurrent liabilities 8 Total liabilities assumed $ 25 Net assets acquired $ 972 Intangible assets Intangible assets recognized in the Trace Acquisition are related to contractual customer relationships from gas gathering agreements with our customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over an initial period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 2 percent of the expected future revenues from these contractual customer relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the existing contractual customer relationships is approximately 19 years. See Note 10 – Intangible Assets. Sequent Acquisition On July 1, 2021, we closed on the acquisition of 100 percent of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp (Sequent Acquisition). Total consideration for this acquisition was $159 million, which included $109 million related to working capital. Operations acquired in the Sequent Acquisition focus on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas and electric utilities, municipalities, power generators, and producers, as well as moving gas to markets through transportation and storage agreements on strategically positioned assets, including our Transco system. The purpose of the Sequent Acquisition was to expand our natural gas marketing activities as well as optimize our pipeline and storage capabilities with expansions into new markets to reach incremental gas-fired power generation, liquified natural gas exports, and future renewable natural gas and other emerging opportunities. During the period from the acquisition date of July 1, 2021 to December 31, 2021, results for the operations acquired in the Sequent Acquisition included net Product sales of $(43) million (including $80 million of purchases from affiliates), Net gain (loss) on commodity derivatives of $(43) million, and unfavorable Modified EBITDA of $112 million. Both the Revenues and Modified EBITDA amounts reflect a net unrealized loss on commodity derivatives in Net gain (loss) on commodity derivatives of $(109) million for the period. Acquisition-related costs for the Sequent Acquisition for the period from the acquisition date of July 1, 2021 to December 31, 2021 of $5 million are reported within our Gas & NGL Marketing Services segment and were included in Selling, general, and administrative expenses in our Consolidated Statement of Income for the year ended December 31, 2021. We accounted for the Sequent Acquisition as a business combination. The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Gas & NGL Marketing Services segment, and liabilities assumed at July 1, 2021. The fair value of accounts receivable acquired equals contractual amounts receivable. The fair value of the intangible assets was measured using an income approach. The fair value of the inventory acquired was based on the market price of the natural gas in underground storage at the acquisition date. See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for the valuation techniques used to measure fair value of derivative assets and liabilities. (Millions) Cash and cash equivalents $ 8 Trade accounts and other receivables – net 498 Inventories 121 Derivative assets 57 Other current assets and deferred charges 4 Property, plant, and equipment – net 5 Intangible assets – net of accumulated amortization 306 Other noncurrent assets 3 Commodity derivatives included in other noncurrent assets 49 Total assets acquired $ 1,051 Accounts payable $ 514 Derivative liabilities 116 Accrued and other current liabilities 46 Other noncurrent liabilities 1 Commodity derivatives included in other noncurrent liabilities 215 Total liabilities assumed $ 892 Net assets acquired $ 159 Accounts receivable and accounts payable The operations acquired in the Sequent Acquisition provide services to retail and wholesale gas marketers, utility companies, upstream producers, and industrial customers. See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for our policy regarding netting receivables and payables. Intangible assets Intangible assets are primarily related to transportation and storage capacity contracts. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired transportation and storage capacity contracts that provide future economic benefits due to their market location, discounted using an industry weighted-average cost of capital. This intangible asset is being amortized based on the expected benefit period over which the underlying contracts are expected to contribute to our cash flows ranging from 1 year to 8 years. As a result, we expect a significant portion of the amortization to be recognized within the first few years of this range. See Note 10 – Intangible Assets. Commodity derivatives We are exposed to commodity price risk. To manage this volatility, we use various contracts in our marketing and trading activities that generally meet the definition of derivatives. We enter into commodity-related derivatives to economically hedge exposures to natural gas and retain exposure to price changes that can, in a volatile energy market, be material and can adversely affect our results of operations; see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for our accounting policy for derivatives. Supplemental Pro Forma The following pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. in 2022, 2021, and 2020, are presented as if the Trace Acquisition had been completed on January 1, 2021, and the Sequent Acquisition had been completed on January 1, 2020. These pro forma amounts are not necessarily indicative of what the actual results would have been if the Trace Acquisition and Sequent Acquisition had in fact occurred on the dates or for the periods indicated, nor do they purport to project Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements. Year Ended December 31, 2022 As Reported Pro Forma Trace (1) Pro Forma Combined (Millions) Revenues $ 10,965 $ 45 $ 11,010 Net income (loss) attributable to The Williams Companies, Inc. 2,049 18 2,067 Year Ended December 31, 2021 As Reported Pro Forma Trace Pro Forma Sequent (2) Pro Forma Combined (Millions) Revenues $ 10,627 $ 118 $ 188 $ 10,933 Net income (loss) attributable to The Williams Companies, Inc. 1,517 42 4 1,563 Year Ended December 31, 2020 As Reported Pro Forma Sequent Pro Forma Combined (Millions) Revenues $ 7,719 $ 74 $ 7,793 Net income (loss) attributable to The Williams Companies, Inc. 211 (13) 198 (1) Excludes results from operations acquired in the Trace Acquisition for the period beginning on the acquisition date of April 29, 2022, as these results are included in the amounts as reported. (2) Excludes results from operations acquired in the Sequent Acquisition for the period beginning on the acquisition date of July 1, 2021, as these results are included in the amounts as reported. NorTex Asset Purchase On August 31, 2022, we purchased a group of assets in north Texas, primarily natural gas storage facilities and pipelines, from NorTex Midstream Holdings, LLC (NorTex Asset Purchase) for approximately $424 million. These assets are included in the Transmission & Gulf of Mexico segment.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Related Party Transactions [Text Block]	Note 4 – Related Party Transactions Transactions with Equity-Method Investees We have expenses associated with our equity-method investees of $1.346 billion, $948 million, and $348 million for 2022, 2021, and 2020, respectively in our Consolidated Statement of Income. Substantially all of these expenses are included in Product costs . We also have revenue from our equity-method investees of $76 million, $46 million, and $26 million for 2022, 2021, and 2020, respectively. In addition, w e have $17 million and $9 million included in Accounts receivable and $87 million and $89 million included in Accounts payable in our Consolidated Balance Sheet with our equity-method investees at December 31, 2022 and 2021, respectively. We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. The total charges to equity-method investees for these fees are $65 million, $70 million, and $79 million for 2022, 2021, and 2020, respectively. Board of Directors Two members of our Board of Directors are also executive officers at certain of our counterparties. We recorded $180 million in Product sales and $86 million in Product costs in our Consolidated Statement of Income from these companies for the purchase and sale of natural gas for 2022.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2022
Revenue Recognition [Abstract]
Revenue Recognition [Text Block]	Note 5 – Revenue Recognition Revenue by Category The following table presents our revenue disaggregated by major service line: Transco Northwest Pipeline Gulf of Mexico Midstream and Storage Northeast West Midstream Gas & NGL Marketing Services Other Eliminations Total (Millions) 2022 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 2,696 $ 443 $ — $ — $ — $ — $ — $ (72) $ 3,067 Gathering, processing, transportation, fractionation, and storage: Monetary consideration — — 365 1,395 1,476 — — (164) 3,072 Commodity consideration — — 64 14 182 — — — 260 Other 10 — 27 233 54 3 — (19) 308 Total service revenues 2,706 443 456 1,642 1,712 3 — (255) 6,707 Product sales 179 — 251 134 841 10,768 706 (1,813) 11,066 Total revenues from contracts with customers 2,885 443 707 1,776 2,553 10,771 706 (2,068) 17,773 Other revenues (1) 24 4 10 26 8 7,929 (55) (11) 7,935 Other adjustments (2) — — — — — (15,467) — 724 (14,743) Total revenues $ 2,909 $ 447 $ 717 $ 1,802 $ 2,561 $ 3,233 $ 651 $ (1,355) $ 10,965 2021 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 2,547 $ 441 $ — $ — $ — $ — $ — $ (33) $ 2,955 Gathering, processing, transportation, fractionation, and storage: Monetary consideration — — 344 1,308 1,184 — — (130) 2,706 Commodity consideration — — 52 7 179 — — — 238 Other 10 — 22 195 52 3 1 (19) 264 Total service revenues 2,557 441 418 1,510 1,415 3 1 (182) 6,163 Product sales 88 — 269 99 643 6,404 333 (1,215) 6,621 Total revenues from contracts with customers 2,645 441 687 1,609 2,058 6,407 334 (1,397) 12,784 Other revenues (1) 10 3 8 25 (32) 2,632 11 (13) 2,644 Other adjustments (2) — — — — — (4,828) — 27 (4,801) Total revenues $ 2,655 $ 444 $ 695 $ 1,634 $ 2,026 $ 4,211 $ 345 $ (1,383) $ 10,627 Transco Northwest Pipeline Gulf of Mexico Midstream and Storage Northeast West Midstream Gas & NGL Marketing Services Other Eliminations Total (Millions) 2020 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 2,404 $ 449 $ — $ — $ — $ — $ — $ (7) $ 2,846 Gathering, processing, transportation, fractionation, and storage: Monetary consideration — — 348 1,279 1,226 — — (97) 2,756 Commodity consideration — — 21 7 101 — — — 129 Other 10 — 27 164 35 32 1 (16) 253 Total service revenues 2,414 449 396 1,450 1,362 32 1 (120) 5,984 Product sales 80 — 114 57 152 1,602 — (336) 1,669 Total revenues from contracts with customers 2,494 449 510 1,507 1,514 1,634 1 (456) 7,653 Other revenues (1) 10 — 9 22 9 (3) 33 (14) 66 Total revenues $ 2,504 $ 449 $ 519 $ 1,529 $ 1,523 $ 1,631 $ 34 $ (470) $ 7,719 ______________________________ (1) Revenues not derived from contracts with customers primarily consist of physical product sales related to derivative contracts, realized and unrealized gains and losses associated with our derivative contracts, which are reported in Net gain (loss) on commodity derivatives in the Consolidated Statement of Income, management fees that we receive for certain services we provide to operated equity-method investments, and leasing revenues associated with our headquarters building. (2) Other adjustments reflect certain costs of Gas & NGL Marketing Services’ risk management activities. As we are acting as agent for natural gas marketing customers or engage in energy trading activities, the resulting revenues are presented net of the related costs of those activities in the Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). Contract Assets The following table presents a reconciliation of our contract assets: Year Ended December 31, 2022 2021 (Millions) Balance at beginning of year $ 22 $ 12 Revenue recognized in excess of amounts invoiced 208 184 Minimum volume commitments invoiced (201) (174) Balance at end of year $ 29 $ 22 Contract Liabilities The following table presents a reconciliation of our contract liabilities: Year Ended December 31, 2022 2021 (Millions) Balance at beginning of year $ 1,126 $ 1,209 Payments received and deferred 180 116 Significant financing component 9 10 Contract liability acquired 2 1 Recognized in revenue (274) (210) Balance at end of year $ 1,043 $ 1,126 Remaining Performance Obligations Remaining performance obligations primarily include reservation charges on contracted capacity for our gas pipeline firm transportation contracts with customers, storage capacity contracts, long-term contracts containing minimum volume commitments associated with our midstream businesses, and fixed payments associated with offshore production handling. For our interstate natural gas pipeline businesses, remaining performance obligations reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes are not currently known. Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient for consideration recognized in revenue as billed. Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of December 31, 2022, do not consider potential future performance obligations for which the renewal has not been exercised and exclude contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to December 31, 2022, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities. The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2022. Contract Liabilities Remaining Performance Obligations (Millions) 2023 (one year) $ 142 $ 3,643 2024 (one year) 122 3,388 2025 (one year) 117 3,149 2026 (one year) 112 2,520 2027 (one year) 101 2,415 Thereafter 449 14,675 Total $ 1,043 $ 29,790

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes [Text Block]	Note 6 – Provision (Benefit) for Income Taxes The Provision (benefit) for income taxes includes: Year Ended December 31, 2022 2021 2020 (Millions) Current: Federal $ (25) $ (1) $ (29) State 19 3 — (6) 2 (29) Deferred: Federal 424 421 98 State 7 88 10 431 509 108 Provision (benefit) for income taxes $ 425 $ 511 $ 79 Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows: Year Ended December 31, 2022 2021 2020 (Millions) Provision (benefit) at statutory rate $ 534 $ 435 $ 58 Increases (decreases) in taxes resulting from: State income taxes (net of federal benefit) 113 71 6 State deferred income tax rate change (92) — — Federal valuation allowance (70) 3 1 Federal settlements (45) — — Impact of nontaxable noncontrolling interests (14) (9) 3 Other – net (1) 11 11 Provision (benefit) for income taxes $ 425 $ 511 $ 79 Income (loss) before income taxes includes less than $1 million of foreign income in 2022, and $2 million and $1 million of foreign loss in 2021 and 2020, respectively. The State deferred income tax rate change benefit of $92 million is related to a decrease in our estimate of the deferred state income tax rate (net of federal effect) driven primarily by the enacted decline in the Pennsylvania state income tax rate over the next several years. During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we apply the two-step process of recognition and measurement. In association with this liability, we record an estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual is included within Other – net in our reconciliation of the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes . Significant components of Deferred income tax liabilities are as follows: December 31, 2022 2021 (Millions) Gross deferred income tax liabilities: Property, plant and equipment $ 3,171 $ 2,777 Investments 1,784 1,669 Other 138 154 Total gross deferred income tax liabilities 5,093 4,600 Gross deferred income tax assets: Accrued liabilities 1,108 872 Foreign tax credits 91 140 Federal loss carryovers 730 879 State losses and credits 356 421 Other 121 132 Total gross deferred income tax assets 2,406 2,444 Less valuation allowance 200 297 Net deferred income tax assets 2,206 2,147 Deferred income tax liabilities $ 2,887 $ 2,453 The valuation allowance at December 31, 2022 and 2021 serves to reduce the available deferred income tax assets to an amount that will, more likely than not, be realized. We considered all available positive and negative evidence, which incorporates available tax planning strategies, and management’s estimate of future reversals of existing taxable temporary differences, and have determined that a portion of our deferred income tax assets related to the Foreign tax credits and State losses and credits may not be realized. In 2022, we released $70 million of valuation allowance upon determining we expect to utilize additional foreign tax credits prior to expiration between 2024 and 2025. The amounts presented in the table above are, with respect to state items, before any federal benefit. The change from prior year for the State losses and credits reflects increases in losses and credits generated in the current and prior years less losses and/or credits utilized in the current year. We have loss and credit carryovers in multiple state taxing jurisdictions. These attributes generally expire between 2023 and 2041 with some carryovers having indefinite carryforward periods. Federal loss carryovers at the end of 2022 include deferred tax assets on net operating loss carryovers of $705 million with no expiration date. Deferred tax assets on charitable contributions of $25 million are expected to be utilized by us prior to expiring between 2023 and 2027. Cash payments for income taxes (net of refunds) were $13 million in 2022. Cash refunds for income taxes (net of payments) were $45 million and $40 million in 2021 and 2020, respectively. During the second quarter of 2022, we finalized settlements for 2011 through 2014 on certain contested matters with the Internal Revenue Service (IRS) that resulted in a 2022 year-to-date tax benefit of approximately $45 million. In 2022, we received cash refunds related to these settlements totaling $7 million. We recognize related interest and penalties as a component of Provision (benefit) for income taxes . Total interest and penalties recognized as part of income tax provision were benefits of $3 million in 2022 and $1 million in each of 2021 and 2020. There are no interest or penalties relating to uncertain tax positions accrued as of December 31, 2022 and $4 million of interest was accrued as of December 31, 2021. Consolidated U.S. Federal income tax returns are open to IRS examination for years after 2017. As of December 31, 2022, examination of 2018 is currently in process, with the statute extended to September 30, 2023. We do not expect material changes in our financial position resulting from this examination. The statute of limitations for most states expires one year after expiration of the IRS statute.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2022
Retirement Benefits [Abstract]
Employee Benefit Plans [Text Block]	Note 7 – Employee Benefit Plans Pension Plans We have noncontributory defined benefit pension plans for eligible employees hired prior to January 1, 2019. Eligible employees earn compensation credits based on a cash balance formula. As of January 1, 2020, certain active employees are no longer eligible to receive compensation credits. Other Postretirement Benefits We provide subsidized retiree medical benefits to a closed group of participants as well as retiree life insurance benefits to eligible participants. Medical benefits for Medicare eligible participants are paid through contributions to health reimbursement accounts. Benefits for all other participants are provided through a self-insured medical plan, which includes participant contributions and contains other cost-sharing features such as deductibles, co-payments, and co-insurance. Defined Contribution Plan We have a defined contribution plan for the benefit of substantially all employees. Plan participants may contribute a portion of their compensation on a pre-tax or after-tax basis. Generally, we match employee contributions up to 6 percent of eligible compensation. Additionally, eligible active employees that do not receive compensation credits under the defined benefit pension plan are eligible for an additional annual fixed-percentage contribution made by us to the defined contribution plan. Our contributions charged to expense were $53 million in 2022, $45 million in 2021, and $42 million in 2020. Funded Status The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated: Pension Benefits Other 2022 2021 2022 2021 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 1,133 $ 1,183 $ 200 $ 220 Service cost 28 30 1 1 Interest cost 31 28 6 5 Plan participants’ contributions — — 2 2 Benefits paid (78) (83) (12) (14) Net actuarial loss (gain) (1) (162) (21) (45) (14) Settlements (12) (4) — — Net increase (decrease) in benefit obligation (193) (50) (48) (20) Benefit obligation at end of year 940 1,133 152 200 Change in plan assets: Fair value of plan assets at beginning of year 1,336 1,357 287 278 Actual return on plan assets (132) 62 (27) 16 Employer contributions 3 4 3 5 Plan participants’ contributions — — 2 2 Benefits paid (78) (83) (12) (14) Settlements (12) (4) — — Net increase (decrease) in fair value of plan assets (219) (21) (34) 9 Fair value of plan assets at end of year 1,117 1,336 253 287 Funded status — overfunded (underfunded) $ 177 $ 203 $ 101 $ 87 Amounts recognized in the Consolidated Balance Sheet: Noncurrent assets $ 201 $ 229 $ 105 $ 91 Current liabilities (2) (3) (4) (4) Noncurrent liabilities (22) (23) — — Funded status — overfunded (underfunded) $ 177 $ 203 $ 101 $ 87 Accumulated benefit obligation $ 930 $ 1,118 ____________ (1) 2022 amounts are due primarily to the following factors: Pension benefits - discount rate assumptions, partially offset by change in interest crediting rate assumption; Other Postretirement Benefits - discount rate assumption. 2021 amounts are due primarily to the following factors: Pension Benefits - discount rate assumptions, partially offset by experience-related items; Other Postretirement Benefits - discount rate assumption and experience-related items. The following table summarizes information for pension plans with obligations in excess of plan assets at December 31. 2022 2021 (Millions) Projected benefit obligation $ 24 $ 26 Accumulated benefit obligation 22 22 Fair value of plan assets — — Pre-tax amounts recognized in Accumulated other comprehensive income (loss) at December 31 are as follows: Pension Benefits Other 2022 2021 2022 2021 (Millions) Net actuarial gain (loss) $ (45) $ (46) $ 18 $ 4 Additionally, as of December 31, 2022 and 2021, we have $130 million and $150 million, respectively, of pension and other postretirement plan amounts included in regulatory liabilities associated with our gas pipeline companies. Net Periodic Benefit Cost (Credit) Net periodic benefit cost (credit) for the years ended December 31 consist of the following: Pension Benefits Other 2022 2021 2020 2022 2021 2020 (Millions) Components of net periodic benefit cost (credit): Service cost $ 28 $ 30 $ 31 $ 1 $ 1 $ 1 Interest cost 31 28 36 6 5 7 Expected return on plan assets (44) (43) (53) (10) (10) (11) Amortization of net actuarial loss 12 14 21 — — — Net actuarial loss from settlements 3 1 9 — — — Reclassification to regulatory liability — — — 1 2 2 Net periodic benefit cost (credit) (1) $ 30 $ 30 $ 44 $ (2) $ (2) $ (1) ____________ (1) Components other than Service cost are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income . Items Recognized in Other Comprehensive Income (Loss) Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes for the years ended December 31 consist of the following: Pension Benefits Other 2022 2021 2020 2022 2021 2020 (Millions) Net actuarial gain (loss) arising during the year $ (14) $ 40 $ 112 $ 14 $ 29 $ (4) Amortization of net actuarial loss 12 14 21 — — — Net actuarial loss from settlements 3 1 9 — — — Total recognized in Other comprehensive income (loss) $ 1 $ 55 $ 142 $ 14 $ 29 $ (4) Key Assumptions The weighted-average assumptions utilized to determine benefit obligations and Net periodic benefit cost (credit) as of December 31 are as follows: Pension Benefits Other 2022 2021 2020 2022 2021 2020 Benefit obligations: Discount rate 5.16 % 2.82 % 2.45 % 5.20 % 2.93 % 2.59 % Rate of compensation increase 3.58 3.67 3.76 N/A N/A N/A Cash balance interest crediting rate 3.50 3.00 3.00 N/A N/A N/A Net periodic benefit cost (credit): Discount rate 2.84 % 2.45 % 3.08 % 2.93 % 2.59 % 3.27 % Expected long-term rate of return on plan assets 3.81 3.69 4.67 3.67 3.61 4.39 Rate of compensation increase 3.67 3.76 3.68 N/A N/A N/A Cash balance interest crediting rate 3.00 3.00 3.50 N/A N/A N/A We use mortality tables issued by the Society of Actuaries to measure the benefit obligations. The assumed health care cost trend rate for 2023 is 6.8 percent. This rate decreases to 4.5 percent by 2032. Plan Assets The plans’ investment objectives include a framework to manage the volatility of the plans’ funded status and minimize future cash contributions. The plans follow a policy of diversifying the investments across various asset classes, strategies, and investment managers. The investment policy for the pension plans includes target asset allocation percentages as well as permitted and prohibited investments designed to mitigate risks associated with investing. The December 31, 2022, target asset allocation was 25 percent equity securities and 75 percent fixed income securities, including investments in equity and fixed income mutual funds, commingled investment funds, and separate accounts. The fair values of our pension and other postretirement benefits plan assets by asset class at December 31 are as follows: 2022 Pension Benefits Other Postretirement Benefits Level 1 (1) Level 2 (2) Total Level 1 (1) Level 2 (2) Total (Millions) Cash management funds $ 45 $ — $ 45 $ 105 $ — $ 105 Government debt securities 58 18 76 8 3 11 Corporate debt securities — 284 284 — 39 39 Other 1 4 5 — — — $ 104 $ 306 410 $ 113 $ 42 155 Commingled investment funds (3): Equities 273 38 Fixed income 434 60 Total assets at fair value $ 1,117 $ 253 2021 Pension Benefits Other Postretirement Benefits Level 1 (1) Level 2 (2) Total Level 1 (1) Level 2 (2) Total (Millions) Cash management funds $ 37 $ — $ 37 $ 14 $ — $ 14 Equity securities 42 19 61 39 10 49 Government debt securities 99 28 127 13 4 17 Corporate debt securities — 350 350 — 47 47 Mutual fund - Municipal bonds — — — 59 — 59 Other (3) 2 (1) (1) — (1) $ 175 $ 399 574 $ 124 $ 61 185 Commingled investment funds (3): Equities 288 39 Fixed income 474 63 Total assets at fair value $ 1,336 $ 287 ____________ (1) Level 1 includes assets with fair values based on quoted prices in active markets for identical assets. Cash management funds, equity securities traded on U.S. exchanges, U.S. Treasury securities, and mutual funds are included in this level. (2) Level 2 includes assets with fair values determined by using significant other observable inputs. This level includes equity securities traded on active foreign exchanges and fixed income securities, other than U.S. Treasury securities, that are valued primarily using pricing models which incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads. (3) The commingled investment funds are measured at fair value using net asset value per share. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 1 day to 15 days. Plan Benefit Payments and Employer Contributions Following are the expected benefit payments, which reflect the same assumptions previously discussed and future service as appropriate. Pension Other (Millions) 2023 $ 84 $ 13 2024 83 13 2025 84 12 2026 81 12 2027 80 11 2028-2032 389 52 In 2023, we expect to contribute approximately $1 million to our pension plans and approximately $4 million to our other postretirement benefit plan.

Investing Activities

Investing Activities	12 Months Ended
	Dec. 31, 2022
Investments [Abstract]
Investing Activities [Text Block]	Note 8 – Investing Activities Investments Ownership Interest at December 31, 2022 December 31, 2022 2021 (Millions) Equity method: Appalachia Midstream Investments (1) $ 2,975 $ 3,056 RMM 50% 395 401 OPPL 50% 386 388 Blue Racer 50% 383 377 Discovery 60% 345 328 Gulfstream 50% 220 215 Laurel Mountain 69% 205 226 Other Various 139 130 5,048 5,121 Other 17 6 $ 5,065 $ 5,127 ___________ (1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale region with an approximate average 66 percent interest. Basis differential The carrying value of our Appalachia Midstream Investments exceeds our portion of the underlying net assets by approximately $1.1 billion and $1.2 billion at December 31, 2022 and 2021, respectively. These differences were assigned at the acquisition date to property, plant, and equipment and customer relationship intangible assets. Certain of our other equity-method investments have a carrying value less than our portion of the underlying equity in the net assets primarily due to other than temporary impairments that we have recognized but that were not required to be recognized in the investees’ financial statements. These differences total approximately $1.1 billion and $1.2 billion at December 31, 2022 and 2021, respectively, and were assigned to property, plant, and equipment and customer relationship intangible assets. Differences in the carrying value of our equity-method investments and our portion of the equity in the underlying net assets are generally amortized over the remaining useful lives of the associated underlying assets and included in Equity earnings (losses) within our Consolidated Statement of Income. Purchases of and contributions to equity-method investments We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included: Year Ended December 31, 2022 2021 2020 (Millions) Appalachia Midstream Investments $ 83 $ 84 $ 116 Discovery 41 — — Cardinal Pipeline Company, LLC 16 — — Gulfstream 14 26 3 Blue Racer (1) — 3 157 Other 12 2 49 $ 166 $ 115 $ 325 ___________ (1) See following discussion in the section Acquisition of additional interests in BRMH below. Acquisition of additional interests in BRMH As of December 31, 2019, we effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent interest in Blue Racer Midstream Holdings, LLC (BRMH), whose primary asset is a 50 percent interest in Blue Racer. In November 2020, we paid $157 million, net of cash acquired, to acquire an additional 41 percent ownership interest in BRMH before acquiring the remaining interest of BRMH in September 2021. As such, we control and consolidate BRMH, reporting the 50 percent interest in Blue Racer as an equity-method investment. Since substantially all of the fair value of the BRMH assets acquired is concentrated in a single asset, the investment in Blue Racer, and we previously held a noncontrolling interest in BRMH, we recorded the November 2020 and September 2021 additional purchases of interests as asset acquisitions. Prior to November 2021 BRMH was named Caiman Energy II, LLC and was accounted for as an equity-method investment. Dividends and distributions The organizational documents of entities in which we have an equity-method investment generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included: Year Ended December 31, 2022 2021 2020 (Millions) Appalachia Midstream Investments $ 415 $ 433 $ 357 Laurel Mountain 112 33 31 Gulfstream 89 90 93 RMM 52 45 39 Blue Racer (1) 49 47 47 Discovery 49 44 21 OPPL 34 26 50 Other 65 39 15 $ 865 $ 757 $ 653 ___________ (1) See previous discussion in the section Acquisition of additional interests in BRMH above. Equity Earnings (Losses) Equity earnings (losses) in 2020 includes a $78 million loss associated with the first-quarter full impairment of goodwill recognized by our investee RMM, which was allocated entirely to our member interest per the terms of the membership agreement. Also included in 2020 are losses of $11 million, $26 million, and $10 million for our share of asset impairments at Laurel Mountain, Appalachia Midstream Investments, and Blue Racer, respectively. Impairments of Equity-Method Investments See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for information regarding impairments of our equity-method investments of $1,046 million for 2020. Summarized Financial Position and Results of Operations of All Equity-Method Investments December 31, 2022 2021 (Millions) Assets (liabilities): Current assets $ 964 $ 743 Noncurrent assets 12,701 13,211 Current liabilities (632) (435) Noncurrent liabilities (3,789) (3,774) Year Ended December 31, 2022 2021 2020 (Millions) Gross revenue $ 5,520 $ 4,688 $ 2,625 Operating income 1,268 1,191 508 Net income 1,102 1,006 459

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, Plant, and Equipment [Text Block]	Note 9 – Property, Plant, and Equipment The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the Consolidated Balance Sheet for the years ended: Estimated Depreciation December 31, 2022 2021 (Millions) Nonregulated: Natural gas gathering and processing facilities 5 - 40 $ 19,163 $ 18,203 Construction in progress Not applicable 997 331 Oil and gas properties Units of production 874 572 Other 0 - 45 2,998 2,649 Regulated: Natural gas transmission facilities 1.25 - 7.13 19,521 19,201 Construction in progress Not applicable Not applicable 708 475 Other 5 - 45 0.00 - 33.33 2,796 2,753 Total property, plant, and equipment, at cost 47,057 44,184 Accumulated depreciation and amortization (16,168) (14,926) Property, plant, and equipment — net $ 30,889 $ 29,258 __________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2022. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC. Depreciation and amortization expense for Property, plant, and equipment – net was $1.498 billion, $1.496 billion, and $1.393 billion in 2022, 2021, and 2020, respectively. Regulated Property, plant, and equipment – net includes approximately $428 million and $468 million at December 31, 2022 and 2021, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction. Asset Retirement Obligations Our accrued obligations primarily relate to offshore platforms and pipelines, oil and gas properties, gas transmission pipelines and facilities, underground storage caverns, gas processing, fractionation, and compression facilities, and gas gathering well connections and pipelines. At the end of the useful life of each respective asset, we are legally obligated to dismantle offshore platforms and appropriately abandon offshore pipelines, to remove certain components of gas transmission facilities from the ground, to restore land and remove surface equipment at gas processing, fractionation, and compression facilities, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, to plug storage caverns and remove any related surface equipment, and to plug producing wells and remove any related surface equipment. The following table presents the significant changes to our ARO, of which $1.827 billion and $1.590 billion are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued and other current liabilities at December 31, 2022 and 2021, respectively. Year Ended December 31, 2022 2021 (Millions) Balance at beginning of year $ 1,665 $ 1,222 Liabilities incurred (1) 77 336 Liabilities settled (22) (25) Accretion 85 73 Revisions (2) 109 59 Balance at end of year $ 1,914 $ 1,665 ___________ (1) Includes $307 million of ARO in 2021 related to acquired upstream properties. (2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2022 revisions reflect changes in removal cost estimates and increases in inflation rates, partially offset by increases in discount rates. The 2021 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and increases in inflation rates. The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Under its current rate settlement, Transco’s annual funding obligation is approximately $16 million, with installments to be deposited monthly.

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets [Text Block]	Note 10 – Intangible Assets The gross carrying amount and accumulated amortization of intangible assets, included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, at December 31 are as follows: 2022 2021 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Customer relationships $ 10,065 $ (2,801) $ 9,593 $ (2,448) Transportation and storage capacity contracts 267 (172) 267 (14) Other intangible assets 6 (2) 6 (2) $ 10,338 $ (2,975) $ 9,866 $ (2,464) Customer Relationships Customer relationships primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in acquisitions. Contractual customer relationships are being amortized on a straight-line basis over a period of 30 years for most acquisitions, which represents a portion of the term over which the contractual customer relationships are expected to contribute to our cash flows. We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Although a significant portion of the expected future cash flows associated with these contractual customer relationships are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investment required. The amortization expense related to customer relationships was $353 million, $332 million, and $328 million in 2022, 2021, and 2020, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $357 million. Transportation and Storage Capacity Contracts Certain transportation and storage capacity contracts were recognized as intangible assets as part of the Sequent Acquisition. (See Note 3 – Acquisitions.) The amortization expense related to transportation and storage capacity contracts was $158 million in 2022 and $14 million in 2021. The estimated amortization expense for each of the next five succeeding fiscal years is $51 million, $21 million, $10 million, $7 million, and $4 million.

Accrued and Other Current Liabi

Accrued and Other Current Liabilities	12 Months Ended
	Dec. 31, 2022
Accrued Liabilities, Current [Abstract]
Accrued and Other Current Liabilities [Text Block]	Note 11 – Accrued and Other Current Liabilities December 31, 2022 2021 (Millions) Interest on debt $ 274 $ 277 Employee costs 218 214 Regulatory liabilities (Note 1) 201 56 Contract liabilities 141 134 Asset retirement obligations (Note 9) 87 75 Operating lease liabilities (Note 13) 25 23 Other, including accrued loss contingencies 324 256 $ 1,270 $ 1,035

Debt and Banking Arrangements

Debt and Banking Arrangements	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Debt and Banking Arrangements [Text Block]	Note 12 – Debt and Banking Arrangements Long-Term Debt December 31, 2022 2021 (Millions) Transco: 7.08% Debentures due 2026 $ 8 $ 8 7.25% Debentures due 2026 200 200 7.85% Notes due 2026 1,000 1,000 4% Notes due 2028 400 400 3.25% Notes due 2030 700 700 5.4% Notes due 2041 375 375 4.45% Notes due 2042 400 400 4.6% Notes due 2048 600 600 3.95% Notes due 2050 500 500 Other financing obligation — Atlantic Sunrise 809 830 Other financing obligation — Leidy South 77 72 Other financing obligation — Dalton 252 254 Northwest Pipeline: 7.125% Debentures due 2025 85 85 4% Notes due 2027 500 500 Williams: 3.35% Notes due 2022 — 750 3.6% Notes due 2022 — 1,250 3.7% Notes due 2023 — 850 4.5% Notes due 2023 600 600 4.3% Notes due 2024 1,000 1,000 4.55% Notes due 2024 1,250 1,250 3.9% Notes due 2025 750 750 4% Notes due 2025 750 750 3.75% Notes due 2027 1,450 1,450 3.5% Notes due 2030 1,000 1,000 2.6% Notes due 2031 1,500 1,500 7.5% Debentures due 2031 339 339 7.75% Notes due 2031 252 252 8.75% Notes due 2032 445 445 4.65% Notes due 2032 1,000 — 6.3% Notes due 2040 1,250 1,250 5.8% Notes due 2043 400 400 5.4% Notes due 2044 500 500 5.75% Notes due 2044 650 650 4.9% Notes due 2045 500 500 5.1% Notes due 2045 1,000 1,000 4.85% Notes due 2048 800 800 3.5% Notes due 2051 650 650 5.3% Notes due 2052 750 — Various — 7.7% to 8.72% Notes due 2022 to 2027 2 2 Unamortized debt issuance costs (135) (131) Net unamortized debt premium (discount) (55) (56) Total long-term debt, including current portion 22,554 23,675 Long-term debt due within one year (627) (2,025) Long-term debt $ 21,927 $ 21,650 Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, and incur additional debt. Default of these agreements could also restrict our ability to make certain distributions or repurchase equity. The following table presents aggregate minimum maturities of long-term debt and other financing obligations, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years: December 31, 2022 (Millions) 2023 $ 629 2024 2,281 2025 1,619 2026 1,245 2027 1,993 Issuances and retirements On October 17, 2022, we early retired $850 million of 3.7 percent senior unsecured notes due January 15, 2023. On August 8, 2022, we issued $1.0 billion of 4.65 percent senior unsecured notes due August 15, 2032, and $750 million of 5.30 percent senior unsecured notes due August 15, 2052. On May 16, 2022, we early retired $750 million of 3.35 percent senior unsecured notes due August 15, 2022. On January 18, 2022, we early retired $1.25 billion of 3.6 percent senior unsecured notes due March 15, 2022. On October 8, 2021, we completed a public offering of $600 million of 2.6 percent senior unsecured notes due 2031. The new 2031 notes are an additional issuance of the $900 million of 2.6 percent senior unsecured notes due 2031 issued on March 2, 2021, and will trade interchangeably with such notes. Also, on October 8, 2021, we completed a public offering of $650 million of 3.5 percent senior unsecured notes due 2051. We retired $371 million of 7.875 percent senior unsecured notes that matured on September 1, 2021. On August 16, 2021, we early retired $500 million of 4.0 percent senior unsecured notes due November 15, 2021. On August 17, 2020, we early retired $600 million of 4.125 percent senior unsecured notes due November 15, 2020. On May 14, 2020, we completed a public offering of $1 billion of 3.5 percent senior unsecured notes due 2030. On May 8, 2020, Transco issued $700 million of 3.25 percent senior unsecured notes due 2030 and $500 million of 3.95 percent senior unsecured notes due 2050 to investors in a private debt placement. In the fourth quarter of 2020, Transco filed a registration statement and completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended. We retired $1.5 billion of 5.25 percent senior unsecured notes that matured on March 15, 2020. We retired $14 million of 8.75 percent senior unsecured notes that matured on January 15, 2020. Other financing obligations During the construction of the Atlantic Sunrise, Leidy South, and Dalton projects, Transco received funding from co-owners for their proportionate share of construction costs. Amounts received were recorded within noncurrent liabilities and the costs associated with construction were capitalized in the Consolidated Balance Sheet. Upon placing these projects into service Transco began utilizing the co-owners’ undivided interest in the assets, including the associated pipeline capacity, and reclassified the funding previously received from its co-owners from noncurrent liabilities to debt. The obligations, which mature in 2038, 2041, and 2052, respectively, require monthly interest and principal payments and bear interest rates of approximately 9 percent, 13 percent, and 9 percent, respectively. Credit Facility December 31, 2022 Stated Capacity Outstanding (Millions) Long-term credit facility (1) $ 3,750 $ — Letters of credit under certain bilateral bank agreements 30 ________________ (1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. Revolving credit facility In October 2021, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into an amended and restated credit agreement (Credit Agreement) that reduced aggregate commitments available from $4.5 billion to $3.75 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The Credit Agreement was effective on October 8, 2021. The maturity date of the credit facility is October 8, 2026. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one-year period to allow a maturity date as late as October 8, 2028, under certain circumstances. The Credit Agreement allows for swing line loans up to an aggregate of $200 million, subject to available capacity under the credit facility, and letters of credit commitments of $500 million. Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. The Credit Agreement contains the following terms and conditions: • Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets in certain circumstances, make certain distributions during an event of default, and each borrower and each borrower’s respective material subsidiaries’ ability to enter into certain restrictive agreements. • If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of the loans of the defaulting borrower under the credit facility and exercise other rights and remedies. • Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to an alternative base rate as defined in the Credit Agreement plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin is determined by reference to a pricing schedule based on the applicable borrower’s senior unsecured long-term debt ratings and the commitment fee is determined by reference to a pricing schedule based on Williams’ senior unsecured long-term debt ratings. The Credit Agreement also includes customary provisions to provide for replacement of LIBOR with an alternative benchmark rate when LIBOR ceases to be available. Significant financial covenants under the Credit Agreement require the ratio of debt to EBITDA (earnings before interest, taxes, depreciation, and amortization), each as defined in the Credit Agreement, to be no greater than 5.0 to 1.0, except that for any fiscal quarter in which the funding of the purchase price for an acquisition (whether effectuated as one or a series of related transactions) with an aggregate purchase price of $25 million or more has been effected, and the following two fiscal quarters (in each case subject to certain limitations), the ratio of debt to EBITDA is to be no greater than 5.5 to 1. The ratio of debt to capitalization (defined as net worth plus debt), each as defined in the Credit Agreement, must be no greater than 65 percent for each of Transco and Northwest Pipeline. At December 31, 2022, we are in compliance with these covenants. Commercial Paper Program In 2018, we entered into a $4 billion commercial paper program that has been reduced to $3.5 billion in connection with the October 2021 Credit Agreement. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The net proceeds of issuances of the commercial paper notes are expected to be used to fund planned capital expenditures and for other general corporate purposes. At December 31, 2022, $350 million of commercial paper was outstanding at a weighted-average interest rate of 4.8 percent. We had no commercial paper outstanding at December 31, 2021. Cash Payments for Interest (Net of Amounts Capitalized) Cash payments for interest (net of amounts capitalized) were $1.117 billion in 2022, $1.137 billion in 2021, and $1.149 billion in 2020.

Leases

Leases	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Leases [Text Block]	Note 13 – Leases We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions. Year Ended December 31, 2022 2021 2020 (Millions) Lease Cost: Operating lease cost $ 34 $ 35 $ 37 Variable lease cost 26 15 19 Sublease income — (1) (1) Total lease cost $ 60 $ 49 $ 55 Cash paid for operating lease liabilities $ 33 $ 35 $ 30 December 31, 2022 2021 (Millions) Other Information: Right-of-use asset (included in Regulatory assets, deferred charges, and other ) $ 162 $ 159 Operating lease liabilities: Current (included in Accrued and other current liabilities ) $ 25 $ 23 Noncurrent (included in Regulatory liabilities, deferred income, and other ) $ 148 $ 141 Weighted-average remaining lease term – operating leases (years) 13 13 Weighted-average discount rate – operating leases 4.62% 4.56% At December 31, 2022, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31: (Millions) 2023 $ 31 2024 26 2025 20 2026 20 2027 19 Thereafter 122 Total future lease payments 238 Less: Amount representing interest 65 Total obligations under operating leases $ 173 We are the lessor to certain lease agreements for office space in our headquarters building, which are insignificant to our financial statements.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement, Noncash Expense [Abstract]
Equity-Based Compensation [Text Block]	Note 14 – Equity-Based Compensation Williams’ Plan Information The Williams Companies, Inc. 2007 Incentive Plan (the Plan) provides common-stock-based awards to both employees and nonmanagement directors. To date, 50 million new shares have been authorized for making awards under the Plan, including 10 million shares added on April 28, 2020. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. At December 31, 2022, 25 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 15 million shares were available for future grants. Additionally, up to 5.2 million new shares of our common stock have been authorized to date to be available for sale under our Employee Stock Purchase Plan (ESPP), including 1.6 million shares added on April 28, 2020. Employees purchased 242 thousand shares at a weighted-average price of $24.57 per share during 2022. Approximately 1.2 million shares were available for purchase under the ESPP at December 31, 2022. We recognize compensation expense on employee stock-based awards on a straight-line basis; forfeitures are recognized when they occur. Operating and maintenance expenses and Selling, general, and administrative expenses in our Consolidated Statement of Income include equity-based compensation expense in 2022, 2021, and 2020 of $73 million, $81 million, and $52 million, respectively. Income tax benefit recognized related to the stock-based compensation expense in 2022, 2021, and 2020 was $18 million, $20 million, and $13 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2022, was $63 million, all of which related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.7 years. Nonvested Restricted Stock Units At December 31, 2022 and 2021, we had restricted stock units outstanding, including performance-based shares, of 6.9 million shares and 7.3 million shares, respectively, with a weighted-average fair value of $23.63 and $22.35, respectively. Restricted stock units generally vest after three years. Performance-based grants may vest at a range from zero percent to 200 percent of the original shares granted based on performance against a target. At December 31, 2022, there were 2.6 million performance-based shares outstanding. Stock Options There were no stock options granted in 2022, 2021, or 2020. At December 31, 2022, we had 2.8 million stock options that were both outstanding and exercisable, with a weighted-average exercise price of $34.32. The weighted-average remaining contractual life for stock options that were both outstanding and exercisable at December 31, 2022, was 2.8 years. Cash received for the exercise of stock options in 2022 was $49 million, and the related income tax benefit recognized in 2022 was $2 million.

Fair Value Measurements, Guaran

Fair Value Measurements, Guarantees, and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Fair Value Measurements, Guarantees, and Concentration of Credit Risk [Text Block]	Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk The following table presents, by level within the fair value hierarchy, certain of our significant financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, accounts payable, and commercial paper approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table. Fair Value Measurements Using Carrying Fair Quoted Significant Significant (Millions) Assets (liabilities) at December 31, 2022: Measured on a recurring basis: ARO Trust investments $ 230 $ 230 $ 230 $ — $ — Commodity derivative assets (1) 166 166 20 132 14 Commodity derivative liabilities (1) (810) (810) (22) (718) (70) Other financial assets (liabilities) - net (5) (5) — (5) — Additional disclosures: Long-term debt, including current portion (22,554) (21,569) — (21,569) — Guarantees (38) (25) — (9) (16) Assets (liabilities) at December 31, 2021: Measured on a recurring basis: ARO Trust investments $ 260 $ 260 $ 260 $ — $ — Commodity derivative assets (2) 84 84 2 81 1 Commodity derivative liabilities (2) (488) (488) (69) (403) (16) Other financial assets (liabilities) - net (7) (7) — (7) — Additional disclosures: Long-term debt, including current portion (23,675) (27,768) — (27,768) — Guarantees (39) (26) — (10) (16) (1) Net commodity derivative assets and liabilities exclude $202 million of net cash collateral in Level 1. (2) Net commodity derivative assets and liabilities exclude $296 million of net cash collateral in Level 1. Fair Value Methods We use the following methods and assumptions in estimating the fair value of our financial instruments: Assets measured at fair value on a recurring basis ARO Trust investments : Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that is specifically designated to fund future ARO’s. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and is reported in Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. Commodity derivatives : Commodity derivatives include exchange-traded contracts and OTC contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. We also have other derivatives related to asset management agreements and other contracts that require physical delivery. Derivatives classified as Level 1 are valued using New York Mercantile Exchange (NYMEX) futures prices. Derivatives classified as Level 2 are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. Derivatives classified as Level 3 are valued using a combination of observable and unobservable inputs. The fair value amounts are presented on a net basis and reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements and cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Commodity derivative assets are reported in Derivative assets and Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet. Commodity derivative liabilities are reported in Derivative liabilities and Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. Changes in the fair value of our derivative assets and liabilities are recorded in Net gain (loss) on commodity derivatives and Net processing commodity expenses in our Consolidated Statement of Income. See Note 16 – Derivatives for additional information on our derivatives. The following table presents a reconciliation of changes in fair value of our net commodity derivatives classified as Level 3 in the fair value hierarchy. Year Ended December 31, 2022 2021 (Millions) Balance at beginning of period $ (15) $ (2) Gains (losses) included in our Consolidated Statement of Income (31) (62) Purchases, issuances, and settlements (5) 13 Acquired derivatives (Note 3) — 24 Transfers into Level 3 (24) — Transfers out of Level 3 19 12 Balance at end of period $ (56) $ (15) A substantial portion of the carrying value of our Level 3 derivatives at December 31, 2022, relates to a long-term physical natural gas purchase contract associated with an ongoing pipeline expansion project. The valuation of this contract reflects the extrapolation of forward natural gas prices for periods beyond observable price curves, which is considered a significant unobservable input. Additional fair value disclosures Long-term debt, including current portion : The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton, Leidy South, and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach (see Note 12 – Debt and Banking Arrangements). Guarantees : Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation. To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued and other current liabilities in our Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $24 million at December 31, 2022. Our exposure declines systematically through the remaining term of WilTel’s obligation. The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim. Nonrecurring fair value measurements During the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock on the New York Stock Exchange, which declined 40 percent during the quarter, including a 26 percent decline in the month of March. These changes were generally attributed to macroeconomic and geopolitical conditions, including significant declines in crude oil prices driven by both surplus supply and a decrease in demand caused by the coronavirus pandemic. As a result of these conditions, we performed an interim assessment of the goodwill associated with our Northeast G&P reporting unit as of March 31, 2020. The assessment considered the total fair value of the businesses within the Northeast G&P reporting unit, which was determined using income and market approaches. We utilized internally developed industry weighted-average discount rates and estimates of valuation multiples of comparable publicly traded gathering and processing companies. In assessing the fair value as of the March 31, 2020, measurement date, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA market multiples as compared with recent history and significantly higher industry weighted-average discount rates. The fair value of the reporting unit was further reconciled to our estimated total enterprise value as of March 31, 2020, which considered observable valuation multiples of comparable publicly traded companies applied to each distinct business including the Northeast G&P reporting unit. This assessment indicated that the estimated fair value of the Northeast G&P reporting unit was below its carrying value, including goodwill. As a result of this Level 3 measurement, we recognized a full impairment charge of $187 million as of March 31, 2020, in Impairment of goodwill in our Consolidated Statement of Income. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in our Consolidated Statement of Income. The following table presents impairments of assets and equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted. Impairments Year Ended December 31, Segment Date of Measurement Fair Value 2022 2021 2020 (Millions) Impairment of certain assets: Certain capitalized project costs (1) Transmission & Gulf of Mexico June 30, 2021 $ 1 $ 2 Certain capitalized project costs (1) Transmission & Gulf of Mexico December 31, 2020 42 $ 170 Certain gathering assets (2) Northeast G&P December 31, 2020 5 12 Impairment of certain assets $ — $ 2 $ 182 Impairment of equity-method investments: RMM (3) West December 31, 2020 $ 421 $ 108 RMM (4) West March 31, 2020 557 243 Brazos Permian II (4) West March 31, 2020 — 193 BRMH (5) Northeast G&P March 31, 2020 191 229 Appalachia Midstream Investments (5) Northeast G&P March 31, 2020 2,700 127 Aux Sable (5) Northeast G&P March 31, 2020 7 39 Laurel Mountain (5) Northeast G&P March 31, 2020 236 10 Discovery (5) Transmission & Gulf of Mexico March 31, 2020 367 97 Impairment of equity-method investments $ — $ — $ 1,046 ______________ (1) Relates to capitalized project development costs for the Northeast Supply Enhancement project. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project. Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, developments in the political and regulatory environments caused us to slightly lower that assessed probability such that the capitalized project costs required impairment. The estimated fair value of the materials within the capitalized project costs at December 31, 2020 considered other internal uses and salvage values for the Property, plant, and equipment – net . The remaining capitalized costs were determined to have no fair value. The estimated fair value of certain capitalized project costs at June 30, 2021, was determined by a market approach, which incorporated an indication of interest by a third-party. (2) Relates to a gathering system in the Marcellus Shale region, that was sold in 2021. The estimated fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization was determined using a market approach, which incorporated an indication of interest by a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. (3) During the fourth quarter of 2020, RMM renegotiated service contracts with a significant customer in connection with the customer’s Chapter 11 bankruptcy proceedings. The renegotiated contracts result in lower service rates and lower projected future cash flows. As a result, we evaluated this investment for other-than-temporary impairment. The fair value was measured using an income approach. We utilized a discount rate of 18 percent in our analysis. (4) Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the market declines previously discussed. (5) Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in BRMH and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments, including gathering systems that are part of Appalachia Midstream Investments, were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the market declines previously discussed. Concentration of Credit Risk Accounts receivable The following table summarizes concentration of receivables, net of allowances: December 31, 2022 2021 (Millions) NGLs, natural gas, and related products and services $ 505 $ 486 Regulated interstate natural gas transportation and storage 311 274 Marketing of natural gas and NGLs 858 609 Upstream activities 97 82 Accounts Receivable related to revenues from contracts with customers 1,771 1,451 Receivables from derivatives 889 462 Other accounts receivable 63 65 Trade accounts and other receivables - net $ 2,723 $ 1,978 Customers include producers, distribution companies, industrial users, gas marketers, and pipelines primarily located in the continental United States. As a general policy, collateral is not required for receivables with the exception of the marketing receivables discussed below. Customers’ financial condition and credit worthiness are evaluated regularly and, based upon this evaluation, we may obtain collateral to support receivables. We use established credit policies to determine and monitor the creditworthiness of gas marketing and trading counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives [Text Block]	Note 16 – Derivatives Commodity-Related Derivatives We are exposed to commodity price risk. To manage this volatility, we use various contracts in our marketing and trading activities that generally meet the definition of derivatives. Derivative positions are monitored using techniques including, but not limited to, value at risk. Derivative instruments are recognized at fair value in our Consolidated Balance Sheet as either assets or liabilities and are presented on a net basis by counterparty, net of margin deposits. See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for additional fair value information. In our Consolidated Statement of Cash Flows, any cash impacts of settled commodity-related derivatives are recorded as operating activities. We enter into commodity-related derivatives to economically hedge exposures to natural gas, NGLs, and crude oil and retain exposure to price changes that can, in a volatile energy market, be material and can adversely affect our results of operations. At December 31, 2022, the notional volume of the net long (short) positions for our commodity-related derivative contracts were as follows: Commodity Unit of Measure Net Long (Short) Position Index Risk Natural Gas MMBtu 745,415,032 Central Hub Risk - Henry Hub Natural Gas MMBtu (46,154,200) Basis Risk Natural Gas MMBtu (50,737,802) Central Hub Risk - Mont Belvieu Natural Gas Liquids Barrels 35,548 Basis Risk Natural Gas Liquids Barrels (3,880,364) Central Hub Risk - WTI Crude Oil Barrels (123,250) Derivative Financial Statement Presentation The fair value of commodity-related derivatives, which are not designated as hedging instruments for accounting purposes, was reflected as follows: December 31, December 31, Derivative Category Assets (Liabilities) Assets (Liabilities) (Millions) Current $ 1,099 $ (1,278) $ 619 $ (760) Noncurrent 269 (734) 166 (429) Total derivatives $ 1,368 $ (2,012) $ 785 $ (1,189) Counterparty and collateral netting offset (1,034) 1,236 (476) 772 Amounts recognized in our Consolidated Balance Sheet $ 334 $ (776) $ 309 $ (417) The pre-tax effects of commodity-related derivative instruments in Net gain (loss) on commodity derivatives reflected within Total revenues and Net processing commodity expenses in our Consolidated Statement of Income were as follows: Gain (Loss) Year Ended December 31, 2022 2021 2020 (Millions) Realized commodity-related derivatives designated as hedging instruments $ — $ (55) $ (2) Realized commodity-related derivatives not designated as hedging instruments (91) 16 (3) Unrealized commodity-related derivatives not designated as hedging instruments (296) (109) — Net gain (loss) on commodity derivatives $ (387) $ (148) $ (5) Realized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses $ 16 $ 2 $ 1 Unrealized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses $ 47 $ — $ — Contingent Features Generally, collateral may be provided by a parent guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are offset against fair value amounts recognized for derivatives executed with the same counterparty. We have specific trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with these counterparties. At December 31, 2022, the contractually required collateral in the event of a credit rating downgrade to non-investment grade status was $13 million. We maintain accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, we may be required to deposit cash into these accounts. At December 31, 2022, and 2021, net cash collateral held on deposit in broker margin accounts was $202 million and $296 million, respectively.

Contingent Liabilities and Comm

Contingent Liabilities and Commitments	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Contingent Liabilities and Commitments [Text Block]	Note 17 – Contingent Liabilities and Commitments Alaska Refinery Contamination Litigation We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions primarily arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane were remanded to the Alaska Superior Court. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us. The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. The State of Alaska later announced the discovery of additional contaminants per- and polyfluoralkyl (PFOS and PFOA) offsite of the refinery, and the court permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The court subsequently remanded the offsite PFOS/PFOA claims to the Alaska Department of Environmental Conservation for investigation and stayed the claims pending their potential resolution at the administrative agency. Several trial dates encompassing all three cases have been scheduled and stricken. In the summer of 2019, the court deconsolidated the cases for purposes of trial. A bench trial on all claims except North Pole’s claims began in October 2019. In January 2020, the Alaska Superior Court issued its Memorandum of Decision finding in favor of the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The court found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the court entered final judgment in the case. Filing deadlines were stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also filed post-judgment motions including a Motion for New Trial and a Motion to Alter or Amend the Judgment. These post-trial motions were resolved with the court’s denial of the last motion on June 11, 2020. Our Statement of Points on Appeal was filed on July 13, 2020. On June 22, 2020, the court stayed the North Pole’s case pending resolution of the appeal in the State of Alaska and FHRA case. On December 23, 2020, we filed our opening brief on appeal. Oral argument was held on December 15, 2021. We have recorded an accrued liability in the amount of our estimate of the probable loss. It is reasonably possible that we may not be successful on appeal and could ultimately pay up to the amount of judgment. Royalty Matters Certain of our customers, including Chesapeake Energy Corporation (Chesapeake), have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with Chesapeake in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by Chesapeake. Chesapeake has reached a settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement applies to both Chesapeake and us. The settlement does not require any contribution from us. On August 23, 2021, the court approved the settlement, but two objectors filed an appeal with the United States Court of Appeals for the Fifth Circuit. Litigation Against Energy Transfer and Related Parties On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (ETE Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the ETE Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims. On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC and the other Energy Transfer affiliates that are parties to the ETE Merger Agreement, alleging material breaches of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the ETE Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the ETE Merger Agreement due to any failure to obtain the Tax Opinion. The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017. On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. Trial was held May 10 through May 17, 2021. On December 29, 2021, the court entered judgment in our favor in the amount of $410 million, plus interest at the contractual rate, and our reasonable attorneys’ fees and expenses. On September 21, 2022, the court entered a final order and judgment awarding us the termination fee, attorney’s fees, expenses, and interest in the amount of $602 million plus additional interest starting September 17, 2022. Energy Transfer has appealed to the Delaware Supreme Court. Environmental Matters We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2022, we have accrued liabilities totaling $ 40 million The EPA and various state regulatory agencies routinely propose and promulgate new rules and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, reviews and updates to the National Ambient Air Quality Standards, and rules for new and existing source performance standards for volatile organic compound and methane. We continuously monitor these regulatory changes and how they may impact our operations. Implementation of new or modified regulations may result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in our Consolidated Balance Sheet for both new and existing facilities in affected areas; however, due to regulatory uncertainty on final rule content and applicability timeframes, we are unable to reasonably estimate the cost of these regulatory impacts at this time. Continuing operations Our interstate gas pipelines are involved in remediation and monitoring activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2022, we have accrued liabilities of $13 million for these costs and expect to recover approximately $4 million through rates. We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2022, we have accrued liabilities totaling $10 million for these costs. Former operations We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below. • Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations; • Former petroleum products and natural gas pipelines; • Former petroleum refining facilities; • Former exploration and production and mining operations; • Former electricity and natural gas marketing and trading operations. At December 31, 2022, we have accrued environmental liabilities of $17 million related to these matters. Other Divestiture Indemnifications Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided. At December 31, 2022, other than as previously disclosed, we are not aware of any material claims against us involving the above-described indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made. In addition to the foregoing, various other proceedings are pending against us that are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position. Summary We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties. Commitments Commitments for construction and acquisition of property, plant, and equipment are approximately $439 million at December 31, 2022. Commitments for Gas & NGL Marketing Services pipeline transportation capacity and storage capacity are approximately $546 million at December 31, 2022.

Segment Disclosures

Segment Disclosures	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
Segment Disclosures [Text Block]	Note 18 – Segment Disclosures Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.) Performance Measurement We evaluate segment operating performance based upon Modified EBITDA . This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment Service revenues primarily represent transportation services provided to our marketing business and gathering services provided to our oil and gas properties. Intersegment Product sales primarily represent the sale of natural gas and NGLs from our natural gas processing plants and our oil and gas properties to our marketing business. We define Modified EBITDA as follows: • Net income (loss) before: ◦ Provision (benefit) for income taxes; ◦ Interest incurred, net of interest capitalized; ◦ Equity earnings (losses); ◦ Impairment of equity-method investments; ◦ Other investing income (loss) – net; ◦ Impairment of goodwill; ◦ Depreciation and amortization expenses; ◦ Accretion expense associated with asset retirement obligations for nonregulated operations. • This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above. The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in our Consolidated Statement of Income: Year Ended December 31, 2022 2021 2020 (Millions) Modified EBITDA by segment: Transmission & Gulf of Mexico $ 2,674 $ 2,621 $ 2,379 Northeast G&P 1,796 1,712 1,489 West 1,211 961 947 Gas & NGL Marketing Services (1) (40) 22 51 Other 434 178 (15) 6,075 5,494 4,851 Accretion expense associated with asset retirement obligations for nonregulated operations (51) (45) (35) Depreciation and amortization expenses (2,009) (1,842) (1,721) Impairment of goodwill — — (187) Equity earnings (losses) 637 608 328 Impairment of equity-method investments — — (1,046) Other investing income (loss) – net 16 7 8 Proportional Modified EBITDA of equity-method investments (979) (970) (749) Interest expense (1,147) (1,179) (1,172) (Provision) benefit for income taxes (425) (511) (79) Net income (loss) $ 2,117 $ 1,562 $ 198 ____________ (1) Modified EBITDA for 2022, 2021, and 2020, includes charges of $161 million, $15 million, and $17 million respectively, associated with lower of cost or net realizable value adjustments to our inventory. These charges are reflected in Product Sales or Product costs in our Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies ) . Net unrealized commodity-related derivatives gains of $47 million in 2022 and $0 in 2021 and 2020 are reflected in Net processing commodity expenses. The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Income and Other financial information : Transmission & Gulf of Mexico Northeast G&P West Gas & NGL Marketing Services (1) Other Eliminations Total (Millions) 2022 Segment revenues: Service revenues External $ 3,461 $ 1,613 $ 1,443 $ 3 $ 16 $ — $ 6,536 Internal 118 41 99 — 8 (266) — Total service revenues 3,579 1,654 1,542 3 24 (266) 6,536 Total service revenues – commodity consideration 64 14 182 — — — 260 Product sales External 228 28 145 4,052 103 — 4,556 Internal 176 106 696 (518) 603 (1,063) — Total product sales 404 134 841 3,534 706 (1,063) 4,556 Net gain (loss) on commodity derivatives Realized — — (4) 17 (104) — (91) Unrealized — — — (321) 25 — (296) Total net gain (loss) on commodity derivatives (2) — — (4) (304) (79) — (387) Total revenues $ 4,047 $ 1,802 $ 2,561 $ 3,233 $ 651 $ (1,329) $ 10,965 Other financial information: Additions to long-lived assets $ 1,420 $ 261 $ 1,507 $ 4 $ 406 $ — $ 3,598 Proportional Modified EBITDA of equity-method investments 193 654 132 — — — 979 2021 Segment revenues: Service revenues External $ 3,310 $ 1,490 $ 1,178 $ 3 $ 20 $ — $ 6,001 Internal 75 38 70 — 12 (195) — Total service revenues 3,385 1,528 1,248 3 32 (195) 6,001 Total service revenues – commodity consideration 52 7 179 — — — 238 Product sales External 231 13 60 4,094 138 — 4,536 Internal 118 86 583 198 195 (1,180) — Total product sales 349 99 643 4,292 333 (1,180) 4,536 Net gain (loss) on commodity derivatives Realized — — (44) 25 (20) — (39) Unrealized — — — (109) — — (109) Total net gain (loss) on commodity derivatives (2) — — (44) (84) (20) — (148) Total revenues $ 3,786 $ 1,634 $ 2,026 $ 4,211 $ 345 $ (1,375) $ 10,627 Other financial information: Additions to long-lived assets $ 861 $ 164 $ 209 $ 1 $ 620 $ — $ 1,855 Proportional Modified EBITDA of equity-method investments 183 682 105 — — — 970 Transmission & Gulf of Mexico Northeast G&P West Gas & NGL Marketing Services (1) Other Eliminations Total (Millions) 2020 Segment revenues: Service revenues External $ 3,207 $ 1,416 $ 1,248 $ 32 $ 21 $ — $ 5,924 Internal 50 49 24 — 13 (136) — Total service revenues 3,257 1,465 1,272 32 34 (136) 5,924 Total service revenues – commodity consideration 21 7 101 — — — 129 Product sales External 144 16 20 1,491 — — 1,671 Internal 47 41 132 111 — (331) — Total product sales 191 57 152 1,602 — (331) 1,671 Net gain (loss) on commodity derivatives Realized — — (2) (3) — — (5) Unrealized — — — — — — — Total net gain (loss) on commodity derivatives (2) — — (2) (3) — — (5) Total revenues $ 3,469 $ 1,529 $ 1,523 $ 1,631 $ 34 $ (467) $ 7,719 Other financial information: Additions to long-lived assets $ 706 $ 137 $ 318 $ — $ 122 $ — $ 1,283 Proportional Modified EBITDA of equity-method investments 166 473 110 — — — 749 ______________ (1) See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies. (2) We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue. Segment assets include Investments , Property, plant, and equipment – net, and Intangible assets – net of accumulated amortization . The following table reflects segment assets and equity-method investments by reportable segments: Segment Assets Equity-Method Investments December 31, 2022 December 31, 2021 December 31, 2022 December 31, 2021 (Millions) Transmission & Gulf of Mexico $ 17,795 $ 17,142 $ 629 $ 602 Northeast G&P 13,539 13,861 3,566 3,681 West 10,710 9,698 843 838 Gas & NGL Marketing Services 130 294 — — Other 1,143 792 10 — Total 43,317 41,787 $ 5,048 $ 5,121 Total current assets 3,797 4,549 Regulatory assets, deferred charges, and other 1,319 1,276 Total assets $ 48,433 $ 47,612

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2022
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Note 19 – Subsequent Events Quarterly Dividends to Common Stockholders On January 31, 2023, our board of directors approved a regular quarterly dividend to common stockholders of $0.4475 per share payable on March 27, 2023. MountainWest Acquisition On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest Pipelines Holding Company (MountainWest) which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity (MountainWest Acquisition), for $1.08 billion of cash funded with available sources of short-term liquidity and assumption of $430 million outstanding principal amount of long-term debt, subject to working capital and post-closing adjustments. The MountainWest Acquisition expands our existing transmission and storage infrastructure footprint into major markets in Utah, Wyoming, and Colorado. Due to the timing, the initial purchase price accounting for the transaction was not yet complete at the time of filing.

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2022
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
Schedule II - Valuation and Qualifying Accounts [Text Block]	The Williams Companies, Inc. Schedule II — Valuation and Qualifying Accounts Additions Beginning Charged Other Deductions Ending (Millions) 2022 Deferred tax asset valuation allowance (1) $ 297 $ (97) $ — $ — $ 200 2021 Deferred tax asset valuation allowance (1) 325 (28) — — 297 2020 Deferred tax asset valuation allowance (1) 319 6 — — 325 __________ (1) Deducted from related assets.

General, Description of Busin_2

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Principles of consolidation [Policy Text Block]	Principles of consolidation The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Our judgment is required to evaluate whether we control an entity. Key areas of that evaluation include: • Determining whether an entity is a VIE (see Note 2 – Variable Interest Entities); • Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests; • Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary; • Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities. We apply the equity method of accounting to investments over which we exercise significant influence but do not control. Distributions received from equity-method investees are presented in our Consolidated Statement of Cash Flows according to the nature of the distributions approach, which classifies distributions received from equity-method investees as either returns on investment (cash inflows from operating activities) or returns of
Use of estimates [Policy Text Block]	Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Significant estimates and assumptions include: • Impairment assessments of investments, property, plant, and equipment, and intangible assets; • Litigation-related contingencies; • Environmental remediation obligations; • Depreciation and/or amortization of long-lived assets, which are comprised of property, plant, and equipment, and intangible assets; • Depreciation and/or amortization of equity-method investment basis differences; • Asset retirement obligations (AROs); • Measurement of fair value of derivatives; • Pension and postretirement valuation variables; • Measurement of regulatory liabilities; • Measurement of deferred income tax assets and liabilities, including assumptions related to the realization of deferred income tax assets; • Revenue recognition, including estimates utilized in recognition of deferred revenue; • Purchase price accounting. These estimates are discussed further throughout these notes.
Regulatory accounting [Policy Text Block]	Regulatory accounting Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC), and their rates are established by the FERC. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates. Management’s expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. We record certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refunded in future rates. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, AROs, shipper imbalance activity, fuel and power cost differentials, depreciation, negative salvage, pension and other postretirement benefits, customer tax refunds, and rate allowances for deferred income taxes at a historically higher federal income tax rate. Our current and noncurrent regulatory asset and liability balances at December 31, 2022 and 2021 are as follows: December 31, 2022 2021 (Millions) Current assets reported within Other current assets and deferred charges $ 138 $ 111 Noncurrent assets reported within Regulatory assets, deferred charges, and other 459 415 Total regulated assets $ 597 $ 526 Current liabilities reported within Accrued and other current liabilities $ 201 $ 56 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,233 1,324 Total regulated liabilities $ 1,434 $ 1,380
Revenue recognition [Policy Text Block]	Revenue recognition Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users. Service revenue contracts from our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer. Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipeline businesses and are not within the scope of ASC Topic 606, “Revenue from Contracts with Customers”. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset, which are referred to as Contributions in aid of construction in our Consolidated Statement of Cash Flows. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied. Service Revenues Gas pipeline businesses: Revenues from our regulated interstate natural gas pipeline businesses, which are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a daily or monthly reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one-month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following: • Firm transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities; • Interruptible transportation or storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities. In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation. We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks. Midstream businesses: Revenues from our non-regulated gathering, processing, transportation, and storage midstream businesses include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ natural gas and NGLs, generally under prepaid contracted storage capacity contracts. In situations where, in our judgment, we provide an integrated package of services combined into a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available. We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer. We generally earn a contractually stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our contracts, we allocate the transaction price to each performance obligation based on the judgmentally determined relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology as these methods appropriately match the consumption of services provided to the customer. The units of production methodology requires the use of production estimates that are uncertain and the use of judgment when developing estimates of future production volumes, thus impacting the rate of revenue recognition. Production estimates are monitored as circumstances and events warrant. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude, based on management’s judgment, it is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period. Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized in our Consolidated Statement of Income both at the time the processing service is provided in Service revenues – commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product sales . The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale. Product Sales In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances. In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers which we remarket. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We also market natural gas and NGLs from the production at our upstream properties. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction. We purchase natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future, resulting in positive net product sales. Commodity-based exchange-traded futures contracts and over-the-counter (OTC) contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. The physical purchase, transportation, storage, and sale of natural gas are accounted for on a weighted-average cost or accrual basis, as appropriate, unlike the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized in our Consolidated Statement of Income in the period they are incurred. As we are acting as an agent for our natural gas marketing customers and engage in energy trading activities, our natural gas marketing revenues are presented net of the related costs of those activities. Prior to the 2022 integration of our legacy gas marketing operations with the acquired Sequent Acquisition operations (see Note 3 – Acquisitions), our legacy gas marketing operations were reported on a gross basis. Contract Assets Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within Other current assets and deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer. Contract Liabilities Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings and transactions for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within Accrued and other current liabilities and Regulatory liabilities, deferred income, and other , respectively, in our Consolidated Balance Sheet. Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined, in our judgment, that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract.
Derivative instruments and hedging activities [Policy Text Block]	Derivative instruments and hedging activities We are exposed to commodity price risk. We utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We purchase natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. Commodity-based exchange-traded futures contracts and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between receipt and delivery points occurs. Some commodity-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the natural gas marketing operations. These contracts generally meet the definition of derivatives and are typically not designated as hedges for accounting purposes. When a commodity-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed, and the contract price is recognized in the respective line item in our Consolidated Statement of Income representing the actual price of the underlying goods being delivered. Unrealized gains and losses on physically settled commodity-related derivative contracts for commodity sales transactions are recognized in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income. Realized and unrealized gains and losses on non-designated commodity-related derivative contracts for commodity sales transactions that are financially settled are reported in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income. Net gains and losses on derivatives for shrink gas purchases for processing plants are reported in Net processing commodity expenses in our Consolidated Statement of Income. We experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio as well as upstream related production. However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying production or transportation and storage contracts, which is not recognized until the underlying transaction occurs. (See Note 16 – Derivatives.) We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Derivative assets; Regulatory assets, deferred charges, and other; Derivative liabilities ; or Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. These amounts are presented on a net basis and reflect the netting of asset and liability positions permitted under the terms of master netting arrangements and cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The accounting for the changes in fair value of a commodity derivative can be summarized as follows: Derivative Treatment Accounting Method Normal purchases and normal sales exception Accrual accounting Designated in a qualifying hedging relationship Hedge accounting All other derivatives Mark-to-market accounting We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected in our Consolidated Balance Sheet after the initial election of the exception. We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income. For commodity derivatives designated as a cash flow hedge, the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in our Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by us. As of December 31, 2022 and 2021, we are not applying hedge accounting to any commodity derivative instruments.
Interest capitalized [Policy Text Block]	Interest capitalized We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds (equity AFUDC). The latter is included in Other income (expense) – net below Operating income (loss) in our Consolidated Statement of Income. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.
Income taxes [Policy Text Block]	Income taxes We include the operations of our domestic corporate subsidiaries and income from our subsidiary partnerships in our consolidated fed e ral income tax return and also file tax return s 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 v aluation allowances associated with deferred tax assets.
Earnings (loss) per common share [Policy Text Block]	Earnings (loss) per common share Basic earnings (loss) per common share in our Consolidated Statement of Income is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share in our Consolidated Statement of Income primarily includes any dilutive effect of nonvested restricted stock units and stock options. Diluted earnings (loss) per common share is calculated using the treasury-stock method.
Cash and cash equivalents [Policy Text Block]	Cash and cash equivalents Cash and cash equivalents in our Consolidated Balance Sheet consist of highly liquid investments with original maturities of three months or less when acquired.
Accounts receivable [Policy Text Block]	Accounts receivable Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts, considering current expected credit losses using a forward-looking “expected loss” model, the financial condition of our customers, and the age of past due accounts. The majority of our trade receivable balances are due within 30 days. We monitor the credit quality of our counterparties through review of collection trends, credit ratings, and other analyses, such as bankruptcy monitoring. Financial assets from our natural gas transmission and storage business, gathering, processing and transportation business, marketing business, and upstream operations are segregated into separate pools for evaluation due to different counterparty risks inherent in each business. Changes in counterparty risk factors could lead to reassessment of the composition of our financial assets as separate pools or the need for additional pools. We calculate our allowance for credit losses incorporating an aging method. In estimating our expected credit losses, we utilize historical loss rates over many years, which include periods of both high and low commodity prices. Commodity prices could have a significant impact on a portion of our gathering and processing and upstream counterparties’ financial health and ability to satisfy current obligations. Our expected credit loss estimate considers both internal and external forward-looking commodity price expectations, as well as counterparty credit ratings, and factors impacting their near-term liquidity. In addition, our expected credit loss estimate considers potential contractual, physical, and commercial protections and outcomes in the case of a counterparty bankruptcy. The physical location and nature of our services help to mitigate collectability concerns of our gathering and processing producer customers. Our gathering lines in many cases are physically connected to the customers’ wellheads and pads, and there may not be alternative gathering lines nearby. The construction of gathering systems is capital intensive and it would be costly for others to replicate, especially considering the depletion to date of the associated reserves. As a result, we play a critical role in getting customers’ production from the wellhead to a marketable condition and location. This tends to reduce collectability risk as our services enable producers to generate operating cash flows. Commodity price movements generally do not impact the majority of our natural gas transmission businesses customers’ financial condition. We also provide marketing and risk management services to retail and wholesale gas marketers, utility companies, upstream producers, and industrial customers. These counterparties utilize netting agreements that enable us to net receivables and payables by counterparty upon settlement. We also net across product lines and against cash collateral received to collateralize receivable positions, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, our counterparties are settled net, they are recorded on a gross basis in our Consolidated Balance Sheet as accounts receivable and accounts payable. We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. We do not have a material amount of significantly aged receivables at December 31, 2022 and 2021.
Inventories [Policy Text Block]	Inventories Inventories in our Consolidated Balance Sheet primarily consist of natural gas in underground storage, NGLs, and materials and supplies and primarily are stated at the lower of cost or net realizable value. The cost of inventories is primarily determined using the average-cost method. Any lower of cost or net realizable value adjustments are included in Product sales (for natural gas marketing inventory as these sales are presented net of the related costs) or in Product costs for NGL inventory.
Property, plant, and equipment [Policy Text Block]	Property, plant, and equipment Property, plant, and equipment is initially recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values. As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method. We follow the successful efforts method of accounting for our undivided interest in upstream properties. Our oil and gas producing property costs are depreciated using a units of production method. Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Gains or losses from the ordinary sale or retirement of property, plant, and equipment for nonregulated assets are primarily recorded in Other (income) expense – net included in Operating income (loss) in our Consolidated Statement of Income. Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment. We record a liability and increase the basis in the underlying asset for the present value of each expected future ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. For our upstream properties, the ARO is recorded based on our working interest in the underlying properties. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as we expect to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in our Consolidated Statement of Income, except for regulated entities, for which the increase in the liability results in a corresponding increase to a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.
Intangible assets [Policy Text Block]	Intangible assets Our intangible assets included within Intangible assets – net of accumulated amortization in our Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation customer relationships. Our intangible assets are generally amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.
Impairment of property, plant, and equipment, intangible assets, and investments [Policy Text Block]	Impairment of property, plant, and equipment, intangible assets, and investments We evaluate our property, plant, and equipment and intangible assets for impairment when, in our judgment, events or circumstances, including probable abandonment, indicate that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes, including selling the assets in the near term or holding them for their remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment to be recognized in our consolidated financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist. For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. We evaluate our investments for impairment when, in our judgment, events or circumstances indicate that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in our consolidated financial statements as an impairment charge.
Equity-method investment basis differences [Policy Text Block]	Equity-method investment basis differences Differences between the carrying value of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in our Consolidated Statement of Income includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.
Leases [Policy Text Block]	Leases We recognize a lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. We have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset. Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 20 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset. We use judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available. When permitted under our lease agreements, we may sublease certain unused office space for fixed periods that could extend up to the length of the original lease agreement.
Pension and other postretirement benefits [Policy Text Block]	Pension and other postretirement benefits The funded status of each of the pension and other postretirement benefit plans is recognized separately in our Consolidated Balance Sheet as either an asset or liability. The plans’ benefit obligations and net periodic benefit costs (credits) are actuarially determined and impacted by various assumptions and estimates. The discount rates are determined separately for each of our pension and other postretirement benefit plans based on an approach specific to our plans. The year-end discount rates are determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows of each plan. The expected long-term rates of return on plan assets are determined by combining a review of the historical returns within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital market projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class. Unrecognized actuarial gains and losses are deferred and recorded in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost (credit). The unrecognized net actuarial losses deferred in AOCI at December 31, 2022 and 2021 were $18 million and $30 million, respectively. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 10 years for our pension plans and approximately 5 years for our other postretirement benefit plan. The expected return on plan assets component of net periodic benefit cost (credit) is calculated using the market-related value of plan assets. For our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect the amortization of gains or losses associated with the difference between the expected and actual return on plan assets over a 5-year period. Additionally, the market-related value of assets may be no more than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related value of plan assets for our other postretirement benefit plan is equal to the unadjusted fair value of plan assets at the beginning of the year.
Contingent liabilities [Policy Text Block]	Contingent liabilities We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable, and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.
Treasury stock [Policy Text Block]	Treasury stock Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as Treasury stock, at cost in our Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in our Consolidated Balance Sheet using the average-cost method.
Cash flows from revolving credit facility and commercial paper program [Policy Text Block]	Cash flows from revolving credit facility and commercial paper program Proceeds and payments related to borrowings under our revolving credit facility are reflected in the financing activities in our Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in our Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 12 – Debt and Banking Arrangements.)

General, Description of Busin_3

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Regulatory Assets and Liabilities [Table Text Block]	Our current and noncurrent regulatory asset and liability balances at December 31, 2022 and 2021 are as follows: December 31, 2022 2021 (Millions) Current assets reported within Other current assets and deferred charges $ 138 $ 111 Noncurrent assets reported within Regulatory assets, deferred charges, and other 459 415 Total regulated assets $ 597 $ 526 Current liabilities reported within Accrued and other current liabilities $ 201 $ 56 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,233 1,324 Total regulated liabilities $ 1,434 $ 1,380

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2022
Variable Interest Entity Disclosures [Abstract]
Schedule of Variable Interest Entities [Table Text Block]	The following table presents amounts included in the Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs: December 31, 2022 2021 (Millions) Assets (liabilities): Cash and cash equivalents $ 49 $ 78 Trade accounts and other receivables – net 136 132 Inventories 4 3 Other current assets and deferred charges 7 7 Property, plant, and equipment – net 5,154 5,295 Intangible assets – net of accumulated amortization 2,158 2,267 Regulatory assets, deferred charges, and other 29 20 Accounts payable (76) (61) Accrued and other current liabilities (34) (29) Regulatory liabilities, deferred income, and other (275) (287)

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2022
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information [Table Text Block]	The following pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. in 2022, 2021, and 2020, are presented as if the Trace Acquisition had been completed on January 1, 2021, and the Sequent Acquisition had been completed on January 1, 2020. These pro forma amounts are not necessarily indicative of what the actual results would have been if the Trace Acquisition and Sequent Acquisition had in fact occurred on the dates or for the periods indicated, nor do they purport to project Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements. Year Ended December 31, 2022 As Reported Pro Forma Trace (1) Pro Forma Combined (Millions) Revenues $ 10,965 $ 45 $ 11,010 Net income (loss) attributable to The Williams Companies, Inc. 2,049 18 2,067 Year Ended December 31, 2021 As Reported Pro Forma Trace Pro Forma Sequent (2) Pro Forma Combined (Millions) Revenues $ 10,627 $ 118 $ 188 $ 10,933 Net income (loss) attributable to The Williams Companies, Inc. 1,517 42 4 1,563 Year Ended December 31, 2020 As Reported Pro Forma Sequent Pro Forma Combined (Millions) Revenues $ 7,719 $ 74 $ 7,793 Net income (loss) attributable to The Williams Companies, Inc. 211 (13) 198 (1) Excludes results from operations acquired in the Trace Acquisition for the period beginning on the acquisition date of April 29, 2022, as these results are included in the amounts as reported. (2) Excludes results from operations acquired in the Sequent Acquisition for the period beginning on the acquisition date of July 1, 2021, as these results are included in the amounts as reported.
Trace Midstream Acquisition
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the West segment, and liabilities assumed at April 29, 2022. The fair value of accounts receivable acquired equals contractual amounts receivable. (Millions) Cash and cash equivalents $ 39 Trade accounts and other receivables – net 18 Property, plant, and equipment – net 448 Intangible assets – net of accumulated amortization 472 Other noncurrent assets 20 Total assets acquired $ 997 Accounts payable $ 12 Accrued and other current liabilities 5 Other noncurrent liabilities 8 Total liabilities assumed $ 25 Net assets acquired $ 972
Sequent Acquisition
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	We accounted for the Sequent Acquisition as a business combination. The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Gas & NGL Marketing Services segment, and liabilities assumed at July 1, 2021. The fair value of accounts receivable acquired equals contractual amounts receivable. The fair value of the intangible assets was measured using an income approach. The fair value of the inventory acquired was based on the market price of the natural gas in underground storage at the acquisition date. See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for the valuation techniques used to measure fair value of derivative assets and liabilities. (Millions) Cash and cash equivalents $ 8 Trade accounts and other receivables – net 498 Inventories 121 Derivative assets 57 Other current assets and deferred charges 4 Property, plant, and equipment – net 5 Intangible assets – net of accumulated amortization 306 Other noncurrent assets 3 Commodity derivatives included in other noncurrent assets 49 Total assets acquired $ 1,051 Accounts payable $ 514 Derivative liabilities 116 Accrued and other current liabilities 46 Other noncurrent liabilities 1 Commodity derivatives included in other noncurrent liabilities 215 Total liabilities assumed $ 892 Net assets acquired $ 159

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2022
Revenue Recognition [Abstract]
Disaggregation of Revenue [Table Text Block]	The following table presents our revenue disaggregated by major service line: Transco Northwest Pipeline Gulf of Mexico Midstream and Storage Northeast West Midstream Gas & NGL Marketing Services Other Eliminations Total (Millions) 2022 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 2,696 $ 443 $ — $ — $ — $ — $ — $ (72) $ 3,067 Gathering, processing, transportation, fractionation, and storage: Monetary consideration — — 365 1,395 1,476 — — (164) 3,072 Commodity consideration — — 64 14 182 — — — 260 Other 10 — 27 233 54 3 — (19) 308 Total service revenues 2,706 443 456 1,642 1,712 3 — (255) 6,707 Product sales 179 — 251 134 841 10,768 706 (1,813) 11,066 Total revenues from contracts with customers 2,885 443 707 1,776 2,553 10,771 706 (2,068) 17,773 Other revenues (1) 24 4 10 26 8 7,929 (55) (11) 7,935 Other adjustments (2) — — — — — (15,467) — 724 (14,743) Total revenues $ 2,909 $ 447 $ 717 $ 1,802 $ 2,561 $ 3,233 $ 651 $ (1,355) $ 10,965 2021 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 2,547 $ 441 $ — $ — $ — $ — $ — $ (33) $ 2,955 Gathering, processing, transportation, fractionation, and storage: Monetary consideration — — 344 1,308 1,184 — — (130) 2,706 Commodity consideration — — 52 7 179 — — — 238 Other 10 — 22 195 52 3 1 (19) 264 Total service revenues 2,557 441 418 1,510 1,415 3 1 (182) 6,163 Product sales 88 — 269 99 643 6,404 333 (1,215) 6,621 Total revenues from contracts with customers 2,645 441 687 1,609 2,058 6,407 334 (1,397) 12,784 Other revenues (1) 10 3 8 25 (32) 2,632 11 (13) 2,644 Other adjustments (2) — — — — — (4,828) — 27 (4,801) Total revenues $ 2,655 $ 444 $ 695 $ 1,634 $ 2,026 $ 4,211 $ 345 $ (1,383) $ 10,627 Transco Northwest Pipeline Gulf of Mexico Midstream and Storage Northeast West Midstream Gas & NGL Marketing Services Other Eliminations Total (Millions) 2020 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 2,404 $ 449 $ — $ — $ — $ — $ — $ (7) $ 2,846 Gathering, processing, transportation, fractionation, and storage: Monetary consideration — — 348 1,279 1,226 — — (97) 2,756 Commodity consideration — — 21 7 101 — — — 129 Other 10 — 27 164 35 32 1 (16) 253 Total service revenues 2,414 449 396 1,450 1,362 32 1 (120) 5,984 Product sales 80 — 114 57 152 1,602 — (336) 1,669 Total revenues from contracts with customers 2,494 449 510 1,507 1,514 1,634 1 (456) 7,653 Other revenues (1) 10 — 9 22 9 (3) 33 (14) 66 Total revenues $ 2,504 $ 449 $ 519 $ 1,529 $ 1,523 $ 1,631 $ 34 $ (470) $ 7,719 ______________________________ (1) Revenues not derived from contracts with customers primarily consist of physical product sales related to derivative contracts, realized and unrealized gains and losses associated with our derivative contracts, which are reported in Net gain (loss) on commodity derivatives in the Consolidated Statement of Income, management fees that we receive for certain services we provide to operated equity-method investments, and leasing revenues associated with our headquarters building. (2) Other adjustments reflect certain costs of Gas & NGL Marketing Services’ risk management activities. As we are acting as agent for natural gas marketing customers or engage in energy trading activities, the resulting revenues are presented net of the related costs of those activities in the Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).
Contract with Customer, Asset and Liability [Table Text Block]	Contract Assets The following table presents a reconciliation of our contract assets: Year Ended December 31, 2022 2021 (Millions) Balance at beginning of year $ 22 $ 12 Revenue recognized in excess of amounts invoiced 208 184 Minimum volume commitments invoiced (201) (174) Balance at end of year $ 29 $ 22 Contract Liabilities The following table presents a reconciliation of our contract liabilities: Year Ended December 31, 2022 2021 (Millions) Balance at beginning of year $ 1,126 $ 1,209 Payments received and deferred 180 116 Significant financing component 9 10 Contract liability acquired 2 1 Recognized in revenue (274) (210) Balance at end of year $ 1,043 $ 1,126
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]	The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2022. Contract Liabilities Remaining Performance Obligations (Millions) 2023 (one year) $ 142 $ 3,643 2024 (one year) 122 3,388 2025 (one year) 117 3,149 2026 (one year) 112 2,520 2027 (one year) 101 2,415 Thereafter 449 14,675 Total $ 1,043 $ 29,790

Provision (Benefit) for Incom_2

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Schedule of Components of Provision (benefit) for income taxes [Table Text Block]	The Provision (benefit) for income taxes includes: Year Ended December 31, 2022 2021 2020 (Millions) Current: Federal $ (25) $ (1) $ (29) State 19 3 — (6) 2 (29) Deferred: Federal 424 421 98 State 7 88 10 431 509 108 Provision (benefit) for income taxes $ 425 $ 511 $ 79
Provision for income taxes at federal statutory rate [Table Text Block]	Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows: Year Ended December 31, 2022 2021 2020 (Millions) Provision (benefit) at statutory rate $ 534 $ 435 $ 58 Increases (decreases) in taxes resulting from: State income taxes (net of federal benefit) 113 71 6 State deferred income tax rate change (92) — — Federal valuation allowance (70) 3 1 Federal settlements (45) — — Impact of nontaxable noncontrolling interests (14) (9) 3 Other – net (1) 11 11 Provision (benefit) for income taxes $ 425 $ 511 $ 79
Deferred tax liabilities and Deferred tax assets [Table Text Block]	Significant components of Deferred income tax liabilities are as follows: December 31, 2022 2021 (Millions) Gross deferred income tax liabilities: Property, plant and equipment $ 3,171 $ 2,777 Investments 1,784 1,669 Other 138 154 Total gross deferred income tax liabilities 5,093 4,600 Gross deferred income tax assets: Accrued liabilities 1,108 872 Foreign tax credits 91 140 Federal loss carryovers 730 879 State losses and credits 356 421 Other 121 132 Total gross deferred income tax assets 2,406 2,444 Less valuation allowance 200 297 Net deferred income tax assets 2,206 2,147 Deferred income tax liabilities $ 2,887 $ 2,453

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2022
Retirement Benefits [Abstract]
Changes in Projected Benefit Obligations, Fair Value of Plan Assets, Funded Status, and Schedule of Amounts Recognized in Balance Sheet [Table Text Block]	The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated: Pension Benefits Other 2022 2021 2022 2021 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 1,133 $ 1,183 $ 200 $ 220 Service cost 28 30 1 1 Interest cost 31 28 6 5 Plan participants’ contributions — — 2 2 Benefits paid (78) (83) (12) (14) Net actuarial loss (gain) (1) (162) (21) (45) (14) Settlements (12) (4) — — Net increase (decrease) in benefit obligation (193) (50) (48) (20) Benefit obligation at end of year 940 1,133 152 200 Change in plan assets: Fair value of plan assets at beginning of year 1,336 1,357 287 278 Actual return on plan assets (132) 62 (27) 16 Employer contributions 3 4 3 5 Plan participants’ contributions — — 2 2 Benefits paid (78) (83) (12) (14) Settlements (12) (4) — — Net increase (decrease) in fair value of plan assets (219) (21) (34) 9 Fair value of plan assets at end of year 1,117 1,336 253 287 Funded status — overfunded (underfunded) $ 177 $ 203 $ 101 $ 87 Amounts recognized in the Consolidated Balance Sheet: Noncurrent assets $ 201 $ 229 $ 105 $ 91 Current liabilities (2) (3) (4) (4) Noncurrent liabilities (22) (23) — — Funded status — overfunded (underfunded) $ 177 $ 203 $ 101 $ 87 Accumulated benefit obligation $ 930 $ 1,118 ____________ (1) 2022 amounts are due primarily to the following factors: Pension benefits - discount rate assumptions, partially offset by change in interest crediting rate assumption; Other Postretirement Benefits - discount rate assumption. 2021 amounts are due primarily to the following factors: Pension Benefits - discount rate assumptions, partially offset by experience-related items; Other Postretirement Benefits - discount rate assumption and experience-related items.
Defined Benefit Plan, Plan with Projected Benefit Obligation in Excess of Plan Assets [Table Text Block]	The following table summarizes information for pension plans with obligations in excess of plan assets at December 31. 2022 2021 (Millions) Projected benefit obligation $ 24 $ 26 Accumulated benefit obligation 22 22 Fair value of plan assets — —
Pre-tax amounts recognized in Accumulated other comprehensive income (loss)[Table Text Block]	Pre-tax amounts recognized in Accumulated other comprehensive income (loss) at December 31 are as follows: Pension Benefits Other 2022 2021 2022 2021 (Millions) Net actuarial gain (loss) $ (45) $ (46) $ 18 $ 4
Schedule of Net Benefit Cost (Credit) [Table Text Block]	Net periodic benefit cost (credit) for the years ended December 31 consist of the following: Pension Benefits Other 2022 2021 2020 2022 2021 2020 (Millions) Components of net periodic benefit cost (credit): Service cost $ 28 $ 30 $ 31 $ 1 $ 1 $ 1 Interest cost 31 28 36 6 5 7 Expected return on plan assets (44) (43) (53) (10) (10) (11) Amortization of net actuarial loss 12 14 21 — — — Net actuarial loss from settlements 3 1 9 — — — Reclassification to regulatory liability — — — 1 2 2 Net periodic benefit cost (credit) (1) $ 30 $ 30 $ 44 $ (2) $ (2) $ (1) ____________ (1) Components other than Service cost are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income
Other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) [Table Text Block]	Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes for the years ended December 31 consist of the following: Pension Benefits Other 2022 2021 2020 2022 2021 2020 (Millions) Net actuarial gain (loss) arising during the year $ (14) $ 40 $ 112 $ 14 $ 29 $ (4) Amortization of net actuarial loss 12 14 21 — — — Net actuarial loss from settlements 3 1 9 — — — Total recognized in Other comprehensive income (loss) $ 1 $ 55 $ 142 $ 14 $ 29 $ (4)
Defined Benefit Plan, Assumptions [Table Text Block]	The weighted-average assumptions utilized to determine benefit obligations and Net periodic benefit cost (credit) as of December 31 are as follows: Pension Benefits Other 2022 2021 2020 2022 2021 2020 Benefit obligations: Discount rate 5.16 % 2.82 % 2.45 % 5.20 % 2.93 % 2.59 % Rate of compensation increase 3.58 3.67 3.76 N/A N/A N/A Cash balance interest crediting rate 3.50 3.00 3.00 N/A N/A N/A Net periodic benefit cost (credit): Discount rate 2.84 % 2.45 % 3.08 % 2.93 % 2.59 % 3.27 % Expected long-term rate of return on plan assets 3.81 3.69 4.67 3.67 3.61 4.39 Rate of compensation increase 3.67 3.76 3.68 N/A N/A N/A Cash balance interest crediting rate 3.00 3.00 3.50 N/A N/A N/A
Fair values of plan assets [Table Text Block]	The fair values of our pension and other postretirement benefits plan assets by asset class at December 31 are as follows: 2022 Pension Benefits Other Postretirement Benefits Level 1 (1) Level 2 (2) Total Level 1 (1) Level 2 (2) Total (Millions) Cash management funds $ 45 $ — $ 45 $ 105 $ — $ 105 Government debt securities 58 18 76 8 3 11 Corporate debt securities — 284 284 — 39 39 Other 1 4 5 — — — $ 104 $ 306 410 $ 113 $ 42 155 Commingled investment funds (3): Equities 273 38 Fixed income 434 60 Total assets at fair value $ 1,117 $ 253 2021 Pension Benefits Other Postretirement Benefits Level 1 (1) Level 2 (2) Total Level 1 (1) Level 2 (2) Total (Millions) Cash management funds $ 37 $ — $ 37 $ 14 $ — $ 14 Equity securities 42 19 61 39 10 49 Government debt securities 99 28 127 13 4 17 Corporate debt securities — 350 350 — 47 47 Mutual fund - Municipal bonds — — — 59 — 59 Other (3) 2 (1) (1) — (1) $ 175 $ 399 574 $ 124 $ 61 185 Commingled investment funds (3): Equities 288 39 Fixed income 474 63 Total assets at fair value $ 1,336 $ 287 ____________ (1) Level 1 includes assets with fair values based on quoted prices in active markets for identical assets. Cash management funds, equity securities traded on U.S. exchanges, U.S. Treasury securities, and mutual funds are included in this level. (2) Level 2 includes assets with fair values determined by using significant other observable inputs. This level includes equity securities traded on active foreign exchanges and fixed income securities, other than U.S. Treasury securities, that are valued primarily using pricing models which incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.
Expected benefit payments [Table Text Block]	Following are the expected benefit payments, which reflect the same assumptions previously discussed and future service as appropriate. Pension Other (Millions) 2023 $ 84 $ 13 2024 83 13 2025 84 12 2026 81 12 2027 80 11 2028-2032 389 52

Investing Activities (Tables)

Investing Activities (Tables)	12 Months Ended
	Dec. 31, 2022
Investments [Abstract]
Investments [Table Text Block]	Ownership Interest at December 31, 2022 December 31, 2022 2021 (Millions) Equity method: Appalachia Midstream Investments (1) $ 2,975 $ 3,056 RMM 50% 395 401 OPPL 50% 386 388 Blue Racer 50% 383 377 Discovery 60% 345 328 Gulfstream 50% 220 215 Laurel Mountain 69% 205 226 Other Various 139 130 5,048 5,121 Other 17 6 $ 5,065 $ 5,127 ___________
Contributions [Table Text Block]	Purchases of and contributions to equity-method investments We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included: Year Ended December 31, 2022 2021 2020 (Millions) Appalachia Midstream Investments $ 83 $ 84 $ 116 Discovery 41 — — Cardinal Pipeline Company, LLC 16 — — Gulfstream 14 26 3 Blue Racer (1) — 3 157 Other 12 2 49 $ 166 $ 115 $ 325 ___________ (1) See following discussion in the section Acquisition of additional interests in BRMH below.
Dividends and distributions [Table Text Block]	Dividends and distributions The organizational documents of entities in which we have an equity-method investment generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included: Year Ended December 31, 2022 2021 2020 (Millions) Appalachia Midstream Investments $ 415 $ 433 $ 357 Laurel Mountain 112 33 31 Gulfstream 89 90 93 RMM 52 45 39 Blue Racer (1) 49 47 47 Discovery 49 44 21 OPPL 34 26 50 Other 65 39 15 $ 865 $ 757 $ 653 ___________ (1) See previous discussion in the section Acquisition of additional interests in BRMH above.
Summarized Financial Position and Results of Operations of Equity Method Investments [Table Text Block]	Summarized Financial Position and Results of Operations of All Equity-Method Investments December 31, 2022 2021 (Millions) Assets (liabilities): Current assets $ 964 $ 743 Noncurrent assets 12,701 13,211 Current liabilities (632) (435) Noncurrent liabilities (3,789) (3,774) Year Ended December 31, 2022 2021 2020 (Millions) Gross revenue $ 5,520 $ 4,688 $ 2,625 Operating income 1,268 1,191 508 Net income 1,102 1,006 459

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, Plant, and Equipment [Table Text Block]	The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the Consolidated Balance Sheet for the years ended: Estimated Depreciation December 31, 2022 2021 (Millions) Nonregulated: Natural gas gathering and processing facilities 5 - 40 $ 19,163 $ 18,203 Construction in progress Not applicable 997 331 Oil and gas properties Units of production 874 572 Other 0 - 45 2,998 2,649 Regulated: Natural gas transmission facilities 1.25 - 7.13 19,521 19,201 Construction in progress Not applicable Not applicable 708 475 Other 5 - 45 0.00 - 33.33 2,796 2,753 Total property, plant, and equipment, at cost 47,057 44,184 Accumulated depreciation and amortization (16,168) (14,926) Property, plant, and equipment — net $ 30,889 $ 29,258 __________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2022. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.
Schedule of Change in Asset Retirement Obligation	The following table presents the significant changes to our ARO, of which $1.827 billion and $1.590 billion are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued and other current liabilities at December 31, 2022 and 2021, respectively. Year Ended December 31, 2022 2021 (Millions) Balance at beginning of year $ 1,665 $ 1,222 Liabilities incurred (1) 77 336 Liabilities settled (22) (25) Accretion 85 73 Revisions (2) 109 59 Balance at end of year $ 1,914 $ 1,665 ___________ (1) Includes $307 million of ARO in 2021 related to acquired upstream properties.

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Finite-Lived Intangible Assets [Table Text Block]	The gross carrying amount and accumulated amortization of intangible assets, included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, at December 31 are as follows: 2022 2021 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Customer relationships $ 10,065 $ (2,801) $ 9,593 $ (2,448) Transportation and storage capacity contracts 267 (172) 267 (14) Other intangible assets 6 (2) 6 (2) $ 10,338 $ (2,975) $ 9,866 $ (2,464)

Accrued and Other Current Lia_2

Accrued and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Accrued Liabilities, Current [Abstract]
Accrued and Other Current Liabilities [Table Text Block]	December 31, 2022 2021 (Millions) Interest on debt $ 274 $ 277 Employee costs 218 214 Regulatory liabilities (Note 1) 201 56 Contract liabilities 141 134 Asset retirement obligations (Note 9) 87 75 Operating lease liabilities (Note 13) 25 23 Other, including accrued loss contingencies 324 256 $ 1,270 $ 1,035

Debt and Banking Arrangements (

Debt and Banking Arrangements (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	Long-Term Debt December 31, 2022 2021 (Millions) Transco: 7.08% Debentures due 2026 $ 8 $ 8 7.25% Debentures due 2026 200 200 7.85% Notes due 2026 1,000 1,000 4% Notes due 2028 400 400 3.25% Notes due 2030 700 700 5.4% Notes due 2041 375 375 4.45% Notes due 2042 400 400 4.6% Notes due 2048 600 600 3.95% Notes due 2050 500 500 Other financing obligation — Atlantic Sunrise 809 830 Other financing obligation — Leidy South 77 72 Other financing obligation — Dalton 252 254 Northwest Pipeline: 7.125% Debentures due 2025 85 85 4% Notes due 2027 500 500 Williams: 3.35% Notes due 2022 — 750 3.6% Notes due 2022 — 1,250 3.7% Notes due 2023 — 850 4.5% Notes due 2023 600 600 4.3% Notes due 2024 1,000 1,000 4.55% Notes due 2024 1,250 1,250 3.9% Notes due 2025 750 750 4% Notes due 2025 750 750 3.75% Notes due 2027 1,450 1,450 3.5% Notes due 2030 1,000 1,000 2.6% Notes due 2031 1,500 1,500 7.5% Debentures due 2031 339 339 7.75% Notes due 2031 252 252 8.75% Notes due 2032 445 445 4.65% Notes due 2032 1,000 — 6.3% Notes due 2040 1,250 1,250 5.8% Notes due 2043 400 400 5.4% Notes due 2044 500 500 5.75% Notes due 2044 650 650 4.9% Notes due 2045 500 500 5.1% Notes due 2045 1,000 1,000 4.85% Notes due 2048 800 800 3.5% Notes due 2051 650 650 5.3% Notes due 2052 750 — Various — 7.7% to 8.72% Notes due 2022 to 2027 2 2 Unamortized debt issuance costs (135) (131) Net unamortized debt premium (discount) (55) (56) Total long-term debt, including current portion 22,554 23,675 Long-term debt due within one year (627) (2,025) Long-term debt $ 21,927 $ 21,650
Schedule of Maturities of Long-term Debt [Table Text Block]	The following table presents aggregate minimum maturities of long-term debt and other financing obligations, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years: December 31, 2022 (Millions) 2023 $ 629 2024 2,281 2025 1,619 2026 1,245 2027 1,993
Schedule of Line of Credit Facilities [Table Text Block]	Credit Facility December 31, 2022 Stated Capacity Outstanding (Millions) Long-term credit facility (1) $ 3,750 $ — Letters of credit under certain bilateral bank agreements 30 ________________ (1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Lease, Cost [Table Text Block]	Year Ended December 31, 2022 2021 2020 (Millions) Lease Cost: Operating lease cost $ 34 $ 35 $ 37 Variable lease cost 26 15 19 Sublease income — (1) (1) Total lease cost $ 60 $ 49 $ 55 Cash paid for operating lease liabilities $ 33 $ 35 $ 30 December 31, 2022 2021 (Millions) Other Information: Right-of-use asset (included in Regulatory assets, deferred charges, and other ) $ 162 $ 159 Operating lease liabilities: Current (included in Accrued and other current liabilities ) $ 25 $ 23 Noncurrent (included in Regulatory liabilities, deferred income, and other ) $ 148 $ 141 Weighted-average remaining lease term – operating leases (years) 13 13 Weighted-average discount rate – operating leases 4.62% 4.56%
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	At December 31, 2022, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31: (Millions) 2023 $ 31 2024 26 2025 20 2026 20 2027 19 Thereafter 122 Total future lease payments 238 Less: Amount representing interest 65 Total obligations under operating leases $ 173

Fair Value Measurements, Guar_2

Fair Value Measurements, Guarantees, and Concentration of Credit Risk (Tables)	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Fair Value Assets and Liabilities Measured On Recurring Basis [Table Text Block]	The following table presents, by level within the fair value hierarchy, certain of our significant financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, accounts payable, and commercial paper approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table. Fair Value Measurements Using Carrying Fair Quoted Significant Significant (Millions) Assets (liabilities) at December 31, 2022: Measured on a recurring basis: ARO Trust investments $ 230 $ 230 $ 230 $ — $ — Commodity derivative assets (1) 166 166 20 132 14 Commodity derivative liabilities (1) (810) (810) (22) (718) (70) Other financial assets (liabilities) - net (5) (5) — (5) — Additional disclosures: Long-term debt, including current portion (22,554) (21,569) — (21,569) — Guarantees (38) (25) — (9) (16) Assets (liabilities) at December 31, 2021: Measured on a recurring basis: ARO Trust investments $ 260 $ 260 $ 260 $ — $ — Commodity derivative assets (2) 84 84 2 81 1 Commodity derivative liabilities (2) (488) (488) (69) (403) (16) Other financial assets (liabilities) - net (7) (7) — (7) — Additional disclosures: Long-term debt, including current portion (23,675) (27,768) — (27,768) — Guarantees (39) (26) — (10) (16) (1) Net commodity derivative assets and liabilities exclude $202 million of net cash collateral in Level 1. (2) Net commodity derivative assets and liabilities exclude $296 million of net cash collateral in Level 1.
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation	The following table presents a reconciliation of changes in fair value of our net commodity derivatives classified as Level 3 in the fair value hierarchy. Year Ended December 31, 2022 2021 (Millions) Balance at beginning of period $ (15) $ (2) Gains (losses) included in our Consolidated Statement of Income (31) (62) Purchases, issuances, and settlements (5) 13 Acquired derivatives (Note 3) — 24 Transfers into Level 3 (24) — Transfers out of Level 3 19 12 Balance at end of period $ (56) $ (15)
Fair Value Measurements, Nonrecurring [Table Text Block]	The following table presents impairments of assets and equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted. Impairments Year Ended December 31, Segment Date of Measurement Fair Value 2022 2021 2020 (Millions) Impairment of certain assets: Certain capitalized project costs (1) Transmission & Gulf of Mexico June 30, 2021 $ 1 $ 2 Certain capitalized project costs (1) Transmission & Gulf of Mexico December 31, 2020 42 $ 170 Certain gathering assets (2) Northeast G&P December 31, 2020 5 12 Impairment of certain assets $ — $ 2 $ 182 Impairment of equity-method investments: RMM (3) West December 31, 2020 $ 421 $ 108 RMM (4) West March 31, 2020 557 243 Brazos Permian II (4) West March 31, 2020 — 193 BRMH (5) Northeast G&P March 31, 2020 191 229 Appalachia Midstream Investments (5) Northeast G&P March 31, 2020 2,700 127 Aux Sable (5) Northeast G&P March 31, 2020 7 39 Laurel Mountain (5) Northeast G&P March 31, 2020 236 10 Discovery (5) Transmission & Gulf of Mexico March 31, 2020 367 97 Impairment of equity-method investments $ — $ — $ 1,046 ______________ (1) Relates to capitalized project development costs for the Northeast Supply Enhancement project. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project. Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, developments in the political and regulatory environments caused us to slightly lower that assessed probability such that the capitalized project costs required impairment. The estimated fair value of the materials within the capitalized project costs at December 31, 2020 considered other internal uses and salvage values for the Property, plant, and equipment – net . The remaining capitalized costs were determined to have no fair value. The estimated fair value of certain capitalized project costs at June 30, 2021, was determined by a market approach, which incorporated an indication of interest by a third-party. (2) Relates to a gathering system in the Marcellus Shale region, that was sold in 2021. The estimated fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization was determined using a market approach, which incorporated an indication of interest by a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. (3) During the fourth quarter of 2020, RMM renegotiated service contracts with a significant customer in connection with the customer’s Chapter 11 bankruptcy proceedings. The renegotiated contracts result in lower service rates and lower projected future cash flows. As a result, we evaluated this investment for other-than-temporary impairment. The fair value was measured using an income approach. We utilized a discount rate of 18 percent in our analysis. (4) Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the market declines previously discussed. (5) Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in BRMH and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments, including gathering systems that are part of Appalachia Midstream Investments, were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the market declines previously discussed.
Concentration of receivables, net of allowances, by product or service [Table Text Block]	The following table summarizes concentration of receivables, net of allowances: December 31, 2022 2021 (Millions) NGLs, natural gas, and related products and services $ 505 $ 486 Regulated interstate natural gas transportation and storage 311 274 Marketing of natural gas and NGLs 858 609 Upstream activities 97 82 Accounts Receivable related to revenues from contracts with customers 1,771 1,451 Receivables from derivatives 889 462 Other accounts receivable 63 65 Trade accounts and other receivables - net $ 2,723 $ 1,978

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	At December 31, 2022, the notional volume of the net long (short) positions for our commodity-related derivative contracts were as follows: Commodity Unit of Measure Net Long (Short) Position Index Risk Natural Gas MMBtu 745,415,032 Central Hub Risk - Henry Hub Natural Gas MMBtu (46,154,200) Basis Risk Natural Gas MMBtu (50,737,802) Central Hub Risk - Mont Belvieu Natural Gas Liquids Barrels 35,548 Basis Risk Natural Gas Liquids Barrels (3,880,364) Central Hub Risk - WTI Crude Oil Barrels (123,250)
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location	The fair value of commodity-related derivatives, which are not designated as hedging instruments for accounting purposes, was reflected as follows: December 31, December 31, Derivative Category Assets (Liabilities) Assets (Liabilities) (Millions) Current $ 1,099 $ (1,278) $ 619 $ (760) Noncurrent 269 (734) 166 (429) Total derivatives $ 1,368 $ (2,012) $ 785 $ (1,189) Counterparty and collateral netting offset (1,034) 1,236 (476) 772 Amounts recognized in our Consolidated Balance Sheet $ 334 $ (776) $ 309 $ (417)
Pretax Effect Of Interest Rate And Energy Related Derivatives	The pre-tax effects of commodity-related derivative instruments in Net gain (loss) on commodity derivatives reflected within Total revenues and Net processing commodity expenses in our Consolidated Statement of Income were as follows: Gain (Loss) Year Ended December 31, 2022 2021 2020 (Millions) Realized commodity-related derivatives designated as hedging instruments $ — $ (55) $ (2) Realized commodity-related derivatives not designated as hedging instruments (91) 16 (3) Unrealized commodity-related derivatives not designated as hedging instruments (296) (109) — Net gain (loss) on commodity derivatives $ (387) $ (148) $ (5) Realized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses $ 16 $ 2 $ 1 Unrealized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses $ 47 $ — $ —

Segment Disclosures (Tables)

Segment Disclosures (Tables)	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
Reconciliation of Modified EBITDA to Net income (loss) [Table Text Block]	The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in our Consolidated Statement of Income: Year Ended December 31, 2022 2021 2020 (Millions) Modified EBITDA by segment: Transmission & Gulf of Mexico $ 2,674 $ 2,621 $ 2,379 Northeast G&P 1,796 1,712 1,489 West 1,211 961 947 Gas & NGL Marketing Services (1) (40) 22 51 Other 434 178 (15) 6,075 5,494 4,851 Accretion expense associated with asset retirement obligations for nonregulated operations (51) (45) (35) Depreciation and amortization expenses (2,009) (1,842) (1,721) Impairment of goodwill — — (187) Equity earnings (losses) 637 608 328 Impairment of equity-method investments — — (1,046) Other investing income (loss) – net 16 7 8 Proportional Modified EBITDA of equity-method investments (979) (970) (749) Interest expense (1,147) (1,179) (1,172) (Provision) benefit for income taxes (425) (511) (79) Net income (loss) $ 2,117 $ 1,562 $ 198 ____________ (1) Modified EBITDA for 2022, 2021, and 2020, includes charges of $161 million, $15 million, and $17 million respectively, associated with lower of cost or net realizable value adjustments to our inventory. These charges are reflected in Product Sales or Product costs in our Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies ) . Net unrealized commodity-related derivatives gains of $47 million in 2022 and $0 in 2021 and 2020 are reflected in Net processing commodity expenses.
Reconciliation of revenue from segment to consolidated [Table Text Block]	The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Income and Other financial information : Transmission & Gulf of Mexico Northeast G&P West Gas & NGL Marketing Services (1) Other Eliminations Total (Millions) 2022 Segment revenues: Service revenues External $ 3,461 $ 1,613 $ 1,443 $ 3 $ 16 $ — $ 6,536 Internal 118 41 99 — 8 (266) — Total service revenues 3,579 1,654 1,542 3 24 (266) 6,536 Total service revenues – commodity consideration 64 14 182 — — — 260 Product sales External 228 28 145 4,052 103 — 4,556 Internal 176 106 696 (518) 603 (1,063) — Total product sales 404 134 841 3,534 706 (1,063) 4,556 Net gain (loss) on commodity derivatives Realized — — (4) 17 (104) — (91) Unrealized — — — (321) 25 — (296) Total net gain (loss) on commodity derivatives (2) — — (4) (304) (79) — (387) Total revenues $ 4,047 $ 1,802 $ 2,561 $ 3,233 $ 651 $ (1,329) $ 10,965 Other financial information: Additions to long-lived assets $ 1,420 $ 261 $ 1,507 $ 4 $ 406 $ — $ 3,598 Proportional Modified EBITDA of equity-method investments 193 654 132 — — — 979 2021 Segment revenues: Service revenues External $ 3,310 $ 1,490 $ 1,178 $ 3 $ 20 $ — $ 6,001 Internal 75 38 70 — 12 (195) — Total service revenues 3,385 1,528 1,248 3 32 (195) 6,001 Total service revenues – commodity consideration 52 7 179 — — — 238 Product sales External 231 13 60 4,094 138 — 4,536 Internal 118 86 583 198 195 (1,180) — Total product sales 349 99 643 4,292 333 (1,180) 4,536 Net gain (loss) on commodity derivatives Realized — — (44) 25 (20) — (39) Unrealized — — — (109) — — (109) Total net gain (loss) on commodity derivatives (2) — — (44) (84) (20) — (148) Total revenues $ 3,786 $ 1,634 $ 2,026 $ 4,211 $ 345 $ (1,375) $ 10,627 Other financial information: Additions to long-lived assets $ 861 $ 164 $ 209 $ 1 $ 620 $ — $ 1,855 Proportional Modified EBITDA of equity-method investments 183 682 105 — — — 970 Transmission & Gulf of Mexico Northeast G&P West Gas & NGL Marketing Services (1) Other Eliminations Total (Millions) 2020 Segment revenues: Service revenues External $ 3,207 $ 1,416 $ 1,248 $ 32 $ 21 $ — $ 5,924 Internal 50 49 24 — 13 (136) — Total service revenues 3,257 1,465 1,272 32 34 (136) 5,924 Total service revenues – commodity consideration 21 7 101 — — — 129 Product sales External 144 16 20 1,491 — — 1,671 Internal 47 41 132 111 — (331) — Total product sales 191 57 152 1,602 — (331) 1,671 Net gain (loss) on commodity derivatives Realized — — (2) (3) — — (5) Unrealized — — — — — — — Total net gain (loss) on commodity derivatives (2) — — (2) (3) — — (5) Total revenues $ 3,469 $ 1,529 $ 1,523 $ 1,631 $ 34 $ (467) $ 7,719 Other financial information: Additions to long-lived assets $ 706 $ 137 $ 318 $ — $ 122 $ — $ 1,283 Proportional Modified EBITDA of equity-method investments 166 473 110 — — — 749 ______________ (1) See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies. (2) We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.
Total assets and equity method investments by reporting segment [Table Text Block]	Segment assets include Investments , Property, plant, and equipment – net, and Intangible assets – net of accumulated amortization . The following table reflects segment assets and equity-method investments by reportable segments: Segment Assets Equity-Method Investments December 31, 2022 December 31, 2021 December 31, 2022 December 31, 2021 (Millions) Transmission & Gulf of Mexico $ 17,795 $ 17,142 $ 629 $ 602 Northeast G&P 13,539 13,861 3,566 3,681 West 10,710 9,698 843 838 Gas & NGL Marketing Services 130 294 — — Other 1,143 792 10 — Total 43,317 41,787 $ 5,048 $ 5,121 Total current assets 3,797 4,549 Regulatory assets, deferred charges, and other 1,319 1,276 Total assets $ 48,433 $ 47,612

Share Repurchase Program (Detai

Share Repurchase Program (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Sep. 03, 2021
Equity, Class of Treasury Stock [Line Items]
Stock Repurchase Program, Authorized Amount			$ 1,500
Purchase of treasury stock	$ 9	$ 0

General, Description of Busin_4

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Gulfstream Natural Gas System, LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50%
Discovery Producer Services LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	60%
Laurel Mountain Midstream, LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	69%
Blue Racer Midstream LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50%
Overland Pass Pipeline Company LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50%
Rocky Mountain Midstream Holdings LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50%
Transmission And Gulf Of Mexico [Member] | Gulfstream Natural Gas System, LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50%
Transmission And Gulf Of Mexico [Member] | Discovery Producer Services LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	60%
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%
Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	69%
Northeast G And P [Member] | Blue Racer Midstream LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50%	50%
Northeast G And P [Member] | Williams Companies Inc [Member] | Northeast JV [Member]
General and Description Of Business [Abstract]
Variable Interest Entity Ownership Percentage	65%
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%
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%
West [Member] | Overland Pass Pipeline Company LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50%
West [Member] | Rocky Mountain Midstream Holdings LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50%
West [Member] | Targa Train 7 LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	20%
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%
West [Member] | Williams Companies Inc [Member] | Brazos Permian II, LLC [Member]
General and Description Of Business [Abstract]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	15%

Summary of Significant Accounti

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets, Current	$ 138	$ 111
Regulatory Assets, Noncurrent	459	415
Total regulated assets	597	526
Regulatory Liabilities, Current	201	56
Regulatory Liabilities, Noncurrent	1,233	1,324
Total regulated liabilities	$ 1,434	1,380
Interest Capitalized [Abstract]
Minimum period of construction for capitalization of interest	3 months
Minimum total project cost for capitalization of interest	$ 1
Retirement Benefits, Description [Abstract]
Threshold For Amortization Of Unrecognized Actuarial Gains Losses	10%
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (24)	(33)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Retirement Benefits, Description [Abstract]
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ 18	$ 30
Pension Benefits [Member]
Retirement Benefits, Description [Abstract]
Approximate Amortization Period Of Net Actuarial Gain Loss	10 years
Amortization Period Of Difference Between Expected And Actual Return On Plan Assets	5 years
Other Postretirement Benefits [Member]
Retirement Benefits, Description [Abstract]
Approximate Amortization Period Of Net Actuarial Gain Loss	5 years
Minimum [Member]
Leases [Abstract]
Lessee, Operating Lease, Term of Contract	1 year
Minimum [Member] | Pension Benefits [Member]
Retirement Benefits, Description [Abstract]
Threshold For Market Related Value	90%
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%

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Variable Interest Entity [Line Items]
Assets	$ 48,433	$ 47,612
Equity-method investments	5,048	5,121
Variable Interest Entity, Primary Beneficiary [Member] | Cash and cash equivalents [Member]
Variable Interest Entity [Line Items]
Assets	49	78
Variable Interest Entity, Primary Beneficiary [Member] | Trade accounts and other receivables [Member]
Variable Interest Entity [Line Items]
Assets	136	132
Variable Interest Entity, Primary Beneficiary [Member] | Inventories [Member]
Variable Interest Entity [Line Items]
Assets	4	3
Variable Interest Entity, Primary Beneficiary [Member] | Other current assets and deferred charges [Member]
Variable Interest Entity [Line Items]
Assets	7	7
Variable Interest Entity, Primary Beneficiary [Member] | Property, plant, and equipment, net [Member]
Variable Interest Entity [Line Items]
Assets	5,154	5,295
Variable Interest Entity, Primary Beneficiary [Member] | Intangible assets - net of accumulated amortization [Member]
Variable Interest Entity [Line Items]
Assets	2,158	2,267
Variable Interest Entity, Primary Beneficiary [Member] | Regulatory assets, deferred charges, and other [Member]
Variable Interest Entity [Line Items]
Assets	29	20
Variable Interest Entity, Primary Beneficiary [Member] | Accounts payable [Member]
Variable Interest Entity [Line Items]
Liabilities	(76)	(61)
Variable Interest Entity, Primary Beneficiary [Member] | Accrued and Other Current Liabilities [Member]
Variable Interest Entity [Line Items]
Liabilities	(34)	(29)
Variable Interest Entity, Primary Beneficiary [Member] | Regulatory liabilities, deferred income, and other [Member]
Variable Interest Entity [Line Items]
Liabilities	$ (275)	$ (287)
Variable Interest Entity, Primary Beneficiary [Member] | Williams Companies Inc [Member] | Northeast JV [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	65%
Variable Interest Entity, Primary Beneficiary [Member] | Williams Companies Inc [Member] | Gulfstar One [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	51%
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%
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%
Equity-method investments	$ 46
Variable Interest Entity, Not Primary Beneficiary [Member] | Williams Companies Inc [Member] | Brazos Permian II, LLC [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	15%
Equity-method investments	$ 16

Acquisitions (Details)

Acquisitions (Details) - USD ($) $ in Millions					6 Months Ended	8 Months Ended	12 Months Ended
		Aug. 31, 2022	Apr. 29, 2022	Jul. 01, 2021	Dec. 31, 2021	Dec. 31, 2022	Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Business Acquisition [Line Items]
Revenues							$ 10,965		$ 10,627		$ 7,719
Modified EBITDA Earnings Loss							6,075		5,494		4,851
Net income (loss) attributable to The Williams Companies, Inc.							2,049		1,517		211
Payments to Acquire Productive Assets							3,598		1,855		1,283
Pro Forma [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue							11,010		10,933		7,793
Business Acquisition, Pro Forma Net Income (Loss)							2,067		1,563		198
Product [Member]
Business Acquisition [Line Items]
Revenues							4,556		4,536		1,671
Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1]						(387)		(148)		(5)
Gain (Loss) on Derivative Instruments | Energy Related Derivative | Not Designated as Hedging Instrument [Member]
Business Acquisition [Line Items]
Unrealized Gain (Loss) on Derivatives							(296)		(109)		0
West [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues							145		60		20
West [Member] | Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1]						(4)		(44)		(2)
West [Member] | Operating Segments [Member]
Business Acquisition [Line Items]
Revenues							2,561		2,026		1,523
Modified EBITDA Earnings Loss							1,211		961		947
Payments to Acquire Productive Assets							1,507		209		318
West [Member] | Operating Segments [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues							841		643		152
Gas & NGL Marketing Services | Product [Member]
Business Acquisition [Line Items]
Revenues							4,052	[2]	4,094		1,491
Gas & NGL Marketing Services | Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1]						(304)		(84)		(3)
Gas & NGL Marketing Services | Operating Segments [Member]
Business Acquisition [Line Items]
Revenues							3,233	[2]	4,211		1,631
Modified EBITDA Earnings Loss	[3]						(40)		22		51
Payments to Acquire Productive Assets							4		1		0
Gas & NGL Marketing Services | Operating Segments [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues							3,534	[2]	4,292		1,602
Transmission And Gulf Of Mexico [Member] | NorTex Acquisition
Business Acquisition [Line Items]
Payments to Acquire Productive Assets		$ 424
Transmission And Gulf Of Mexico [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues							228		231		144
Transmission And Gulf Of Mexico [Member] | Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1]						0		0		0
Transmission And Gulf Of Mexico [Member] | Operating Segments [Member]
Business Acquisition [Line Items]
Revenues							4,047		3,786		3,469
Modified EBITDA Earnings Loss							2,674		2,621		2,379
Payments to Acquire Productive Assets							1,420		861		706
Transmission And Gulf Of Mexico [Member] | Operating Segments [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues							404		349		191
Trace Midstream Acquisition
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			100%
Business Combination, Consideration Transferred			$ 972
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents			39
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables			18
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			448
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles			472
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets			20
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets			997
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable			12
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other			5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other			8
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities			25
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net			$ 972
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life			20 years
Percentage Of Finite Lived Intangible Assets Impacted By Our Intent Or Ability To Renew Or Extend Arrangement			2%
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension			19 years
Trace Midstream Acquisition | Pro Forma [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue							45	[4]	118
Business Acquisition, Pro Forma Net Income (Loss)							$ 18	[4]	42
Trace Midstream Acquisition | West [Member] | Selling, general and administrative expenses [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs						$ 8
Trace Midstream Acquisition | West [Member] | Operating Segments [Member]
Business Acquisition [Line Items]
Revenues						148
Modified EBITDA Earnings Loss						$ 73
Sequent Acquisition
Business Acquisition [Line Items]
Business Combination, Consideration Transferred				$ 159
Business Combination Working Capital Acquired				109
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents				8
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables				498
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory				121
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other				4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment				5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles				306
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets				3
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets				1,051
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable				514
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other				46
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other				1
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities				892
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net				$ 159
Sequent Acquisition | Pro Forma [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue									188	[5]	74
Business Acquisition, Pro Forma Net Income (Loss)									$ 4	[5]	$ (13)
Sequent Acquisition | Minimum [Member]
Business Acquisition [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life				1 year
Sequent Acquisition | Maximum [Member]
Business Acquisition [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life				8 years
Sequent Acquisition | Derivative
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other				$ 57
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets				49
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other				116
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other				$ 215
Sequent Acquisition | Gas & NGL Marketing Services
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				100%
Sequent Acquisition | Gas & NGL Marketing Services | Energy Commodities and Service
Business Acquisition [Line Items]
Revenues					$ (43)
Sequent Acquisition | Gas & NGL Marketing Services | Selling, general and administrative expenses [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs					5
Sequent Acquisition | Gas & NGL Marketing Services | Gain (Loss) on Derivative Instruments | Energy Related Derivative | Not Designated as Hedging Instrument [Member]
Business Acquisition [Line Items]
Unrealized Gain (Loss) on Derivatives					(109)
Sequent Acquisition | Gas & NGL Marketing Services | Operating Segments [Member]
Business Acquisition [Line Items]
Modified EBITDA Earnings Loss					(112)
Sequent Acquisition | Gas & NGL Marketing Services | Operating Segments [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues					(43)
Affiliate Costs					$ 80
[1]We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.[2]See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.[3] Modified EBITDA for 2022, 2021, and 2020, includes charges of $161 million, $15 million, and $17 million respectively, associated with lower of cost or net realizable value adjustments to our inventory. These charges are reflected in Product Sales or Product costs in our Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies ) . Net unrealized commodity-related derivatives gains of $47 million in 2022 and $0 in 2021 and 2020 are reflected in Net processing commodity expenses.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Director
Related Party Transaction [Line Items]
Revenue from Related Parties	$ 180
Related Party Costs	86
Equity Method Investee [Member]
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Current	87	$ 89
OperatingFeesAndCostsBilledToThirdParty	65	70	$ 79
Accounts Receivable, Related Parties, Current	17	9
Related Party Transaction, Expenses from Transactions with Related Party	1,346	948	348
Related Party Transaction, Other Revenues from Transactions with Related Party	$ 76	$ 46	$ 26

Revenue by Category (Details)

Revenue by Category (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ 17,773	$ 12,784	$ 7,653
Revenue Not from Contract with Customer	[1]	7,935	2,644	66
Revenue Not from Contract with Customer, Other	[2]	(14,743)	(4,801)
Total revenues		10,965	10,627	7,719
Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,067	2,955	2,846
NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,072	2,706	2,756
NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		260	238	129
Total revenues		260	238	129
Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		308	264	253
Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		6,707	6,163	5,984
Total revenues		6,536	6,001	5,924
Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		11,066	6,621	1,669
Total revenues		4,556	4,536	1,671
Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,885	2,645	2,494
Revenue Not from Contract with Customer	[1]	24	10	10
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		2,909	2,655	2,504
Transco [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,696	2,547	2,404
Transco [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Transco [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Transco [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		10	10	10
Transco [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,706	2,557	2,414
Transco [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		179	88	80
Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		443	441	449
Revenue Not from Contract with Customer	[1]	4	3	0
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		447	444	449
Northwest Pipeline [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		443	441	449
Northwest Pipeline [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Northwest Pipeline [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Northwest Pipeline [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Northwest Pipeline [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		443	441	449
Northwest Pipeline [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Gulf of Mexico Midstream and Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		707	687	510
Revenue Not from Contract with Customer	[1]	10	8	9
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		717	695	519
Gulf of Mexico Midstream and Storage [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Gulf of Mexico Midstream and Storage [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		365	344	348
Gulf of Mexico Midstream and Storage [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		64	52	21
Gulf of Mexico Midstream and Storage [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		27	22	27
Gulf of Mexico Midstream and Storage [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		456	418	396
Gulf of Mexico Midstream and Storage [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		251	269	114
Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,776	1,609	1,507
Revenue Not from Contract with Customer	[1]	26	25	22
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		1,802	1,634	1,529
Northeast Midstream [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Northeast Midstream [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,395	1,308	1,279
Northeast Midstream [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		14	7	7
Northeast Midstream [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		233	195	164
Northeast Midstream [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,642	1,510	1,450
Northeast Midstream [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		134	99	57
West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,553	2,058	1,514
Revenue Not from Contract with Customer	[1]	8	(32)	9
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		2,561	2,026	1,523
West Midstream [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
West Midstream [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,476	1,184	1,226
West Midstream [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		182	179	101
West Midstream [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		54	52	35
West Midstream [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,712	1,415	1,362
West Midstream [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		841	643	152
Gas & NGL Marketing Services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		10,771	6,407	1,634
Revenue Not from Contract with Customer	[1]	7,929	2,632	(3)
Revenue Not from Contract with Customer, Other	[2]	(15,467)	(4,828)
Total revenues		3,233	4,211	1,631
Gas & NGL Marketing Services | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Gas & NGL Marketing Services | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Gas & NGL Marketing Services | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Gas & NGL Marketing Services | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3	3	32
Gas & NGL Marketing Services | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3	3	32
Gas & NGL Marketing Services | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		10,768	6,404	1,602
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		706	334	1
Revenue Not from Contract with Customer	[1]	(55)	11	33
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		651	345	34
Other [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Other [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Other [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Other [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	1	1
Other [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	1	1
Other [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		706	333	0
Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(2,068)	(1,397)	(456)
Revenue Not from Contract with Customer	[1]	(11)	(13)	(14)
Revenue Not from Contract with Customer, Other	[2]	724	27
Total revenues		(1,355)	(1,383)	(470)
Intersegment Eliminations [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(72)	(33)	(7)
Intersegment Eliminations [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(164)	(130)	(97)
Intersegment Eliminations [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Intersegment Eliminations [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(19)	(19)	(16)
Intersegment Eliminations [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(255)	(182)	(120)
Intersegment Eliminations [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ (1,813)	$ (1,215)	$ (336)
[1] Revenues not derived from contracts with customers primarily consist of physical product sales related to derivative contracts, realized and unrealized gains and losses associated with our derivative contracts, which are reported in Net gain (loss) on commodity derivatives in the Consolidated Statement of Income, management fees that we receive for certain services we provide to operated equity-method investments, and leasing revenues associated with our headquarters building.

Revenue Recognition Contract As

Revenue Recognition Contract Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Contract With Customer, Asset [Line Items]
Contract with Customer, Asset, Net - Beginning of Period	$ 22	$ 12
Contract with Customer, Asset, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	208	184
Contract with Customer, Asset, Reclassified to Receivable	(201)	(174)
Contract with Customer, Asset, Net - End of Period	$ 29	$ 22

Revenue Recognition Contract Li

Revenue Recognition Contract Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Contract With Customer, Liability [Line Items]
Contract with Customer, Liability - Beginning of Period	$ 1,126	$ 1,209
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	180	116
Other Significant Noncash Transaction, Value of Consideration Received	9	10
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination	2	1
Contract with Customer, Liability, Revenue Recognized	(274)	(210)
Contract with Customer, Liability - End of Period	$ 1,043	$ 1,126

Revenue Recognition Contract _2

Revenue Recognition Contract Liabilities Performance Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	$ 1,043	$ 1,126	$ 1,209
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	142
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	122
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	117
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	112
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	101
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	$ 449
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period

Revenue Recognition Remaining P

Revenue Recognition Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2022 USD ($)
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 29,790
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,643
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,388
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,149
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	2,520
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	2,415
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 14,675
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period

Provision (Benefit) for Incom_3

Provision (Benefit) for Income Taxes Tax Provison (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current :
Federal	$ (25)	$ (1)	$ (29)
State	19	3	0
Total	(6)	2	(29)
Deferred:
Federal	424	421	98
State	7	88	10
Total	431	509	108
Less: Provision (benefit) for income taxes	$ 425	$ 511	$ 79

Provision (Benefit) for Incom_4

Provision (Benefit) for Income Taxes Reconciliations to Recorded Tax Provision (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Effective Income Tax Rate Reconciliation [Abstract]
Provision (benefit) at statutory rate	$ 534	$ 435	$ 58
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	113	71	6
State deferred income tax rate change	(92)	0	0
Federal valuation allowance	(70)	3	1
Federal settlements	(45)	0	0
Impact of nontaxable noncontrolling interests	(14)	(9)	3
Other – net	(1)	11	11
Less: Provision (benefit) for income taxes	$ 425	$ 511	$ 79

Provision (Benefit) for Incom_5

Provision (Benefit) for Income Taxes Deferred Tax Table (Details) - USD ($) $ in Millions	Dec. 31, 2022	Jun. 30, 2022	Dec. 31, 2021
Gross deferred income tax liabilities:
Property, plant and equipment	$ 3,171		$ 2,777
Investments	1,784		1,669
Other	138		154
Total gross deferred income tax liabilities	5,093		4,600
Gross deferred income tax assets:
Accrued liabilities	1,108		872
Foreign tax credits	91	$ 70	140
Federal loss carryovers	730		879
State losses and credits	356		421
Other	121		132
Total gross deferred income tax assets	2,406		2,444
Less valuation allowance	200		297
Net deferred income tax assets	2,206		2,147
Deferred income tax liabilities	$ 2,887		$ 2,453

Provision (Benefit) for Incom_6

Provision (Benefit) for Income Taxes Textuals (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jun. 30, 2022
Income Tax Contingency [Line Items]
Foreign income (loss) in Income from continuing operations before income taxes		$ (2)	$ (1)
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	$ 113	71	6
Deferred Tax Assets, Charitable Contribution Carryforwards	25
Deferred Tax Assets, Tax Credit Carryforwards	705
Income Taxes Paid	13
Proceeds from Income Tax Refunds		45	40
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	91	140		$ 70
Tax Adjustments, Settlements, and Unusual Provisions	45
Total interest and penalties recognized as part of income tax provision	(3)	(1)	$ (1)
Total interest and penalties accrued as uncertain tax positions	0	$ 4
Settlement with Taxing Authority
Income Tax Contingency [Line Items]
Proceeds from Income Tax Refunds	7
Less Than
Income Tax Contingency [Line Items]
Foreign income (loss) in Income from continuing operations before income taxes	$ 1

EBPs Funded Status (Details)

EBPs Funded Status (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Contribution Plan
Percentage of eligible compensation the employer will match of employee contributions		6%
Employer's contributions charged to expense under defined contribution plan		$ 53	$ 45	$ 42
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year		1,133	1,183
Service cost		28	30	31
Interest cost		31	28	36
Plan participants’ contributions		0	0
Benefits paid		(78)	(83)
Net actuarial loss (gain) (1)	[1]	(162)	(21)
Settlements		(12)	(4)
Net increase (decrease) in benefit obligation		(193)	(50)
Benefit obligation at end of year		940	1,133	1,183
Other Postretirement Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year		200	220
Service cost		1	1	1
Interest cost		6	5	7
Plan participants’ contributions		2	2
Benefits paid		(12)	(14)
Net actuarial loss (gain) (1)	[1]	(45)	(14)
Settlements		0	0
Net increase (decrease) in benefit obligation		(48)	(20)
Benefit obligation at end of year		$ 152	$ 200	$ 220
[1]2022 amounts are due primarily to the following factors: Pension benefits - discount rate assumptions, partially offset by change in interest crediting rate assumption; Other Postretirement Benefits - discount rate assumption. 2021 amounts are due primarily to the following factors: Pension Benefits - discount rate assumptions, partially offset by experience-related items; Other Postretirement Benefits - discount rate assumption and experience-related items.

EBP Asset rollforward and B.S.

EBP Asset rollforward and B.S. classification (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Net regulatory liabilities	$ 130	$ 150
Pension Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	1,336	1,357
Actual return on plan assets	(132)	62
Employer contributions	3	4
Plan participants’ contributions	0	0
Benefits paid	(78)	(83)
Settlements	(12)	(4)
Net increase (decrease) in fair value of plan assets	(219)	(21)
Fair value of plan assets at end of year	1,117	1,336
Funded status — overfunded (underfunded)	177	203
Amounts recognized in the Consolidated Balance Sheet:
Noncurrent assets	201	229
Current liabilities	(2)	(3)
Noncurrent liabilities	(22)	(23)
Funded status - overfunded (underfunded)	177	203
Accumulated benefit obligation	930	1,118
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	24	26
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	22	22
Fair value of plan assets	0	0
Amounts recognized in Accumulated other comprehensive income (loss):
Net actuarial gain (loss)	(45)	(46)
Other Postretirement Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	287	278
Actual return on plan assets	(27)	16
Employer contributions	3	5
Plan participants’ contributions	2	2
Benefits paid	(12)	(14)
Settlements	0	0
Net increase (decrease) in fair value of plan assets	(34)	9
Fair value of plan assets at end of year	253	287
Funded status — overfunded (underfunded)	101	87
Amounts recognized in the Consolidated Balance Sheet:
Noncurrent assets	105	91
Current liabilities	(4)	(4)
Noncurrent liabilities	0	0
Funded status - overfunded (underfunded)	101	87
Amounts recognized in Accumulated other comprehensive income (loss):
Net actuarial gain (loss)	$ 18	$ 4

EBP Net Periodic Benefit Cost &

EBP Net Periodic Benefit Cost & OCI (Details 2) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost		$ 28	$ 30	$ 31
Interest cost		31	28	36
Expected return on plan assets		(44)	(43)	(53)
Amortization of net actuarial loss		12	14	21
Net actuarial loss from settlements		3	1	9
Reclassification to regulatory liability		0	0	0
Net periodic benefit cost (credit) (1)	[1]	30	30	44
Items Recognized in Other Comprehensive Income (Loss)
Net actuarial gain (loss) arising during the year		(14)	40	112
Amortization of net actuarial loss		12	14	21
Net actuarial loss from settlements		3	1	9
Total recognized in Other comprehensive income (loss)		1	55	142
Other Postretirement Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost		1	1	1
Interest cost		6	5	7
Expected return on plan assets		(10)	(10)	(11)
Amortization of net actuarial loss		0	0	0
Net actuarial loss from settlements		0	0	0
Reclassification to regulatory liability		1	2	2
Net periodic benefit cost (credit) (1)	[1]	(2)	(2)	(1)
Items Recognized in Other Comprehensive Income (Loss)
Net actuarial gain (loss) arising during the year		14	29	(4)
Amortization of net actuarial loss		0	0	0
Net actuarial loss from settlements		0	0	0
Total recognized in Other comprehensive income (loss)		$ 14	$ 29	$ (4)
[1]Components other than Service cost are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income

EBP Key Assumptions (Details 3)

EBP Key Assumptions (Details 3)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	5.16%	2.82%	2.45%
Rate of compensation increase	3.58%	3.67%	3.76%
Cash balance interest crediting rate	3.50%	3%	3%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	2.84%	2.45%	3.08%
Expected long-term rate of return on plan assets	3.81%	3.69%	4.67%
Rate of compensation increase	3.67%	3.76%	3.68%
Cash balance interest crediting rate	3%	3%	3.50%
Other Postretirement Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	5.20%	2.93%	2.59%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	2.93%	2.59%	3.27%
Expected long-term rate of return on plan assets	3.67%	3.61%	4.39%
Health care cost trend rate assumed for next fiscal year	6.80%
Direction and pattern of change for assumed health care cost trend rate	decreases
Ultimate health care cost trend rate	4.50%
Year that rate reaches ultimate trend rate	2032

EBP Plan Assets (Details 4)

EBP Plan Assets (Details 4) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Redemption notification period restrictions for commingled investment funds		15 days
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Redemption notification period restrictions for commingled investment funds		1 day
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		$ 1,117	$ 1,336	$ 1,357
Pension Benefits [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	104	175
Pension Benefits [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	306	399
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		$ 410	574
Pension Benefits [Member] | Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Plan asset target allocation		75%
Pension Benefits [Member] | Cash management funds | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	$ 45	37
Pension Benefits [Member] | Cash management funds | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	0	0
Pension Benefits [Member] | Cash management funds | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		$ 45	37
Pension Benefits [Member] | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Plan asset target allocation		25%
Pension Benefits [Member] | Equity securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]		42
Pension Benefits [Member] | Equity securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]		19
Pension Benefits [Member] | Equity securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value			61
Pension Benefits [Member] | Government debt securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	$ 58	99
Pension Benefits [Member] | Government debt securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	18	28
Pension Benefits [Member] | Government debt securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		76	127
Pension Benefits [Member] | Corporate debt securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	0	0
Pension Benefits [Member] | Corporate debt securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	284	350
Pension Benefits [Member] | Corporate debt securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		284	350
Pension Benefits [Member] | Mutual fund - Municipal bonds | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]		0
Pension Benefits [Member] | Mutual fund - Municipal bonds | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]		0
Pension Benefits [Member] | Mutual fund - Municipal bonds | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value			0
Pension Benefits [Member] | Other | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	1	(3)
Pension Benefits [Member] | Other | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	4	2
Pension Benefits [Member] | Other | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		5	(1)
Pension Benefits [Member] | Commingled investment funds - equities | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[3]	273	288
Pension Benefits [Member] | Commingled investment funds - fixed income | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[3]	434	474
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		253	287	$ 278
Other Postretirement Benefits [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	113	124
Other Postretirement Benefits [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	42	61
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		155	185
Other Postretirement Benefits [Member] | Cash management funds | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	105	14
Other Postretirement Benefits [Member] | Cash management funds | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	0	0
Other Postretirement Benefits [Member] | Cash management funds | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		105	14
Other Postretirement Benefits [Member] | Equity securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]		39
Other Postretirement Benefits [Member] | Equity securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]		10
Other Postretirement Benefits [Member] | Equity securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value			49
Other Postretirement Benefits [Member] | Government debt securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	8	13
Other Postretirement Benefits [Member] | Government debt securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	3	4
Other Postretirement Benefits [Member] | Government debt securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		11	17
Other Postretirement Benefits [Member] | Corporate debt securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	0	0
Other Postretirement Benefits [Member] | Corporate debt securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	39	47
Other Postretirement Benefits [Member] | Corporate debt securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		39	47
Other Postretirement Benefits [Member] | Mutual fund - Municipal bonds | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]		59
Other Postretirement Benefits [Member] | Mutual fund - Municipal bonds | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]		0
Other Postretirement Benefits [Member] | Mutual fund - Municipal bonds | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value			59
Other Postretirement Benefits [Member] | Other | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	0	(1)
Other Postretirement Benefits [Member] | Other | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	0	0
Other Postretirement Benefits [Member] | Other | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		0	(1)
Other Postretirement Benefits [Member] | Commingled investment funds - equities | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[3]	38	39
Other Postretirement Benefits [Member] | Commingled investment funds - fixed income | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[3]	$ 60	$ 63
[1]Level 1 includes assets with fair values based on quoted prices in active markets for identical assets. Cash management funds, equity securities traded on U.S. exchanges, U.S. Treasury securities, and mutual funds are included in this level.[2]Level 2 includes assets with fair values determined by using significant other observable inputs. This level includes equity securities traded on active foreign exchanges and fixed income securities, other than U.S. Treasury securities, that are valued primarily using pricing models which incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.[3]The commingled investment funds are measured at fair value using net asset value per share. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 1 day to 15 days.

EBP Benefit Pymts & Employer Co

EBP Benefit Pymts & Employer Contributions (Details 5) $ in Millions	Dec. 31, 2022 USD ($)
Pension Benefits [Member]
Expected benefit payments
2023	$ 84
2024	83
2025	84
2026	81
2027	80
2028-2032	389
Expected total plans contribution, approximate	1
Other Postretirement Benefits [Member]
Expected benefit payments
2023	13
2024	13
2025	12
2026	12
2027	11
2028-2032	52
Expected total plans contribution, approximate	$ 4

Investing Activities (Details)

Investing Activities (Details) - USD ($) $ in Millions				12 Months Ended
		Nov. 18, 2020	Dec. 31, 2019	Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Schedule of Investments [Line Items]
Income (Loss) from Equity Method Investments				$ (637)		$ (608)		$ (328)
Impairment of equity-method investments				0		0		1,046
Other investing income (loss) - net				16		7		8
Equity-method investment, payments to purchase or contributions				166		115		325
Equity-method investments				5,048		5,121
Other Investments and Securities, at Cost				17		6
Investments				5,065		5,127
Equity-method investment, difference between carrying amount and underlying equity				1,100		1,200
Distributions from equity-method investees (Note 8)				865		757		653
Current assets				3,797		4,549
Current liabilities				(4,890)		(4,972)
Revenues				10,965		10,627		7,719
Operating income				1,268		1,191		508
Net income				2,117		1,562		198
Equity Method Investee [Member]
Schedule of Investments [Line Items]
Accounts Payable, Related Parties, Current				87		89
OperatingFeesAndCostsBilledToThirdParty				65		70		79
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Schedule of Investments [Line Items]
Current assets				964		743
Noncurrent assets				12,701		13,211
Current liabilities				(632)		(435)
Noncurrent liabilities				(3,789)		(3,774)
Revenues				5,520		4,688		2,625
Net income				$ 1,102		1,006		459
Appalachia Midstream Investments [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				66%
Income (Loss) from Equity Method Investments								26
Equity-method investment, payments to purchase or contributions				$ 83		84		116
Equity-method investments	[1]			2,975		3,056
Equity-method investment, difference between carrying amount and underlying equity				1,100		1,200
Distributions from equity-method investees (Note 8)				$ 415		433		357
Rocky Mountain Midstream Holdings LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50%
Income (Loss) from Equity Method Investments								78
Equity-method investments				$ 395		401
Distributions from equity-method investees (Note 8)				$ 52		45		39
Discovery Producer Services LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				60%
Equity-method investment, payments to purchase or contributions				$ 41		0		0
Equity-method investments				345		328
Distributions from equity-method investees (Note 8)				$ 49		44		21
Blue Racer Midstream Holdings LLC
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions	[2]							157
Distributions from equity-method investees (Note 8)	[3]							47
Overland Pass Pipeline Company LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50%
Equity-method investments				$ 386		388
Distributions from equity-method investees (Note 8)				$ 34		26		50
Laurel Mountain Midstream, LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				69%
Income (Loss) from Equity Method Investments								11
Equity-method investments				$ 205		226
Distributions from equity-method investees (Note 8)				$ 112		33		31
Gulfstream Natural Gas System, LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50%
Equity-method investment, payments to purchase or contributions				$ 14		26		3
Equity-method investments				220		215
Distributions from equity-method investees (Note 8)				89		90		93
Other [Member]
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions				12		2		49
Equity-method investments				139		130
Distributions from equity-method investees (Note 8)				65		39		15
Total Equity Method Investment [Member]
Schedule of Investments [Line Items]
Distributions from equity-method investees (Note 8)				$ 865		757		653
Blue Racer Midstream LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50%
Income (Loss) from Equity Method Investments								10
Equity-method investment, payments to purchase or contributions		$ 157		$ 0	[2]	3	[2]
Equity-method investments				383		377
Distributions from equity-method investees (Note 8)	[3]			49		47
Cardinal Pipeline Company, LLC
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions				$ 16		$ 0		$ 0
Northeast G And P [Member] | Blue Racer Midstream Holdings LLC
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage			58%
Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				69%
Northeast G And P [Member] | Blue Racer Midstream LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50%		50%
West [Member] | Rocky Mountain Midstream Holdings LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50%
West [Member] | Overland Pass Pipeline Company LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50%
West [Member] | Targa Train 7 LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				20%
Caiman Energy II Acquisition [Member] | Blue Racer Midstream Holdings LLC
Schedule of Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		41%
Blue Racer Midstream Holdings LLC | Blue Racer Midstream LLC [Member]
Schedule of Investments [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest			50%
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%
[1]Includes equity-method investments in multiple gathering systems in the Marcellus Shale region with an approximate average 66 percent interest.[2] See following discussion in the section Acquisition of additional interests in BRMH below. See previous discussion in the section Acquisition of additional interests in BRMH above.

Property, Plant, and Equipmen_2

Property, Plant, and Equipment (Details PPE) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 47,057	$ 44,184
Accumulated depreciation and amortization		(16,168)	(14,926)
Property, plant, and equipment - net		30,889	29,258
Depreciation and amortization expenses		1,498	1,496	$ 1,393
Nonregulated [Member] | Natural gas gathering and processing facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		19,163	18,203
Nonregulated [Member] | Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		997	331
Nonregulated [Member] | Oil and Gas Properties
Property, Plant, and Equipment
Property, plant, and equipment, at cost		874	572
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		2,998	2,649
Regulated [Member] | Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		19,521	19,201
Regulated [Member] | Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		708	475
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		2,796	2,753
Regulated [Member] | Acquisition Adjustment Of Regulated Facilities [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Plant Acquisition Adjustments for Intangible Utility Plants		$ 428	$ 468
Period of straight-line amortization		40 years
Minimum [Member] | Nonregulated [Member] | Natural gas gathering and processing facilities [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	5 years
Minimum [Member] | Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	0 years
Minimum [Member] | Regulated [Member] | Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, Plant, and Equipment, Depreciation Rate	[1]	1.25%
Minimum [Member] | Regulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	5 years
Property, Plant, and Equipment, Depreciation Rate	[1]	0%
Maximum [Member] | Nonregulated [Member] | Natural gas gathering and processing facilities [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	40 years
Maximum [Member] | Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	45 years
Maximum [Member] | Regulated [Member] | Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, Plant, and Equipment, Depreciation Rate	[1]	7.13%
Maximum [Member] | Regulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	45 years
Property, Plant, and Equipment, Depreciation Rate	[1]	33.33%
[1](1)    Estimated useful life and depreciation rates are presented as of December 31, 2022. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

Property, Plant, and Equipmen_3

Property, Plant, and Equipment (Details ARO) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligations
Asset Retirement Obligations, Noncurrent		$ 1,827	$ 1,590
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year		1,665	1,222
Liabilities incurred (1)	[1]	77	336
Liabilities settled		(22)	(25)
Accretion		85	73
Revisions (2)	[2]	109	59
Balance at end of year		1,914	1,665
Unusual or Infrequent Item [Line Items]
Asset Retirement Obligation, Liabilities Incurred	[1]	77	336
Upstream Equipment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities incurred (1)			307
Unusual or Infrequent Item [Line Items]
Asset Retirement Obligation, Liabilities Incurred			$ 307
Asset Retirement Obligation Costs [Member]
Unusual or Infrequent Item [Line Items]
Transco's annual funding commitment for ARO		$ 16
[1]Includes $307 million of ARO in 2021 related to acquired upstream properties.[2]Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2022 revisions reflect changes in removal cost estimates and increases in inflation rates, partially offset by increases in discount rates. The 2021 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and increases in inflation rates.

Intangible Assets (Details)

Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	$ 10,338	$ 9,866
Finite-Lived Intangible Assets, Accumulated Amortization	(2,975)	(2,464)
Customer relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	10,065	9,593
Finite-Lived Intangible Assets, Accumulated Amortization	$ (2,801)	(2,448)
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	30 years
Amortization of Intangible Assets	$ 353	332	$ 328
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	357
Finite-Lived Intangible Assets, Amortization Expense, Year Two	357
Finite-Lived Intangible Assets, Amortization Expense, Year Three	357
Finite-Lived Intangible Assets, Amortization Expense, Year Four	357
Finite-Lived Intangible Assets, Amortization Expense, Year Five	357
Transportation and Storage Capacity [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	267	267
Finite-Lived Intangible Assets, Accumulated Amortization	(172)	(14)
Amortization of Intangible Assets	158	14
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	51
Finite-Lived Intangible Assets, Amortization Expense, Year Two	21
Finite-Lived Intangible Assets, Amortization Expense, Year Three	10
Finite-Lived Intangible Assets, Amortization Expense, Year Four	7
Finite-Lived Intangible Assets, Amortization Expense, Year Five	4
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	6	6
Finite-Lived Intangible Assets, Accumulated Amortization	$ (2)	$ (2)

Accrued and Other Current Lia_3

Accrued and Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Accrued Liabilities [Line Items]
Interest on debt	$ 274	$ 277
Employee costs	218	214
Regulatory Liabilities, Current	201	56
Contract liabilities	141	134
Asset Retirement Obligation, Current	87	75
Operating Lease, Liability, Current	25	23
Other, including accrued loss contingencies	324	256
Other accrued liabilities	$ 1,270	$ 1,035

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2022	Oct. 17, 2022	Aug. 08, 2022	May 16, 2022	Jan. 18, 2022	Dec. 31, 2021	Oct. 08, 2021	Mar. 02, 2021	May 14, 2020	May 08, 2020
Long-term Debt
Unamortized debt issuance costs	$ (135)					$ (131)
Net unamortized debt premium (discount)	(55)					(56)
Total long-term debt, including current portion	22,554					23,675
Long-term debt due within one year	(627)					(2,025)
Long-term debt	21,927					21,650
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.08% Debentures Due 2026 [Member]
Long-term Debt
Long-term debt	$ 8					8
Long-term debt interest rate	7.08%
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.25% Debentures Due 2026 [Member]
Long-term Debt
Long-term debt	$ 200					200
Long-term debt interest rate	7.25%
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.85% Senior Unsecured Notes Due 2026 [Member]
Long-term Debt
Long-term debt	$ 1,000					1,000
Long-term debt interest rate	7.85%
Transcontinental Gas Pipe Line Company, LLC [Member] | 4% Senior Unsecured Notes Due 2028 [Member]
Long-term Debt
Long-term debt	$ 400					400
Long-term debt interest rate	4%
Transcontinental Gas Pipe Line Company, LLC [Member] | 3.25 Percent Senior Unsecured Notes Due 2030 [Member]
Long-term Debt
Long-term debt	$ 700					700
Long-term debt interest rate	3.25%									3.25%
Transcontinental Gas Pipe Line Company, LLC [Member] | 5.4% Senior Unsecured Notes Due 2041 [Member]
Long-term Debt
Long-term debt	$ 375					375
Long-term debt interest rate	5.40%
Transcontinental Gas Pipe Line Company, LLC [Member] | 4.45% Senior Unsecured Notes Due 2042 [Member]
Long-term Debt
Long-term debt	$ 400					400
Long-term debt interest rate	4.45%
Transcontinental Gas Pipe Line Company, LLC [Member] | 4.6% Senior Unsecured Notes Due 2048 [Member]
Long-term Debt
Long-term debt	$ 600					600
Long-term debt interest rate	4.60%
Transcontinental Gas Pipe Line Company, LLC [Member] | 3.95 Percent Senior Unsecured Notes Due 2050 [Member]
Long-term Debt
Long-term debt	$ 500					500
Long-term debt interest rate	3.95%									3.95%
Transcontinental Gas Pipe Line Company, LLC [Member] | Atlantic Sunrise [Member]
Long-term Debt
Other financing obligations	$ 809					830
Long-term debt interest rate	9%
Transcontinental Gas Pipe Line Company, LLC [Member] | Leidy South
Long-term Debt
Other financing obligations	$ 77					72
Long-term debt interest rate	13%
Transcontinental Gas Pipe Line Company, LLC [Member] | Dalton [Member]
Long-term Debt
Other financing obligations	$ 252					254
Long-term debt interest rate	9%
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%
The Williams Companies, Inc. [Member]
Long-term Debt
Credit facility loans	$ 0
The Williams Companies, Inc. [Member] | 3.35% Senior Unsecured Notes Due 2022 [Member]
Long-term Debt
Long-term debt	$ 0					750
Long-term debt interest rate	3.35%			3.35%
The Williams Companies, Inc. [Member] | 3.6% Senior Unsecured Notes Due 2022 [Member]
Long-term Debt
Long-term debt	$ 0					1,250
Long-term debt interest rate	3.60%				3.60%
The Williams Companies, Inc. [Member] | 3.7% Senior Unsecured Notes Due 2023 [Member]
Long-term Debt
Long-term debt	$ 0					850
Long-term debt interest rate	3.70%	3.70%
The Williams Companies, Inc. [Member] | 4.5% Senior Unsecured Notes Due 2023 [Member]
Long-term Debt
Long-term debt	$ 600					600
Long-term debt interest rate	4.50%
The Williams Companies, Inc. [Member] | 4.3% Senior Unsecured Notes Due 2024 [Member]
Long-term Debt
Long-term debt	$ 1,000					1,000
Long-term debt interest rate	4.30%
The Williams Companies, Inc. [Member] | 4.55% Senior Unsecured Notes Due 2024 [Member]
Long-term Debt
Long-term debt	$ 1,250					1,250
Long-term debt interest rate	4.55%
The Williams Companies, Inc. [Member] | 3.9% Senior Unsecured Notes Due 2025 [Member]
Long-term Debt
Long-term debt	$ 750					750
Long-term debt interest rate	3.90%
The Williams Companies, Inc. [Member] | 4% Senior Unsecured Notes Due 2025 [Member]
Long-term Debt
Long-term debt	$ 750					750
Long-term debt interest rate	4%
The Williams Companies, Inc. [Member] | 3.75% Senior Unsecured Notes Due 2027 [Member]
Long-term Debt
Long-term debt	$ 1,450					1,450
Long-term debt interest rate	3.75%
The Williams Companies, Inc. [Member] | 3.5 Percent Senior Unsecured Notes Due 2030 [Member]
Long-term Debt
Long-term debt	$ 1,000					1,000
Long-term debt interest rate	3.50%								3.50%
The Williams Companies, Inc. [Member] | 7.5% Debentures Due 2031 [Member]
Long-term Debt
Long-term debt	$ 339					339
Long-term debt interest rate	7.50%
The Williams Companies, Inc. [Member] | 7.75% Senior Unsecured Notes Due 2031 [Member]
Long-term Debt
Long-term debt	$ 252					252
Long-term debt interest rate	7.75%
The Williams Companies, Inc. [Member] | 8.75% Senior Unsecured Notes Due 2032 [Member]
Long-term Debt
Long-term debt	$ 445					445
Long-term debt interest rate	8.75%
The Williams Companies, Inc. [Member] | 6.3% Senior Unsecured Notes Due 2040 [Member]
Long-term Debt
Long-term debt	$ 1,250					1,250
Long-term debt interest rate	6.30%
The Williams Companies, Inc. [Member] | 5.8% Senior Unsecured Notes Due 2043 [Member]
Long-term Debt
Long-term debt	$ 400					400
Long-term debt interest rate	5.80%
The Williams Companies, Inc. [Member] | 5.4% Senior Unsecured Notes Due 2044 [Member]
Long-term Debt
Long-term debt	$ 500					500
Long-term debt interest rate	5.40%
The Williams Companies, Inc. [Member] | 5.75% Senior Unsecured Notes Due 2044 [Member]
Long-term Debt
Long-term debt	$ 650					650
Long-term debt interest rate	5.75%
The Williams Companies, Inc. [Member] | 4.9% Senior Unsecured Notes Due 2045 [Member]
Long-term Debt
Long-term debt	$ 500					500
Long-term debt interest rate	4.90%
The Williams Companies, Inc. [Member] | 5.1% Senior Unsecured Notes Due 2045 [Member]
Long-term Debt
Long-term debt	$ 1,000					1,000
Long-term debt interest rate	5.10%
The Williams Companies, Inc. [Member] | 4.85 Percent Senior Unsecured Notes Due 2048 [Member]
Long-term Debt
Long-term debt	$ 800					800
Long-term debt interest rate	4.85%
The Williams Companies, Inc. [Member] | 3.5 Percent Senior Unsecured Notes Due 2051
Long-term Debt
Long-term debt	$ 650					650
Long-term debt interest rate	3.50%						3.50%
The Williams Companies, Inc. [Member] | 2.6 Percent Senior Unsecured Notes Due 2031
Long-term Debt
Long-term debt	$ 1,500					1,500
Long-term debt interest rate	2.60%						2.60%	2.60%
The Williams Companies, Inc. [Member] | Various - 7.7% to 8.72% Notes due 2022 to 2027 [Member]
Long-term Debt
Long-term debt	$ 2					2
The Williams Companies, Inc. [Member] | Various - 7.7 to 8.72 Percent Notes Due 2022 to 2027 Minimum Interest Rate [Member]
Long-term Debt
Long-term debt interest rate	7.70%
The Williams Companies, Inc. [Member] | Various - 7.7% to 8.72% Notes Due 2022 to 2027 Maximum Interest Rate [Member]
Long-term Debt
Long-term debt interest rate	8.72%
The Williams Companies, Inc. [Member] | 4.65 Percent Senior Unsecured Notes Due 2032
Long-term Debt
Long-term debt	$ 1,000					0
Long-term debt interest rate	4.65%		4.65%
The Williams Companies, Inc. [Member] | 5.3 Percent Senior Unsecured Notes Due 2052
Long-term Debt
Long-term debt	$ 750					$ 0
Long-term debt interest rate	5.30%		5.30%

Long-Term Debt Maturities (Deta

Long-Term Debt Maturities (Details) $ in Millions	Dec. 31, 2022 USD ($)
Aggregate minimum maturities of long-term debt
2023	$ 629
2024	2,281
2025	1,619
2026	1,245
2027	$ 1,993

Long-Term Debt Issuances and Re

Long-Term Debt Issuances and Retirements (Details) - USD ($) $ in Millions	Oct. 17, 2022	May 16, 2022	Jan. 18, 2022	Sep. 01, 2021	Aug. 16, 2021	Aug. 17, 2020	Mar. 15, 2020	Jan. 15, 2020	Dec. 31, 2022	Aug. 08, 2022	Dec. 31, 2021	Oct. 08, 2021	Mar. 02, 2021	May 14, 2020	May 08, 2020
The Williams Companies, Inc. [Member] | 3.7% Senior Unsecured Notes Due 2023 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 850
Long-term debt interest rate	3.70%								3.70%
Long-term debt									$ 0		$ 850
The Williams Companies, Inc. [Member] | 4.65 Percent Senior Unsecured Notes Due 2032
Debt Instrument [Line Items]
Long-term debt interest rate									4.65%	4.65%
Long-term debt face amount										$ 1,000
Long-term debt									$ 1,000		0
The Williams Companies, Inc. [Member] | 5.3 Percent Senior Unsecured Notes Due 2052
Debt Instrument [Line Items]
Long-term debt interest rate									5.30%	5.30%
Long-term debt face amount										$ 750
Long-term debt									$ 750		0
The Williams Companies, Inc. [Member] | 3.35% Senior Unsecured Notes Due 2022 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount		$ 750
Long-term debt interest rate		3.35%							3.35%
Long-term debt									$ 0		750
The Williams Companies, Inc. [Member] | 3.6% Senior Unsecured Notes Due 2022 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount			$ 1,250
Long-term debt interest rate			3.60%						3.60%
Long-term debt									$ 0		1,250
The Williams Companies, Inc. [Member] | 2.6 Percent Senior Unsecured Notes Due 2031
Debt Instrument [Line Items]
Long-term debt interest rate									2.60%			2.60%	2.60%
Long-term debt face amount												$ 600	$ 900
Long-term debt									$ 1,500		1,500
The Williams Companies, Inc. [Member] | 3.5 Percent Senior Unsecured Notes Due 2051
Debt Instrument [Line Items]
Long-term debt interest rate									3.50%			3.50%
Long-term debt face amount												$ 650
Long-term debt									$ 650		650
The Williams Companies, Inc. [Member] | 7.875% Senior Unsecured Notes Due 2021 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount				$ 371
Long-term debt interest rate				7.875%
The Williams Companies, Inc. [Member] | 4% Senior Unsecured Notes Due 2021 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount					$ 500
Long-term debt interest rate					4%
The Williams Companies, Inc. [Member] | 4.125% Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount						$ 600
Long-term debt interest rate						4.125%
The Williams Companies, Inc. [Member] | 3.5 Percent Senior Unsecured Notes Due 2030 [Member]
Debt Instrument [Line Items]
Long-term debt interest rate									3.50%					3.50%
Long-term debt face amount														$ 1,000
Long-term debt									$ 1,000		1,000
The Williams Companies, Inc. [Member] | 5.25% Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount							$ 1,500
Long-term debt interest rate							5.25%
The Williams Companies, Inc. [Member] | 8.75 Percent Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount								$ 14
Long-term debt interest rate								8.75%
Transcontinental Gas Pipe Line Company, LLC [Member] | 3.25 Percent Senior Unsecured Notes Due 2030 [Member]
Debt Instrument [Line Items]
Long-term debt interest rate									3.25%						3.25%
Long-term debt face amount															$ 700
Long-term debt									$ 700		700
Transcontinental Gas Pipe Line Company, LLC [Member] | 3.95 Percent Senior Unsecured Notes Due 2050 [Member]
Debt Instrument [Line Items]
Long-term debt interest rate									3.95%						3.95%
Long-term debt face amount															$ 500
Long-term debt									$ 500		$ 500
Transcontinental Gas Pipe Line Company, LLC [Member] | Atlantic Sunrise [Member]
Debt Instrument [Line Items]
Long-term debt interest rate									9%
Transcontinental Gas Pipe Line Company, LLC [Member] | Leidy South
Debt Instrument [Line Items]
Long-term debt interest rate									13%
Transcontinental Gas Pipe Line Company, LLC [Member] | Dalton [Member]
Debt Instrument [Line Items]
Long-term debt interest rate									9%

Credit Facility and Commercial

Credit Facility and Commercial Paper (Details) $ in Millions	Oct. 08, 2021 USD ($)	Aug. 10, 2018 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Sep. 30, 2021 USD ($)
Credit Facility and Commercial Paper [Line Items]
Commercial paper, outstanding			$ 350	$ 0
Short-Term Debt, Weighted Average Interest Rate, at Point in Time			4.80%
Williams Companies Inc [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 3,750		$ 3,750		$ 4,500
Credit facility, loans outstanding			0
Additional amount by which credit facility can be increased	$ 500
Maximum ratio of debt to EBITDA after acquisition	5.5
Acquisition Trigger Amount	$ 25
Williams Companies Inc [Member] | Swing Line Loan [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	200
Williams Companies Inc [Member] | Commercial paper [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	3,500	$ 4,000
Commercial paper, outstanding			350	$ 0
Commercial paper, maximum maturity		397 days
Williams Companies Inc [Member] | Letters of credit [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 500
Williams Companies Inc [Member] | Letters Of Credit Under Certain Bilateral Bank Agreements [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, letters of credit outstanding			$ 30
Transcontinental Gas Pipe Line Company, LLC [Member]
Credit Facility and Commercial Paper [Line Items]
Maximum ratio of debt to capitalization	65%
Transcontinental Gas Pipe Line Company, LLC [Member] | Letters of credit [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 500
Northwest Pipeline LLC [Member]
Credit Facility and Commercial Paper [Line Items]
Maximum ratio of debt to capitalization	65%
Northwest Pipeline LLC [Member] | Letters of credit [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 500
Dec21 And Subsequent Quarters [Member] | Williams Companies Inc [Member]
Credit Facility and Commercial Paper [Line Items]
Maximum ratio of debt to EBITDA	5

Cash Payments For Interest (Net

Cash Payments For Interest (Net of Amounts Capitalized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
Cash payments for interest (net of amounts capitalized)	$ 1,117	$ 1,137	$ 1,149

Leases (Details)

Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	$ 34	$ 35	$ 37
Variable Lease, Cost	26	15	19
Sublease Income	0	(1)	(1)
Lease, Cost	60	49	55
Operating Lease, Payments	$ 33	$ 35	$ 30
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Operating Lease, Right-of-Use Asset	$ 162	$ 159
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Accrued Liabilities, Current	Accrued Liabilities, Current
Operating Lease, Liability, Current	$ 25	$ 23
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities and Deferred Revenue, Noncurrent	Other Liabilities and Deferred Revenue, Noncurrent
Operating Lease, Liability, Noncurrent	$ 148	$ 141
Operating Lease, Weighted Average Remaining Lease Term	13 years	13 years
Operating Lease, Weighted Average Discount Rate, Percent	4.62%	4.56%
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 31
Lessee, Operating Lease, Liability, Payments, Due Year Two	26
Lessee, Operating Lease, Liability, Payments, Due Year Three	20
Lessee, Operating Lease, Liability, Payments, Due Year Four	20
Lessee, Operating Lease, Liability, Payments, Due Year Five	19
Lessee, Operating Lease, Liability, Payments, Due after Year Five	122
Lessee, Operating Lease, Liability, Payments, Due	238
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	65
Other Liabilities
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	$ 173

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Apr. 28, 2020
Williams Companies Incentive Plan [Member]
Equity-Based Compensation (Textuals) [Abstract]
Shares authorized for issuance	50,000			10,000
Shares reserved for future issuance	25,000
Shares available for future grants	15,000
Equity-based compensation expense	$ 73	$ 81	$ 52
Tax benefit from equity-based compensation expense	18	$ 20	$ 13
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized [Abstract]
Unrecognized equity-based compensation expense	$ 63
Unrecognized equity-based compensation expense, Weighted-average period of recognition in years	1 year 8 months 12 days
Williams Companies Incentive Plan [Member] | Nonvested Restricted Stock Units [Member]
Rollforward of nonvested restricted stock unit activity and related information
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	6,900	7,300
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 23.63	$ 22.35
Williams Companies Incentive Plan [Member] | Performance Shares [Member]
Rollforward of nonvested restricted stock unit activity and related information
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	2,600
Williams Companies Incentive Plan [Member] | Performance Shares [Member] | Minimum [Member]
Rollforward of nonvested restricted stock unit activity and related information
Range of vested shares based on extent to which certain financial targets are achieved	0%
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%
Williams Companies Incentive Plan [Member] | Stock options [Member]
Rollforward of stock option activity and related information
Options, Granted	0	0	0
Options Outstanding, Ending Balance	2,800
Options Exercisable at Period End	2,800
Options, Weighted Average Exercise Price, Ending Balance	$ 34.32
Options, Weighted Average Exercise Price, Exercisable at Period End	$ 34.32
Stock Options Outstanding, Weighted Average Remaining Contractual Life	2 years 9 months 18 days
Stock Options Exercisable, Weighted Average Remaining Contractual Life	2 years 9 months 18 days
Proceeds from Stock Options Exercised	$ 49
Tax benefits realized on options exercised	$ 2
Employee Stock Purchase Plan [Member]
Equity-Based Compensation (Textuals) [Abstract]
Shares authorized for issuance	5,200			1,600
Shares available for future grants	1,200
No. of shares purchases by employees	242
Average price of shares purchased	$ 24.57

Fair Value Measurements and Gua

Fair Value Measurements and Guarantees Recurring Measurements and Additional (Details) - USD ($) $ in Millions	Dec. 31, 2022		Dec. 31, 2021
Additional disclosures:
Collateral Already Posted, Aggregate Fair Value	$ 202		$ 296
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities and Deferred Revenue, Noncurrent
Carrying Amount [Member]
Additional disclosures:
Long-term debt, including current portion	$ (22,554)		(23,675)
Guarantees	(38)		(39)
Fair Value [Member]
Additional disclosures:
Long-term debt, including current portion	(21,569)		(27,768)
Guarantees	(25)		(26)
Level 1 [Member]
Additional disclosures:
Long-term debt, including current portion	0		0
Guarantees	0		0
Collateral Already Posted, Aggregate Fair Value	202		296
Level 2 [Member]
Additional disclosures:
Long-term debt, including current portion	(21,569)		(27,768)
Guarantees	(9)		(10)
Level 3 [Member]
Additional disclosures:
Long-term debt, including current portion	0		0
Guarantees	(16)		(16)
Fair Value, Recurring [Member] | Carrying Amount [Member]
Measured on a recurring basis
ARO Trust investments	230		260
Derivative Asset, Fair Value, Gross Asset	166	[1]	84	[2]
Derivative Liability, Fair Value, Gross Liability	(810)	[1]	(488)	[2]
Financial Liabilities Fair Value Disclosure	(5)		(7)
Fair Value, Recurring [Member] | Fair Value [Member]
Measured on a recurring basis
ARO Trust investments	230		260
Derivative Asset, Fair Value, Gross Asset	166	[1]	84	[2]
Derivative Liability, Fair Value, Gross Liability	(810)	[1]	(488)	[2]
Financial Liabilities Fair Value Disclosure	(5)		(7)
Fair Value, Recurring [Member] | Level 1 [Member]
Measured on a recurring basis
ARO Trust investments	230		260
Derivative Asset, Fair Value, Gross Asset	20	[1]	2	[2]
Derivative Liability, Fair Value, Gross Liability	(22)	[1]	(69)	[2]
Financial Liabilities Fair Value Disclosure	0		0
Fair Value, Recurring [Member] | Level 2 [Member]
Measured on a recurring basis
ARO Trust investments	0		0
Derivative Asset, Fair Value, Gross Asset	132	[1]	81	[2]
Derivative Liability, Fair Value, Gross Liability	(718)	[1]	(403)	[2]
Financial Liabilities Fair Value Disclosure	(5)		(7)
Fair Value, Recurring [Member] | Level 3 [Member]
Measured on a recurring basis
ARO Trust investments	0		0
Derivative Asset, Fair Value, Gross Asset	14	[1]	1	[2]
Derivative Liability, Fair Value, Gross Liability	(70)	[1]	(16)	[2]
Financial Liabilities Fair Value Disclosure	0		$ 0
Wiltel Guarantee [Member]
Additional disclosures:
Guarantor Obligations, Maximum Exposure, Undiscounted	24
Indemnification Agreement [Member] | Carrying Amount [Member]
Additional disclosures:
Guarantees	$ 0
[1]Net commodity derivative assets and liabilities exclude $202 million of net cash collateral in Level 1.[2]Net commodity derivative assets and liabilities exclude $296 million of net cash collateral in Level 1.

Fair Value Net Derivative Asset

Fair Value Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period	$ (15)	$ (2)
Gains (losses) included in the Consolidated Statement of Income	(31)	(62)
Purchases, issuances, and settlements	(5)	13
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	(24)	0
Transfers out of Level 3	19	12
Balance at end of period	(56)	(15)
Sequent Acquisition
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	$ 0	$ 24

Fair Value Measurements Nonrecu

Fair Value Measurements Nonrecurring Measurements (Details) - USD ($) $ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Jun. 30, 2021

Dec. 31, 2020

Mar. 31, 2020

Mar. 31, 2020

Mar. 31, 2020

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets (Note 15)

$ 0

$ 2

$ 182

Impairment of equity-method investments

0

0

1,046

Share Price Change

26%

40%

Goodwill, Impairment Loss

0

0

187

Noncontrolling Interests

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Goodwill, Impairment Loss

$ 65

Level 3 [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Goodwill, Impairment Loss

187

Level 3 [Member] | Property, plant, and equipment, net [Member] | Transmission And Gulf Of Mexico [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of property, plant, and equipment

[1]

$ 1

$ 42

42

Level 3 [Member] | Investments [Member] | Transmission And Gulf Of Mexico [Member] | Discovery Producer Services LLC [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

[2]

$ 367

$ 367

367

Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Blue Racer Midstream Holdings LLC | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

[2]

191

191

191

Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Aux Sable Liquid Products LP [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

[2]

7

7

7

Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

[2]

236

236

236

Level 3 [Member] | Investments [Member] | West [Member] | Rocky Mountain Midstream Holdings LLC [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

421

[3]

557

[4]

557

[4]

557

[4]

421

[3]

Level 3 [Member] | Investments [Member] | West [Member] | Brazos Permian II, LLC [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

[4]

0

$ 0

$ 0

Level 2 [Member] | Property Plant And Equipment, Net And Intangible Assets, Net Of Accumulated Amortization [Member] | Northeast G And P [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Property Plant And Equipment And Intangibles, Fair Value Disclosure

[5]

5

5

Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets (Note 15)

0

2

182

Impairment Of Certain Assets [Member] | Level 3 [Member] | Transmission And Gulf Of Mexico [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets

[1]

$ 2

170

Impairment Of Certain Assets [Member] | Level 2 [Member] | Northeast G And P [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of certain assets (Note 15)

[5]

12

Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | Transmission And Gulf Of Mexico [Member] | Discovery Producer Services LLC [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

[2]

97

Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | Northeast G And P [Member] | Blue Racer Midstream Holdings LLC | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

[2]

229

Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | Northeast G And P [Member] | Aux Sable Liquid Products LP [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

[2]

39

Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

[2]

10

Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | West [Member] | Rocky Mountain Midstream Holdings LLC [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

$ 108

[3]

243

[4]

Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | West [Member] | Brazos Permian II, LLC [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

[4]

$ 193

Impairment Of Equity-Method Investments [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

$ 0

$ 0

$ 1,046

Measurement Input, Discount Rate [Member] | Rocky Mountain Midstream Holdings LLC [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Investments Fair Value Inputs

17%

17%

17%

18%

Measurement Input, Discount Rate [Member] | Brazos Permian II, LLC [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Investments Fair Value Inputs

17%

17%

17%

Measurement Input, Discount Rate [Member] | Appalachia Midstream Services LLC And Laurel Mountain Midstream LLC And Discovery Producer Services LLC [Member] | Minimum [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Investments Fair Value Inputs

9.70%

9.70%

9.70%

Measurement Input, Discount Rate [Member] | Appalachia Midstream Services LLC And Laurel Mountain Midstream LLC And Discovery Producer Services LLC [Member] | Maximum [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Investments Fair Value Inputs

13.50%

13.50%

13.50%

Measurement Input, Discount Rate [Member] | Appalachia Midstream Services LLC And Laurel Mountain Midstream LLC And Discovery Producer Services LLC [Member] | Weighted Average [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Investments Fair Value Inputs

12.60%

12.60%

12.60%

Measurement Input, EBITDA Multiple [Member] | Blue Racer Midstream Holdings LLC And Aux Sable Liquid Products LP | Minimum [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Investments Fair Value Inputs

500%

500%

500%

Measurement Input, EBITDA Multiple [Member] | Blue Racer Midstream Holdings LLC And Aux Sable Liquid Products LP | Maximum [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Investments Fair Value Inputs

620%

620%

620%

Measurement Input, EBITDA Multiple [Member] | Blue Racer Midstream Holdings LLC And Aux Sable Liquid Products LP | Weighted Average [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Investments Fair Value Inputs

600%

600%

600%

Williams Companies Inc [Member] | Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Appalachia Midstream Services, LLC [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Fair value of investment

[2]

$ 2,700

$ 2,700

$ 2,700

Williams Companies Inc [Member] | Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | Northeast G And P [Member] | Appalachia Midstream Services, LLC [Member] | Fair Value, Nonrecurring [Member]

Fair Value Assets Measured On Nonrecurring Basis [Abstract]

Impairment of equity-method investments

[2]

$ 127

[1] Relates to capitalized project development costs for the Northeast Supply Enhancement project. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project. Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, developments in the political and regulatory environments caused us to slightly lower that assessed probability such that the capitalized project costs required impairment. The estimated fair value of the materials within the capitalized project costs at December 31, 2020 considered other internal uses and salvage values for the Property, plant, and equipment – net . The remaining capitalized costs were determined to have no fair value. The estimated fair value of certain capitalized project costs at June 30, 2021, was determined by a market approach, which incorporated an indication of interest by a third-party. Relates to a gathering system in the Marcellus Shale region, that was sold in 2021. The estimated fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization was determined using a market approach, which incorporated an indication of interest by a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

Fair Value Measurements Concent

Fair Value Measurements Concentration of Credit Risk (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Concentration Risk [Line Items]
Trade accounts and other receivables – net	$ 2,723	$ 1,978
NGLs, natural gas, and related products and services [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables – net	505	486
Transportation of natural gas and related products [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables – net	311	274
Marketing Of Natural Gas And NGLs
Concentration Risk [Line Items]
Trade accounts and other receivables – net	858	609
Oil and Gas, Exploration and Production
Concentration Risk [Line Items]
Trade accounts and other receivables – net	97	82
Accounts Receivable related to revenues from contracts with customers [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables – net	1,771	1,451
Derivative Receivables
Concentration Risk [Line Items]
Trade accounts and other receivables – net	889	462
Other Receivable [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables – net	$ 63	$ 65

Derivatives - Commodity Related

Derivatives - Commodity Related Derivatives (Details) - Not Designated as Hedging Instrument [Member]	Dec. 31, 2022 MMBTU Boe
Public Utilities, Inventory, Natural Gas | IndexRisk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | MMBTU	745,415,032
Public Utilities, Inventory, Natural Gas | Central Hub Risk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | MMBTU	(46,154,200)
Public Utilities, Inventory, Natural Gas | Basis Risk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | MMBTU	(50,737,802)
Natural Gas Liquids | Central Hub Risk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | Boe	35,548
Natural Gas Liquids | Basis Risk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | Boe	(3,880,364)
Crude Oil | Central Hub Risk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | Boe	(123,250)

Derivatives - Financial Stateme

Derivatives - Financial Statement Presentation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Liability	$ (1,034)	$ (476)
Derivative Liability, Fair Value, Gross Asset	1,236	772
Derivative Asset	334	309
Derivative Liability	(776)	(417)
Energy Related Derivative | Gain (Loss) on Derivative Instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	(387)	(148)	$ (5)
Designated as Hedging Instrument | Energy Related Derivative | Gain (Loss) on Derivative Instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	(55)	(2)
Not Designated as Hedging Instrument [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,368	785
Derivative Liability, Fair Value, Gross Liability	(2,012)	(1,189)
Not Designated as Hedging Instrument [Member] | Energy Related Derivative | Gain (Loss) on Derivative Instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(91)	16	(3)
Unrealized Gain (Loss) on Derivatives	(296)	(109)	0
Not Designated as Hedging Instrument [Member] | Energy Related Derivative | Cost of Sales
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Gain (Loss) on Derivative, Net	16	2	1
Unrealized Gain (Loss) on Derivatives	47	0	$ 0
Other Current Liabilities | Not Designated as Hedging Instrument [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,099	619
Derivative Liability, Fair Value, Gross Liability	(1,278)	(760)
Regulatory liabilities, deferred income, and other [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset	269	166
Derivative Liability, Fair Value, Gross Liability	$ (734)	$ (429)

Derivatives - Contingent Featur

Derivatives - Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Additional Collateral, Aggregate Fair Value	$ 13
Collateral Already Posted, Aggregate Fair Value	$ 202	$ 296

Contingent Liabilities and Co_2

Contingent Liabilities and Commitments (Details) - USD ($) $ in Millions				1 Months Ended
	Sep. 21, 2022	Dec. 29, 2021	May 20, 2016	Jan. 31, 2020	Dec. 31, 2022
Loss Contingencies [Line Items]
Accrued environmental loss liabilities					$ 40
Environmental Loss Contingency, Statement of Financial Position [Extensible Enumeration]					Accrued Liabilities, Current
Capital Addition Purchase Commitments [Member]
Loss Contingencies [Line Items]
Commitments for construction and acquisition of property, plant, and equipment					$ 439
Gas & NGL Marketing Services
Loss Contingencies [Line Items]
Other Commitment					546
Former Alaska Refinery [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Awarded, Value				$ 86
Energy Transfer Merger [Member]
Loss Contingencies [Line Items]
Loss contingency, damages sought, value			$ 1,480
Litigation Settlement, Amount Awarded from Other Party	$ 602	$ 410
Gas Pipeline [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities					13
Natural Gas Underground Storage Facilities [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities					10
Former Operations [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities					17
Recoverable through rates [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities					$ 4

Segment Disclosures Recon from

Segment Disclosures Recon from Modified EBITDA to Net Income (Loss) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA		$ 6,075	$ 5,494	$ 4,851
Accretion expense associated with asset retirement obligations for nonregulated operations		(51)	(45)	(35)
Depreciation and amortization expenses		(2,009)	(1,842)	(1,721)
Impairment of goodwill (Note 15)		0	0	(187)
Equity earnings (losses) (Note 8)		637	608	328
Impairment of equity-method investments (Note 17)		0	0	(1,046)
Other investing income (loss) – net		16	7	8
Proportional Modified EBITDA Equity Method Investments		(979)	(970)	(749)
Interest Expense		(1,147)	(1,179)	(1,172)
(Provision) benefit for income taxes		(425)	(511)	(79)
Net income (loss)		2,117	1,562	198
Inventory write-downs		161	15	17
Energy Related Derivative | Not Designated as Hedging Instrument [Member] | Cost of Sales
Reconciliation of Modified EBITDA to Net Income (Loss)
Unrealized Gain (Loss) on Derivatives		47	0	0
Gas & NGL Marketing Services | Energy Related Derivative | Not Designated as Hedging Instrument [Member] | Cost of Sales
Reconciliation of Modified EBITDA to Net Income (Loss)
Unrealized Gain (Loss) on Derivatives		47	0	0
Intersegment Eliminations [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Proportional Modified EBITDA Equity Method Investments		0	0	0
Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA		2,674	2,621	2,379
Proportional Modified EBITDA Equity Method Investments		(193)	(183)	(166)
Operating Segments [Member] | Northeast G And P [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA		1,796	1,712	1,489
Proportional Modified EBITDA Equity Method Investments		(654)	(682)	(473)
Operating Segments [Member] | West [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA		1,211	961	947
Proportional Modified EBITDA Equity Method Investments		(132)	(105)	(110)
Operating Segments [Member] | Gas & NGL Marketing Services
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	[1]	(40)	22	51
Proportional Modified EBITDA Equity Method Investments		0	0	0
Operating Segments [Member] | Other [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA		434	178	(15)
Proportional Modified EBITDA Equity Method Investments		$ 0	$ 0	$ 0
[1] Modified EBITDA for 2022, 2021, and 2020, includes charges of $161 million, $15 million, and $17 million respectively, associated with lower of cost or net realizable value adjustments to our inventory. These charges are reflected in Product Sales or Product costs in our Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies ) . Net unrealized commodity-related derivatives gains of $47 million in 2022 and $0 in 2021 and 2020 are reflected in Net processing commodity expenses.

Segment Disclosures Recon fro_2

Segment Disclosures Recon from Segment to Consolidated - Revenues (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022		Dec. 31, 2021	Dec. 31, 2020
Segment revenues [Line Items]
Revenues		$ 10,965		$ 10,627	$ 7,719
Other financial information:
Additions to long-lived assets		3,598		1,855	1,283
Proportional Modified EBITDA Equity Method Investments		979		970	749
Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues		(1,329)		(1,375)	(467)
Other financial information:
Additions to long-lived assets		0		0	0
Proportional Modified EBITDA Equity Method Investments		0		0	0
Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		4,047		3,786	3,469
Other financial information:
Additions to long-lived assets		1,420		861	706
Proportional Modified EBITDA Equity Method Investments		193		183	166
Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		1,802		1,634	1,529
Other financial information:
Additions to long-lived assets		261		164	137
Proportional Modified EBITDA Equity Method Investments		654		682	473
Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues		2,561		2,026	1,523
Other financial information:
Additions to long-lived assets		1,507		209	318
Proportional Modified EBITDA Equity Method Investments		132		105	110
Operating Segments [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		3,233	[1]	4,211	1,631
Other financial information:
Additions to long-lived assets		4		1	0
Proportional Modified EBITDA Equity Method Investments		0		0	0
Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		651		345	34
Other financial information:
Additions to long-lived assets		406		620	122
Proportional Modified EBITDA Equity Method Investments		0		0	0
Service [Member]
Segment revenues [Line Items]
Revenues		6,536		6,001	5,924
Service [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		3,461		3,310	3,207
Service [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		1,613		1,490	1,416
Service [Member] | West [Member]
Segment revenues [Line Items]
Revenues		1,443		1,178	1,248
Service [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		3	[1]	3	32
Service [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		16		20	21
Service [Member] | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues		(266)		(195)	(136)
Service [Member] | Intersegment Eliminations [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		(118)		(75)	(50)
Service [Member] | Intersegment Eliminations [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		(41)		(38)	(49)
Service [Member] | Intersegment Eliminations [Member] | West [Member]
Segment revenues [Line Items]
Revenues		(99)		(70)	(24)
Service [Member] | Intersegment Eliminations [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		0	[1]	0	0
Service [Member] | Intersegment Eliminations [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		(8)		(12)	(13)
Service [Member] | Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		3,579		3,385	3,257
Service [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		1,654		1,528	1,465
Service [Member] | Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues		1,542		1,248	1,272
Service [Member] | Operating Segments [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		3	[1]	3	32
Service [Member] | Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		24		32	34
NonRegulated Service Commodity Consideration [Member]
Segment revenues [Line Items]
Revenues		260		238	129
NonRegulated Service Commodity Consideration [Member] | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues		0		0	0
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		64		52	21
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		14		7	7
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues		182		179	101
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		0	[1]	0	0
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		0		0	0
Product [Member]
Segment revenues [Line Items]
Revenues		4,556		4,536	1,671
Product [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		228		231	144
Product [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		28		13	16
Product [Member] | West [Member]
Segment revenues [Line Items]
Revenues		145		60	20
Product [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		4,052	[1]	4,094	1,491
Product [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		103		138	0
Product [Member] | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues		(1,063)		(1,180)	(331)
Product [Member] | Intersegment Eliminations [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		(176)		(118)	(47)
Product [Member] | Intersegment Eliminations [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		(106)		(86)	(41)
Product [Member] | Intersegment Eliminations [Member] | West [Member]
Segment revenues [Line Items]
Revenues		(696)		(583)	(132)
Product [Member] | Intersegment Eliminations [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		518	[1]	(198)	(111)
Product [Member] | Intersegment Eliminations [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		(603)		(195)	0
Product [Member] | Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		404		349	191
Product [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		134		99	57
Product [Member] | Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues		841		643	152
Product [Member] | Operating Segments [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		3,534	[1]	4,292	1,602
Product [Member] | Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		706		333	0
Energy Commodities and Service
Segment revenues [Line Items]
Revenues	[2]	(387)		(148)	(5)
Energy Commodities and Service | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		(91)		(39)	(5)
Energy Commodities and Service | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		(296)		(109)	0
Energy Commodities and Service | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues	[2]	0		0	0
Energy Commodities and Service | Transmission And Gulf Of Mexico [Member] | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | Transmission And Gulf Of Mexico [Member] | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues	[2]	0		0	0
Energy Commodities and Service | Northeast G And P [Member] | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | Northeast G And P [Member] | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | West [Member]
Segment revenues [Line Items]
Revenues	[2]	(4)		(44)	(2)
Energy Commodities and Service | West [Member] | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		(4)		(44)	(2)
Energy Commodities and Service | West [Member] | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues	[2]	(304)		(84)	(3)
Energy Commodities and Service | Gas & NGL Marketing Services | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		17		25	(3)
Energy Commodities and Service | Gas & NGL Marketing Services | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		(321)		(109)	0
Energy Commodities and Service | Other [Member]
Segment revenues [Line Items]
Revenues	[2]	(79)		(20)	0
Energy Commodities and Service | Other [Member] | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		(104)		(20)	0
Energy Commodities and Service | Other [Member] | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		25		0	0
Energy Commodities and Service | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues	[2]	0		0	0
Energy Commodities and Service | Intersegment Eliminations [Member] | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | Intersegment Eliminations [Member] | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		$ 0		$ 0	$ 0
[1]See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.[2]We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.

Segment Disclosures Recon fro_3

Segment Disclosures Recon from Segment to Consolidated - Assets and Investments (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 48,433	$ 47,612
Equity-method investments	5,048	5,121
Current assets	3,797	4,549
Other Assets, Noncurrent	1,319	1,276
Operating Segments [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	43,317	41,787
Equity-method investments	5,048	5,121
Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	17,795	17,142
Equity-method investments	629	602
Operating Segments [Member] | Northeast G And P [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	13,539	13,861
Equity-method investments	3,566	3,681
Operating Segments [Member] | West [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	10,710	9,698
Equity-method investments	843	838
Operating Segments [Member] | Gas & NGL Marketing Services
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	130	294
Equity-method investments	0	0
Operating Segments [Member] | Other [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	1,143	792
Equity-method investments	$ 10	$ 0

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Feb. 14, 2023	Jan. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Subsequent Event [Line Items]
Common Stock, Dividends, Per Share, Declared			$ 1.70	$ 1.64	$ 1.60
Subsequent Event [Member]
Subsequent Event [Line Items]
Common Stock, Dividends, Per Share, Declared		$ 0.4475
Subsequent Event [Member] | MountainWestAcquisition
Subsequent Event [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	100%
Business Combination, Consideration Transferred	$ 1,080
Business Combination, Consideration Transferred, Liabilities Incurred	$ 430

Schedule II Valuation and Quali

Schedule II Valuation and Qualifying Accounts (Details) - Deferred Tax Asset Valuation Allowance [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Valuation And Qualifying Accounts
Beginning Balance	[1]	$ 297	$ 325	$ 319
Additions Charged (Credited) To Cost and Expenses		(97)	(28)	6
Additions Other		0	0	0
Deductions		0	0	0
Ending Balance	[1]	$ 200	$ 297	$ 325
[1]Deducted from related assets.