The Williams Companies, Inc. (WMB) 10-K21 Feb 242023 FY Annual reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2023	Feb. 16, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
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			$ 38,305,701,487
Entity Common Stock, Shares Outstanding		1,216,750,172
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 30, 2024, are incorporated into Part III, as specifically set forth in Part III.
Entity Central Index Key	0000107263
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY

Audit Information

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2023
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues:
Revenues		$ 10,907	$ 10,965	$ 10,627
Costs and expenses:
Operating and maintenance expenses		1,984	1,817	1,548
Depreciation and amortization expenses		2,071	2,009	1,842
Selling, general, and administrative expenses		665	636	558
Gain on sale of business (Note 3)		(129)	0	0
Other (income) expense – net		(30)	28	16
Total costs and expenses		6,596	7,947	7,996
Operating income (loss)		4,311	3,018	2,631
Equity earnings (losses)		589	637	608
Other investing income (loss) – net		108	16	7
Interest expense		(1,236)	(1,147)	(1,179)
Gain (Loss) Related to Litigation Settlement		534	0	0
Other income (expense) – net		99	18	6
Income (loss) before income taxes		4,405	2,542	2,073
Less: Provision (benefit) for income taxes		1,005	425	511
Income (Loss) from Continuing Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest		3,400	2,117	1,562
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest		(97)	0	0
Net income (loss)		3,303	2,117	1,562
Less: Net income (loss) attributable to noncontrolling interests		124	68	45
Net income (loss) attributable to The Williams Companies, Inc.		3,179	2,049	1,517
Less: Preferred stock dividends		3	3	3
Net income (loss) available to common stockholders		3,176	2,046	1,514
Amounts attributable to The Williams Companies, Inc. available to common stockholders:
Income (loss) from continuing operations available to common stockholders		$ 3,273	$ 2,046	$ 1,514
Basic earnings (loss) per common share:
Basic		$ 2.69	$ 1.68	$ 1.25
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share		(0.08)	0	0
Net income (loss)		$ 2.61	$ 1.68	$ 1.25
Weighted-average shares (thousands)		1,217,784	1,218,362	1,215,221
Diluted earnings (loss) per common share:
Diluted		$ 2.68	$ 1.67	$ 1.24
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share		(0.08)	0	0
Net income (loss)		$ 2.60	$ 1.67	$ 1.24
Weighted-average shares (thousands)		1,222,715	1,222,672	1,218,215
Service [Member]
Revenues:
Revenues		$ 7,026	$ 6,536	$ 6,001
NonRegulated Service Commodity Consideration [Member]
Revenues:
Revenues		146	260	238
Product [Member]
Revenues:
Revenues		2,779	4,556	4,536
Energy Commodities and Service
Revenues:
Revenues	[1]	956	(387)	(148)
Oil and Gas, Purchased [Member]
Costs and expenses:
Cost of Goods and Service, Excluding Depreciation, Depletion, and Amortization		1,884	3,369	3,931
Natural Gas Purchased For Shrink [Member]
Costs and expenses:
Cost of Goods and Service, Excluding Depreciation, Depletion, and Amortization		$ 151	$ 88	$ 101

[1]We record transactions that qualify as commodity 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 from commodity 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, 2023	Dec. 31, 2022	Dec. 31, 2021
Comprehensive income (loss):
Net income (loss)	$ 3,303	$ 2,117	$ 1,562
Designated interest rate cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of ($8), $1, and $14 in 2023, 2022, and 2021, respectively	26	(3)	(40)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $1, $—, and ($14) in 2023, 2022, and 2021, respectively	(2)	0	41
Pension and other postretirement benefits:
Net actuarial gain (loss) arising during the year, net of taxes of $—, $1, and ($18) in 2023, 2022, and 2021, respectively	(2)	1	51
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of $—, ($4), and ($4) in 2023, 2022, and 2021, respectively	3	11	11
Other comprehensive income (loss)	25	9	63
Comprehensive income (loss)	3,328	2,126	1,625
Less: Comprehensive income (loss) attributable to noncontrolling interests	124	68	45
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$ 3,204	$ 2,058	$ 1,580

Consolidated Statement of Com_2

Consolidated Statement of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash flow hedging activities:
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, Tax	$ (8)	$ 1	$ 14
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	1	0	(14)
Pension and other postretirement benefits:
Other Comprehensive Income (Loss), Defined Benefit Plan, Net Actuarial Gain (Loss) Arising During Period, Tax	0	1	(18)
Other Comprehensive Income Loss, Reclassification Pension And Other Postretirement Benefit Plans Net Gain Loss Included In Net Periodic Benefit Cost (Credit), Tax	$ 0	$ (4)	$ (4)

Consolidated Balance Sheet

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents	$ 2,150	$ 152
Receivables, Net, Current	1,655	2,723
Inventories	274	320
Derivative assets	239	323
Other current assets and deferred charges	195	279
Total current assets	4,513	3,797
Investments	4,637	5,065
Property, plant, and equipment – net	34,311	30,889
Intangible assets – net of accumulated amortization	7,593	7,363
Regulatory assets, deferred charges, and other	1,573	1,319
Total assets	52,627	48,433
Current liabilities:
Accounts payable	1,379	2,327
Derivative Liability, Current	105	316
Accrued and other current liabilities	1,284	1,270
Commercial Paper	725	350
Long-term debt due within one year	2,337	627
Total current liabilities	5,830	4,890
Long-term debt	23,376	21,927
Deferred income tax liabilities	3,846	2,887
Regulatory liabilities, deferred income, and other	4,684	4,684
Contingent liabilities and commitments (Note 17)
Stockholders’ equity:
Preferred stock ($1 par value; 30 million shares authorized at December 31, 2023 and December 31, 2022; 35,000 shares issued at December 31, 2023 and December 31, 2022)	35	35
Common stock ($1 par value; 1,470 million shares authorized at December 31, 2023 and December 31, 2022; 1,256 million shares issued at December 31, 2023 and 1,253 million shares issued at December 31, 2022)	1,256	1,253
Capital in excess of par value	24,578	24,542
Retained deficit	(12,287)	(13,271)
Accumulated other comprehensive income (loss)	0	(24)
Treasury stock, at cost (39 million shares at December 31, 2023 and 35 million shares at December 31, 2022 of common stock)	(1,180)	(1,050)
Total stockholders’ equity	12,402	11,485
Noncontrolling interests in consolidated subsidiaries	2,489	2,560
Total equity	14,891	14,045
Total liabilities and equity	$ 52,627	$ 48,433

Consolidated Balance Sheet (Par

Consolidated Balance Sheet (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Accounts Receivable, Allowance for Credit Loss, Current	$ 3	$ 6
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	1,256,000,000	1,253,000,000
Treasury Stock, Common, Shares	39,000,000	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, 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
Purchases of treasury stock	0
Other	(17)	0	0	0	(14)	0	0	(14)	(3)
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
Purchases 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
Net income (loss)	3,303	0	0	0	3,179	0	0	3,179	124
Other comprehensive income (loss)	25	0	0	0	0	25	0	25	0
Dividends, Common Stock, Cash	(2,179)	0	0	0	(2,179)	0	0	(2,179)	0
Dividends and distributions to noncontrolling interests	(213)	0	0	0	0	0	0	0	(213)
Stock-based compensation and related common stock issuances, net of tax	38	0	3	35	0	0	0	38	0
Contributions from noncontrolling interests	18	0	0	0	0	0	0	0	18
Purchases of treasury stock	(130)	0	0	0	0	0	(130)	(130)	0
Other	(16)	0	0	1	(16)	(1)	0	(16)	0
Net increase (decrease) in equity	846	0	3	36	984	24	(130)	917	(71)
Ending balance at Dec. 31, 2023	$ 14,891	$ 35	$ 1,256	$ 24,578	$ (12,287)	$ 0	$ (1,180)	$ 12,402	$ 2,489

Consolidated Statement of Cha_2

Consolidated Statement of Changes in Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Stockholders' Equity [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 1.79	$ 1.70	$ 1.64

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
OPERATING ACTIVITIES:
Net income (loss)	$ 3,303	$ 2,117	$ 1,562
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	2,071	2,009	1,842
Provision (benefit) for deferred income taxes	951	431	509
Equity (earnings) losses	(589)	(637)	(608)
Distributions from equity-method investees (Note 8)	796	865	757
Net unrealized (gain) loss from commodity derivative instruments	(660)	249	109
Gain on sale of business (Note 3)	(129)	0	0
Inventory write-downs	30	161	15
Amortization of stock-based awards	77	73	81
Cash provided (used) by changes in current assets and liabilities:
Accounts receivable	1,089	(733)	(545)
Inventories	13	(110)	(139)
Other current assets and deferred charges	60	(33)	(63)
Accounts payable	(1,009)	410	643
Accrued and other current liabilities	(19)	209	58
Changes in current and noncurrent commodity derivative assets and liabilities	200	94	(277)
Other, including changes in noncurrent assets and liabilities	(246)	(216)	1
Net cash provided (used) by operating activities	5,938	4,889	3,945
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	372	345	0
Proceeds from long-term debt	2,755	1,755	2,155
Payments of long-term debt	(634)	(2,876)	(894)
Proceeds from issuance of common stock	6	54	9
Purchases of treasury stock	(130)	(9)	0
Common dividends paid	(2,179)	(2,071)	(1,992)
Dividends and distributions paid to noncontrolling interests	(213)	(204)	(187)
Contributions from noncontrolling Interests	18	18	9
Payments for debt issuance costs	(23)	(17)	(26)
Other – net	(21)	(37)	(16)
Net cash provided (used) by financing activities	(49)	(3,042)	(942)
INVESTING ACTIVITIES:
Capital expenditures (1)	(2,516)	(2,253)	(1,239)
Dispositions - net	(51)	(30)	(8)
Proceeds from sale of business (Note 3)	346	0	0
Purchases of businesses, net of cash acquired (Note 3)	(1,568)	(933)	(151)
Purchases of and contributions to equity-method investments (Note 8)	(141)	(166)	(115)
Other – net	39	7	48
Net cash provided (used) by investing activities	(3,891)	(3,375)	(1,465)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect, Total	1,998	(1,528)	1,538
Cash and cash equivalents at beginning of year	152	1,680	142
Cash and cash equivalents at end of year	2,150	152	1,680
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
(1) Increases to property, plant, and equipment	(2,564)	(2,394)	(1,305)
Changes in related accounts payable and accrued liabilities	48	141	66
Capital expenditures	$ (2,516)	$ (2,253)	$ (1,239)

General, Description of Busines

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2023
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. 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 and 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), Northwest Pipeline LLC (Northwest Pipeline), and MountainWest Pipelines Holding Company (MountainWest) (see Note 3 – Acquisitions and Divestitures), 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, the Mid-Continent region which includes the Anadarko and Permian basins, and the Denver-Julesberg Basin (DJ Basin) of Colorado which includes Rocky Mountain Midstream Holdings LLC (RMM), a former 50 percent equity-method investment in which we acquired the remaining ownership interest in November 2023 (see Note 3 – Acquisitions and Divestitures ) . 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 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 natural gas liquid (NGL) and natural gas marketing and trading operations, which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets. Basis of Presentation Discontinued operations Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations. 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 commodity 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, Northwest Pipeline, and MountainWest 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 include 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, trackers, 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, 2023 and 2022 are as follows: December 31, 2023 2022 (Millions) Current assets reported within Other current assets and deferred charges $ 95 $ 138 Noncurrent assets reported within Regulatory assets, deferred charges, and other 527 459 Total regulated assets $ 622 $ 597 Current liabilities reported within Accrued and other current liabilities $ 77 $ 201 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,288 1,233 Total regulated liabilities $ 1,365 $ 1,434 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. 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 nonregulated 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 commodity 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 and Divestitures), 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. Commodity 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 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 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 from physically settled commodity derivative contracts for commodity sales transactions are recognized in Net gain (loss) from commodity derivatives in our Consolidated Statement of Income. Realized and unrealized gains and losses from non-designated commodity derivative contracts for commodity sales transactions that are financially settled are reported in Net gain (loss) from commodity derivatives in our Consolidated Statement of Income. Net gains and losses from 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 – Commodity 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) from 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

Variable Interest Entities

Variable Interest Entities	12 Months Ended
Variable Interest Entities	Dec. 31, 2023
Variable Interest Entity Disclosures [Abstract]
Variable Interest Entities [Text Block]	Note 2 – Variable Interest Entities Consolidated VIEs As of December 31, 2023, 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. In order to meet contractual gas gathering commitments, we may fund more than our proportional share of future expansion activity, which could ultimately impact relative ownership. The following table presents amounts included in our Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs: December 31, 2023 2022 (Millions) Assets (liabilities): Cash and cash equivalents $ 33 $ 49 Trade accounts and other receivables – net 215 136 Inventories 5 4 Other current assets and deferred charges 4 7 Property, plant, and equipment – net 5,046 5,154 Intangible assets – net of accumulated amortization 2,049 2,158 Regulatory assets, deferred charges, and other 31 29 Accounts payable (109) (76) Accrued and other current liabilities (28) (34) Regulatory liabilities, deferred income, and other (268) (275) 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, 2023, the carrying value of our investment in Targa Train 7 was $44 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, 2023, the carrying value of our investment in Brazos Permian II was $27 million. Our maximum exposure to loss is limited to the carrying value of our investment.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
Acquisitions and Divestitures	Dec. 31, 2023
Business Combinations [Abstract]
Acquisitions and Divestitures [Text Block]	Note 3 – Acquisitions and Divestitures Gulf Coast Storage Acquisition On January 3, 2024, we closed on the acquisition of 100 percent of a strategic portfolio of natural gas storage facilities and pipelines, located in Louisiana and Mississippi, from Hartree Partners LP (Gulf Coast Storage Acquisition) for $1.95 billion, subject to working capital and post-closing adjustments. The purpose of this acquisition was to expand our natural gas storage footprint in the Gulf Coast region. The Gulf Coast Storage Acquisition was funded with cash on hand and $100 million of deferred consideration that does not accrue interest and is payable one year from the acquisition date. Acquisition-related costs for the Gulf Coast Storage Acquisition of $1 million are reported within our Transmission & Gulf of Mexico segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income during 2023. We plan on accounting for the Gulf Coast Storage 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 cost approach for property, plant, and equipment. The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired, which will be included in our Transmission & Gulf of Mexico segment, and liabilities assumed at January 3, 2024. The allocation is considered preliminary because the valuation work has not been completed due to the ongoing review of the valuation results and validation of significant inputs and assumptions. Preliminary fair value measurements were made for certain acquired assets and liabilities, primarily property, plant, and equipment; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified. The fair value of accounts receivable acquired, included in Other current assets in the following table, equals contractual amounts receivable. (Millions) Cash and cash equivalents $ 46 Other current assets 18 Property, plant, and equipment – net 2,042 Other noncurrent assets 2 Total assets acquired $ 2,108 Current liabilities $ (10) Noncurrent liabilities (107) Total liabilities assumed $ (117) Net assets acquired $ 1,991 DJ Basin Acquisitions Cureton Acquisition On November 30, 2023, we closed on the acquisition of 100 percent of Cureton Front Range, LLC (Cureton Acquisition), whose operations are located in the DJ Basin, for $546 million, subject to working capital and post-closing adjustments. The purpose of this acquisition was to expand our gathering and processing footprint and create operational synergies for our operations in the DJ Basin. The Cureton Acquisition was funded with cash on hand. During the period from the acquisition date of November 30, 2023 to December 31, 2023, the operations acquired in the Cureton Acquisition contributed Revenues of $35 million and Modified EBITDA (as defined in Note 18 – Segment Disclosures) of $7 million. Acquisition-related costs for the Cureton Acquisition of $6 million are reported within our West segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income during 2023. We accounted for the Cureton Acquisition as a business combination. The valuation techniques used consisted of the cost approach for property, plant, and equipment and the income approach for valuation of other intangible assets. The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in our West segment, and liabilities assumed at November 30, 2023. The allocation is considered preliminary because the valuation work has not been completed due to the ongoing review of the valuation results and validation of significant inputs and assumptions. Preliminary fair value measurements were made for certain acquired assets and liabilities, primarily property, plant, and equipment and other intangible assets; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified. The fair value of accounts receivable acquired, included in Other current assets in the following table, equals contractual amounts receivable. (Millions) Cash and cash equivalents $ 2 Other current assets 21 Property, plant, and equipment – net 437 Intangible assets – net of accumulated amortization 117 Other noncurrent assets 4 Total identifiable assets acquired $ 581 Current liabilities $ (25) Noncurrent liabilities (16) Total liabilities assumed $ (41) Net identifiable assets acquired $ 540 Goodwill included in Intangible assets – net of accumulated amortization 6 Net assets acquired $ 546 Other intangible assets recognized in the Cureton Acquisition are related to contractual customer relationships from gas gathering and processing 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 24 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 10 years. See Note 10 – Goodwill and Other Intangible Assets. RMM Acquisition As of December 31, 2022, we owned a 50 percent interest in RMM which we accounted for as an equity-method investment. On November 30, 2023, we closed on the acquisition of the remaining 50 percent interest in RMM (RMM Acquisition) for $704 million. As a result of acquiring this additional interest, we obtained control of and now consolidate RMM. The purpose of this acquisition was to expand our gathering and processing footprint and create operational synergies for our operations in the DJ Basin. Substantially all of the RMM purchase price is not due to the seller until the first quarter of 2025, does not accrue interest until the fourth quarter of 2024, and may be repaid early without penalty. It was recorded as a deferred consideration obligation at fair value using an income approach, which resulted in a discount to the contractual amount due which will be imputed as interest expense over the term of the obligation. The obligation is presented within long-term debt owed by our wholly owned subsidiary Williams Rocky Mountain Midstream Holdings LLC. During the period from the acquisition date of November 30, 2023 to December 31, 2023, RMM contributed Revenues of $53 million and Modified EBITDA of $12 million. We accounted for the RMM Acquisition as a business combination. The book value of our existing equity-method investment prior to the acquisition date of November 30, 2023 was $406 million. We recognized a $30 million gain on remeasuring our existing equity-method investment to fair value included in Other investing income (loss) – net in our Consolidated Statement of Income during 2023. The valuation techniques used consisted of the income approach for our previous equity-method investment in RMM and the valuation of other intangible assets, and the cost approach for property, plant, and equipment. The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in our West segment, and liabilities assumed at November 30, 2023. The net assets acquired primarily reflect the noncash consideration transferred, which includes the fair value of both our previous equity-method investment and the deferred consideration obligation. The allocation is considered preliminary because the valuation work has not been completed due to the ongoing review of the valuation results and validation of significant inputs and assumptions. Preliminary fair value measurements were made for certain acquired assets and liabilities, primarily property, plant, and equipment and other intangible assets; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified. The fair value of accounts receivable acquired, included in Other current assets in the following table, equals contractual amounts receivable. (Millions) Cash and cash equivalents $ 28 Other current assets 4 Investments 20 Property, plant, and equipment – net 1,041 Intangible assets – net of accumulated amortization 61 Other noncurrent assets 12 Total identifiable assets acquired $ 1,166 Current liabilities $ (44) Noncurrent liabilities (103) Total liabilities assumed $ (147) Net identifiable assets acquired $ 1,019 Goodwill included in Intangible assets – net of accumulated amortization 57 Net assets acquired $ 1,076 Goodwill recognized in the RMM Acquisition relates primarily to enhancing and diversifying our basin positions as well as delivering operational synergies, including increasing volumes on our existing processing facilities and increasing revenues on our NGL transportation, fractionation, and storage assets, and is reported within our West segment. Substantially all of the goodwill is deductible for tax purposes. Other intangible assets recognized in the RMM Acquisition are related to contractual customer relationships from gas gathering and processing 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 18 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 10 years. See Note 10 – Goodwill and Other Intangible Assets. MountainWest Acquisition On February 14, 2023, we closed on the acquisition of 100 percent of 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 retaining $430 million outstanding principal amount of MountainWest long-term debt. For 2023, $1.024 billion is presented in Purchases of businesses, net of cash acquired in our Consolidated Statement of Cash Flows reflecting the cash purchase price, reduced for post-closing adjustments and the cash acquired as presented in the purchase price allocation. The purpose of the MountainWest Acquisition was to expand our existing transmission and storage infrastructure footprint into major markets in Utah, Wyoming, and Colorado. During the period from the acquisition date of February 14, 2023 to December 31, 2023, the operations acquired in the MountainWest Acquisition contributed Revenues of $225 million and Modified EBITDA of $122 million, which includes $27 million of transition-related costs. Acquisition-related costs for the MountainWest Acquisition of $16 million are reported within our Transmission & Gulf of Mexico segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income during 2023. We accounted for the MountainWest Acquisition as a business combination. The valuation techniques used consisted of the cost approach for nonregulated property, plant, and equipment, as well as the market approach for the assumed long-term debt consistent with the valuation technique discussed in Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk. MountainWest’s regulated operations are accounted for pursuant to ASC 980. The fair value of assets and liabilities subject to rate making and cost recovery provisions were determined utilizing the income approach. MountainWest’s expected return on rate base is consistent with expected returns of similarly situated assets, resulting in carryover basis of these assets and liabilities equaling their fair value. The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in our Transmission & Gulf of Mexico segment, and liabilities assumed at February 14, 2023. The fair value of accounts receivable acquired equals contractual amounts receivable. After the March 31, 2023, financial statements were issued, we identified adjustments to the preliminary purchase price allocation, primarily resulting in an increase of $19 million in trade accounts and other receivables and decreases of $73 million in property, plant, and equipment and $60 million in other noncurrent liabilities. (Millions) Cash and cash equivalents $ 23 Trade accounts and other receivables 33 Other current assets 26 Investments 20 Property, plant, and equipment – net 1,019 Other noncurrent assets 33 Total identifiable assets acquired $ 1,154 Current liabilities $ (47) Long-term debt (Note 12) (365) Other noncurrent liabilities (95) Total liabilities assumed $ (507) Net identifiable assets acquired $ 647 Goodwill included in Intangible assets – net of accumulated amortization 400 Net assets acquired $ 1,047 Goodwill recognized in the MountainWest Acquisition relates primarily to enhancing and diversifying our basin positions and the long-term value associated with rate regulated businesses and is reported within our Transmission & Gulf of Mexico segment. Substantially all of the goodwill is deductible for tax purposes. Trace Acquisition On April 29, 2022, we closed on the acquisition of 100 percent of Gemini Arklatex, LLC through which we acquired the Haynesville Shale region gas gathering and related assets of Trace Midstream for $972 million 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 of $73 million. Acquisition-related costs for the Trace Acquisition of $8 million are reported within our West segment and were included in Selling, general, and administrative expenses in our Consolidated Statement of Income during 2022. We accounted for the Trace 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 our West segment, and liabilities assumed at April 29, 2022. The fair value of accounts receivable acquired equals contractual amounts receivable. The valuation techniques used consisted of the income approach for valuation of intangible assets and the cost approach for property, plant, and equipment. (Millions) Cash and cash equivalents $ 39 Trade accounts and other receivables 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 Other 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 – Goodwill and Other 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) from commodity derivatives of $(43) million, and unfavorable Modified EBITDA of $112 million. Both the Revenues and Modified EBITDA amounts reflect a net unrealized loss from commodity derivatives in Net gain (loss) from 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 our 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 commodity derivative assets and liabilities. (Millions) Cash and cash equivalents $ 8 Trade accounts and other receivables 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. Other intangible assets Other 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, a significant portion of the amortization will be recognized within the first few years of this range. See Note 10 – Goodwill and Other 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 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 commodity derivatives. Supplemental Pro Forma The following pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for 2023, 2022, and 2021, are presented as if the Gulf Coast Storage Acquisition had been completed on January 1, 2023, the DJ Basin Acquisitions and MountainWest Acquisition had been completed on January 1, 2022, 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 acquisitions 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 transactions or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements. Year Ended December 31, 2023 As Reported Pro Forma Gulf Coast Storage Pro Forma DJ Basin (1) Pro Forma MountainWest (1) Pro Forma Combined (Millions) Revenues $ 10,907 $ 202 $ 270 $ 35 $ 11,414 Net income (loss) attributable to The Williams Companies, Inc. 3,179 53 17 6 3,255 Year Ended December 31, 2022 As Reported Pro Forma DJ Basin Pro Forma MountainWest Pro Forma Trace (1) Pro Forma Combined (Millions) Revenues $ 10,965 $ 218 $ 265 $ 45 $ 11,493 Net income (loss) attributable to The Williams Companies, Inc. 2,049 13 170 18 2,250 Year Ended December 31, 2021 As Reported Pro Forma Trace Pro Forma Sequent (1) 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 (1) Excludes results from operations acquired in the acquisition for the period beginning on the acquisition date, 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 our Transmission & Gulf of Mexico segment. Sale of Certain Gulf Coast Liquids Pipelines On September 29, 2023, we completed the sale of various petrochemical and feedstock pipelines and associated contracts in the Gulf Coast region for $348 million. As a result of this sale, we recorded a gain of $129 million in 2023 in our Transmission & Gulf of Mexico segment. The gain is reflected in Gain on sale of business in our Consolidated Statement of Income. The results of operations for this disposal group, excluding the gain noted, were not significant for the reporting periods.

Related Party Transactions

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2023
Related Party Transactions [Abstract]
Related Party Transactions [Text Block]	Note 4 – Related Party Transactions Transactions with Equity-Method Investees We have costs and expenses associated with our equity-method investees of $776 million, $1.346 billion, and $948 million for 2023, 2022, and 2021, 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 $5 million, $76 million, and $46 million for 2023, 2022, and 2021, respectively. In addition, w e have $2 million and $17 million included in Trade accounts and other receivables and $33 million and $87 million included in Accounts payable in our Consolidated Balance Sheet with our equity-method investees at December 31, 2023 and 2022, 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 $64 million, $65 million, and $70 million for 2023, 2022, and 2021, respectively. Board of Directors Two members of our Board of Directors are also executive officers at certain of our counterparties. We recorded $90 million and $180 million in Product sales and $25 million and $86 million in Product costs in our Consolidated Statement of Income from these companies for the purchase and sale of natural gas for 2023 and 2022, respectively.

Revenue Recognition

Revenue Recognition	12 Months Ended
Revenue Recognition	Dec. 31, 2023
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: Regulated Interstate Transportation & Storage Gulf of Mexico Midstream & Storage Northeast West Midstream Gas & NGL Marketing Services Other Eliminations Total (Millions) 2023 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 3,334 $ — $ — $ — $ — $ — $ (60) $ 3,274 Gathering, processing, transportation, fractionation, and storage: Monetary consideration — 443 1,782 1,478 — — (170) 3,533 Commodity consideration — 38 5 103 — — — 146 Other 19 11 87 12 1 — (15) 115 Total service revenues 3,353 492 1,874 1,593 1 — (245) 7,068 Product sales 140 120 132 441 4,615 442 (962) 4,928 Total revenues from contracts with customers 3,493 612 2,006 2,034 4,616 442 (1,207) 11,996 Other revenues (1) 38 15 27 101 4,294 64 (2) 4,537 Other adjustments (2) — — — — (6,032) — 406 (5,626) Total revenues $ 3,531 $ 627 $ 2,033 $ 2,135 $ 2,878 $ 506 $ (803) $ 10,907 2022 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 3,139 $ — $ — $ — $ — $ — $ (72) $ 3,067 Gathering, processing, transportation, fractionation, and storage: Monetary consideration (3) — 381 1,526 1,518 — — (167) 3,258 Commodity consideration — 64 14 182 — — — 260 Other (3) 10 11 102 12 3 — (16) 122 Total service revenues 3,149 456 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 3,328 707 1,776 2,553 10,771 706 (2,068) 17,773 Other revenues (1) 28 10 26 8 7,929 (55) (11) 7,935 Other adjustments (2) — — — — (15,467) — 724 (14,743) Total revenues $ 3,356 $ 717 $ 1,802 $ 2,561 $ 3,233 $ 651 $ (1,355) $ 10,965 Regulated Interstate Transportation & Storage Gulf of Mexico Midstream & Storage Northeast West Midstream Gas & NGL Marketing Services Other Eliminations Total (Millions) 2021 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 2,988 $ — $ — $ — $ — $ — $ (33) $ 2,955 Gathering, processing, transportation, fractionation, and storage: Monetary consideration (3) — 358 1,425 1,227 — — (133) 2,877 Commodity consideration — 52 7 179 — — — 238 Other (3) 10 8 78 9 3 1 (16) 93 Total service revenues 2,998 418 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 3,086 687 1,609 2,058 6,407 334 (1,397) 12,784 Other revenues (1) 13 8 25 (32) 2,632 11 (13) 2,644 Other adjustments (2) — — — — (4,828) — 27 (4,801) Total revenues $ 3,099 $ 695 $ 1,634 $ 2,026 $ 4,211 $ 345 $ (1,383) $ 10,627 ______________________________ (1) Revenues not derived from contracts with customers primarily consist of physical product sales related to commodity derivative contracts, realized and unrealized gains and losses associated with our commodity derivative contracts, which are reported in Net gain (loss) from commodity derivatives in our 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 our Consolidated Statement of Income. (3) Certain contractual reimbursements of operating and maintenance costs totaling $186 million and $171 million for 2022 and 2021, respectively, previously included in Other are now presented in Monetary consideration to conform to the current presentation. Contract Assets The following table presents a reconciliation of our contract assets: Year Ended December 31, 2023 2022 (Millions) Balance at beginning of year $ 29 $ 22 Revenue recognized in excess of amounts invoiced 183 208 Minimum volume commitments invoiced (176) (201) Balance at end of year $ 36 $ 29 Contract Liabilities The following table presents a reconciliation of our contract liabilities: Year Ended December 31, 2023 2022 (Millions) Balance at beginning of year $ 1,043 $ 1,126 Payments received and deferred 190 180 Significant financing component 9 9 Contract liability acquired (disposed) – net 115 2 Recognized in revenue (276) (274) Balance at end of year $ 1,081 $ 1,043 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 MVC 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, 2023, 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, 2023, 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, 2023. Contract Liabilities Remaining Performance Obligations (Millions) 2024 (one year) $ 165 $ 3,828 2025 (one year) 145 3,467 2026 (one year) 139 3,289 2027 (one year) 131 2,627 2028 (one year) 112 2,365 Thereafter 389 13,548 Total $ 1,081 $ 29,124

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	12 Months Ended
Provision (Benefit) for Income Taxes	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes [Text Block]	Note 6 – Provision (Benefit) for Income Taxes The Provision (benefit) for income taxes from continuing operations includes: Year Ended December 31, 2023 2022 2021 (Millions) Current: Federal $ 3 $ (25) $ (1) State 21 19 3 24 (6) 2 Deferred: Federal 872 424 421 State 109 7 88 981 431 509 Provision (benefit) for income taxes $ 1,005 $ 425 $ 511 Reconciliations from the Provision (benefit) at statutory rate from continuing operations to recorded Provision (benefit) for income taxes are as follows: Year Ended December 31, 2023 2022 2021 (Millions) Provision (benefit) at statutory rate $ 925 $ 534 $ 435 Increases (decreases) in taxes resulting from: State income taxes (net of federal benefit) 129 113 71 State deferred income tax rate change (25) (92) — Federal valuation allowance — (70) 3 Federal settlements — (45) — Impact of nontaxable noncontrolling interests (26) (14) (9) Other – net 2 (1) 11 Provision (benefit) for income taxes $ 1,005 $ 425 $ 511 The State deferred income tax rate change benefit of $25 million and $92 million in 2023 and 2022, respectively, 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, 2023 2022 (Millions) Gross deferred income tax liabilities: Property, plant and equipment $ 3,541 $ 3,171 Investments 1,740 1,784 Other 146 138 Total gross deferred income tax liabilities 5,427 5,093 Gross deferred income tax assets: Accrued liabilities 935 1,108 Foreign tax credits 35 91 Federal loss carryovers 398 730 State losses and credits 293 356 Other 103 121 Total gross deferred income tax assets 1,764 2,406 Less valuation allowance 183 200 Net deferred income tax assets 1,581 2,206 Deferred income tax liabilities $ 3,846 $ 2,887 The valuation allowance at December 31, 2023 and 2022 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 2024 and 2042 with some carryovers having indefinite carryforward periods. Federal loss carryovers at December 31, 2023 reflect deferred tax assets on net operating loss carryovers with no expiration date. Cash payments for income taxes (net of refunds) were $31 million and $13 million in 2023 and 2022, respectively. Cash refunds for income taxes (net of payments) were $45 million in 2021. 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 and we received cash refunds totaling $7 million. During the fourth quarter of 2023, we closed the audit for 2018 and made a $5 million payment. We recognize related interest and penalties as a component of Provision (benefit) for income taxes . No significant interest and penalties were recognized for any period presented. There are no interest or penalties relating to uncertain tax positions accrued as of December 31, 2023 and December 31, 2022. Consolidated U.S. Federal income tax returns are open to IRS examination for years after 2019. 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
Employee Benefit Plans	Dec. 31, 2023
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 $60 million in 2023, $53 million in 2022, and $45 million in 2021. 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 2023 2022 2023 2022 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 940 $ 1,133 $ 152 $ 200 Service cost 23 28 1 1 Interest cost 46 31 7 6 Plan participants’ contributions — — 2 2 Benefits paid (71) (78) (13) (12) Net actuarial loss (gain) (1) 68 (162) (4) (45) Settlements — (12) — — Net increase (decrease) in benefit obligation 66 (193) (7) (48) Benefit obligation at end of year 1,006 940 145 152 Change in plan assets: Fair value of plan assets at beginning of year 1,117 1,336 253 287 Actual return on plan assets 120 (132) 17 (27) Employer contributions 1 3 3 3 Plan participants’ contributions — — 2 2 Benefits paid (71) (78) (13) (12) Settlements — (12) — — Net increase (decrease) in fair value of plan assets 50 (219) 9 (34) Fair value of plan assets at end of year 1,167 1,117 262 253 Funded status — overfunded (underfunded) $ 161 $ 177 $ 117 $ 101 Amounts recognized in the Consolidated Balance Sheet: Noncurrent assets $ 187 $ 201 $ 120 $ 105 Current liabilities (4) (2) (3) (4) Noncurrent liabilities (22) (22) — — Funded status — overfunded (underfunded) $ 161 $ 177 $ 117 $ 101 Accumulated benefit obligation $ 998 $ 930 ____________ (1) 2023 amounts are due primarily to changes in the following factors: Pension Benefits - interest crediting rate assumption and discount rate assumptions. 2022 amounts are due primarily to changes in the following factors: Pension Benefits - discount rate assumptions, partially offset by interest crediting rate assumption; Other Postretirement Benefits - discount rate assumption. The following table summarizes information for pension plans with obligations in excess of plan assets at December 31. 2023 2022 (Millions) Projected benefit obligation $ 26 $ 24 Accumulated benefit obligation 24 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 2023 2022 2023 2022 (Millions) Net actuarial gain (loss) $ (45) $ (45) $ 19 $ 18 Additionally, as of December 31, 2023 and 2022, we have $123 million and $130 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 2023 2022 2021 2023 2022 2021 (Millions) Components of net periodic benefit cost (credit): Service cost $ 23 $ 28 $ 30 $ 1 $ 1 $ 1 Interest cost 46 31 28 7 6 5 Expected return on plan assets (57) (44) (43) (10) (10) (10) Amortization of net actuarial loss (gain) 5 12 14 (3) — — Net actuarial loss from settlements — 3 1 — — — Reclassification to regulatory liability — — — — 1 2 Net periodic benefit cost (credit) (1) $ 17 $ 30 $ 30 $ (5) $ (2) $ (2) ____________ (1) Components other than Service cost are included in Other income (expense) – net below Operating income (loss) in our 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 2023 2022 2021 2023 2022 2021 (Millions) Net actuarial gain (loss) arising during the year $ (5) $ (14) $ 40 $ 3 $ 14 $ 29 Amortization of net actuarial loss (gain) 5 12 14 (2) — — Net actuarial loss from settlements — 3 1 — — — Total recognized in Other comprehensive income (loss) $ — $ 1 $ 55 $ 1 $ 14 $ 29 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 2023 2022 2021 2023 2022 2021 Benefit obligations: Discount rate 4.98 % 5.16 % 2.82 % 5.01 % 5.20 % 2.93 % Rate of compensation increase 3.52 3.58 3.67 N/A N/A N/A Cash balance interest crediting rate 4.50 3.50 3.00 N/A N/A N/A Net periodic benefit cost (credit): Discount rate 5.16 % 2.84 % 2.45 % 5.20 % 2.93 % 2.59 % Expected long-term rate of return on plan assets 5.17 3.81 3.69 4.04 3.67 3.61 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 We use mortality tables issued by the Society of Actuaries to measure the benefit obligations. The assumed health care cost trend rate for 2024 is 7.0 percent. This rate decreases to 4.5 percent by 2034. 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, 2023, 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: 2023 Pension Benefits Other Postretirement Benefits Level 1 (1) Level 2 (2) Total Level 1 (1) Level 2 (2) Total (Millions) Cash management funds $ 17 $ — $ 17 $ 99 $ — $ 99 Government debt securities 61 17 78 9 2 11 Corporate debt securities — 311 311 — 44 44 Other 2 5 7 1 — 1 $ 80 $ 333 413 $ 109 $ 46 155 Commingled investment funds (3): Equities 287 41 Fixed income 467 66 Total assets at fair value $ 1,167 $ 262 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 ____________ (1) Level 1 includes assets with fair values based on quoted prices in active markets for identical assets. Cash management funds and U.S. Treasury securities are included in this level. (2) Level 2 includes assets with fair values determined by using significant other observable inputs. This level includes 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) 2024 $ 95 $ 12 2025 96 12 2026 90 11 2027 87 11 2028 84 11 2029-2033 397 49 In 2024, we expect to contribute approximately $2 million to our pension plans and approximately $3 million to our other postretirement benefit plan.

Investing Activities

Investing Activities	12 Months Ended
Investing Activities	Dec. 31, 2023
Investments [Abstract]
Investing Activities [Text Block]	Note 8 – Investing Activities Investments Ownership Interest at December 31, 2023 December 31, 2023 2022 (Millions) Equity method: Appalachia Midstream Investments (1) $ 2,886 $ 2,975 Blue Racer 50% 398 383 OPPL 50% 387 386 Discovery 60% 361 345 Gulfstream 50% 210 220 Laurel Mountain 69% 184 205 RMM (2) 100% — 395 Other Various 188 139 4,614 5,048 Other 23 17 $ 4,637 $ 5,065 ___________ (1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale region with an approximate average 66 percent interest. (2) RMM is a wholly owned subsidiary as of November 30, 2023. See Note 3 – Acquisitions and Divestitures. Basis differential The carrying value of our Appalachia Midstream Investments exceeds our portion of the underlying net assets by approximately $1.1 billion at December 31, 2023 and 2022. 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 $773 million and $1.1 billion at December 31, 2023 and 2022, 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, 2023 2022 2021 (Millions) Appalachia Midstream Investments $ 59 $ 83 $ 84 Discovery 40 41 — Aux Sable Liquid Products LP 38 — — Cardinal Pipeline Company, LLC — 16 — Gulfstream — 14 26 Other 4 12 5 $ 141 $ 166 $ 115 Other investing income (loss) – net The following table presents certain items reflected in Other investing income (loss) – net in our Consolidated Statement of Income: Year Ended December 31, 2023 2022 2021 (Millions) Interest income $ 79 $ 15 $ 7 Gain on remeasurement of RMM investment (Note 3) 30 — — Other (1) 1 — Other investing income (loss) – net $ 108 $ 16 $ 7 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, 2023 2022 2021 (Millions) Appalachia Midstream Investments $ 405 $ 415 $ 433 Gulfstream 98 89 90 Blue Racer 62 49 47 OPPL 56 34 26 RMM 49 52 45 Discovery 49 49 44 Laurel Mountain 42 112 33 Other 35 65 39 $ 796 $ 865 $ 757 Summarized Financial Position and Results of Operations of All Equity-Method Investments December 31, 2023 2022 (Millions) Assets (liabilities): Current assets $ 669 $ 964 Noncurrent assets 11,058 12,701 Current liabilities (358) (632) Noncurrent liabilities (3,619) (3,789) Year Ended December 31, 2023 2022 2021 (Millions) Gross revenue $ 3,714 $ 5,520 $ 4,688 Operating income 966 1,268 1,191 Net income 748 1,102 1,006

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
Property, Plant, and Equipment	Dec. 31, 2023
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 in our Consolidated Balance Sheet for the years ended: Estimated Depreciation December 31, 2023 2022 (Millions) Nonregulated: Natural gas gathering and processing facilities 5 - 40 $ 21,357 $ 19,163 Construction in progress Not applicable 1,138 997 Oil and gas properties Units of production 1,111 874 Other 0 - 45 3,268 2,998 Regulated: Natural gas transmission facilities 1.25 - 8.33 21,083 19,521 Construction in progress Not applicable Not applicable 1,124 708 Other 5 - 45 0.00 - 33.33 2,761 2,796 Total property, plant, and equipment, at cost 51,842 47,057 Accumulated depreciation and amortization (17,531) (16,168) Property, plant, and equipment — net $ 34,311 $ 30,889 __________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2023. 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 $1.660 billion, $1.498 billion, and $1.496 billion in 2023, 2022, and 2021, respectively. Interest capitalized was $54 million, $20 million, and $11 million in 2023, 2022, and 2021, respectively. Regulated Property, plant, and equipment – net includes approximately $389 million and $428 million at December 31, 2023 and 2022, 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 AROs, of which $1.978 billion and $1.827 billion are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued and other current liabilities at December 31, 2023 and 2022, respectively. Year Ended December 31, 2023 2022 (Millions) Balance at beginning of year $ 1,914 $ 1,665 Liabilities incurred 42 77 Liabilities settled (43) (22) Accretion 97 85 Revisions (1) 74 109 Balance at end of year $ 2,084 $ 1,914 ___________ (1) 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 2023 and 2022 revisions reflect changes in removal cost estimates and increases in inflation rates, partially offset by increases in discount rates. The funds Transco collects through a portion of its rates to fund its AROs are deposited into an external trust account dedicated to funding its AROs (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.

Goodwill and Other Intangible A

Goodwill and Other Intangible Assets	12 Months Ended
Goodwill and Other Intangible Assets	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Other Intangible Assets [Text Block]	Note 10 – Goodwill and Other Intangible Assets Goodwill Changes in the carrying amount of goodwill, included in Intangible assets – net of accumulated amortization in our Consolidated Balance Sheet, by reportable segment for the periods indicated are as follows: Transmission & Gulf of Mexico West Total (Millions) December 31, 2021 $ — $ — $ — December 31, 2022 — — — MountainWest Acquisition (Note 3) 400 400 Cureton Acquisition (Note 3) 6 6 RMM Acquisition (Note 3) 57 57 December 31, 2023 $ 400 $ 63 $ 463 Goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with our evaluation of goodwill for impairment during the year ended December 31, 2023. Other Intangible Assets The gross carrying amount and accumulated amortization of other intangible assets, included in Intangible assets – net of accumulated amortization in our Consolidated Balance Sheet, at December 31 are as follows: 2023 2022 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Customer relationships $ 10,237 $ (3,155) $ 10,065 $ (2,801) Transportation and storage capacity contracts 267 (223) 267 (172) Other 6 (2) 6 (2) Other intangible assets $ 10,510 $ (3,380) $ 10,338 $ (2,975) 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 periods of up to 30 years, 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 $360 million, $353 million, and $332 million in 2023, 2022, and 2021, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is $368 million, $368 million, $364 million, $360 million, and $360 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 and Divestitures.) The amortization expense related to transportation and storage capacity contracts was $51 million, $158 million, and $14 million in 2023, 2022, and 2021, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is $21 million, $10 million, $7 million, $4 million, and $2 million.

Accrued and Other Current Liabi

Accrued and Other Current Liabilities	12 Months Ended
Accrued and Other Current Liabilities	Dec. 31, 2023
Accrued Liabilities, Current [Abstract]
Accrued and Other Current Liabilities [Text Block]	Note 11 – Accrued and Other Current Liabilities December 31, 2023 2022 (Millions) Interest on debt $ 322 $ 274 Employee costs 197 218 Contract liabilities 159 141 Alaska refinery contamination litigation (Note 17) 134 21 Asset retirement obligations (Note 9) 106 87 Regulatory liabilities (Note 1) 77 201 Operating lease liabilities (Note 13) 24 25 Other, including accrued loss contingencies 265 303 $ 1,284 $ 1,270

Debt and Banking Arrangements

Debt and Banking Arrangements	12 Months Ended
Debt and Banking Arrangements	Dec. 31, 2023
Debt Disclosure [Abstract]
Debt and Banking Arrangements [Text Block]	Note 12 – Debt and Banking Arrangements Long-Term Debt December 31, 2023 2022 (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 790 809 Other financing obligation — Leidy South 76 77 Other financing obligation — Dalton 250 252 MountainWest: 3.53% Notes due 2028 (Note 3) 100 — 3.91% Notes due 2038 (Note 3) 150 — 4.875% Notes due 2041 (Note 3) 180 — Northwest Pipeline: 7.125% Debentures due 2025 85 85 4% Notes due 2027 500 500 Williams: 4.5% Notes due 2023 — 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 5.4% Notes due 2026 1,100 — 3.75% Notes due 2027 1,450 1,450 5.3% Notes due 2028 900 — 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 1,000 5.65% Notes due 2033 750 — 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 750 750 7.7% Notes due 2027 2 2 RMM deferred consideration obligation (Note 3) 665 — Unamortized debt issuance costs (140) (135) Net unamortized debt premium (discount) (114) (55) Total long-term debt, including current portion 25,713 22,554 Long-term debt due within one year (2,337) (627) Long-term debt $ 23,376 $ 21,927 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, other financing obligations, and the RMM deferred consideration obligation, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years: December 31, 2023 (Millions) 2024 $ 2,338 2025 2,263 2026 2,345 2027 1,993 2028 1,445 Issuances Our senior unsecured public debt issuances for the past three years and subsequent to the balance sheet date are as follows: Issue Date Maturity Date Amount Rate (Millions) January 5, 2024 March 15, 2029 $ 1,100 4.900% January 5, 2024 March 15, 2034 1,000 5.150% August 10, 2023 (1) March 2, 2026 350 5.400% August 10, 2023 August 15, 2028 900 5.300% March 2, 2023 March 2, 2026 750 5.400% March 2, 2023 March 15, 2033 750 5.650% August 8, 2022 August 15, 2032 1,000 4.650% August 8, 2022 August 15, 2052 750 5.300% October 8, 2021 (2) March 15, 2031 600 2.600% October 8, 2021 October 15, 2051 650 3.500% March 2, 2021 March 15, 2031 900 2.600% (1) Additional issuance of the 5.40 percent senior notes due 2026 issued on March 2, 2023, and trade interchangeably with such notes. (2) Additional issuance of the 2.6 percent senior notes due 2031 issued on March 2, 2021, and trade interchangeably with such notes. Retirements Our senior unsecured public debt retirements for the past three years are as follows: Date of Retirement Maturity Date Amount Rate (Millions) November 15, 2023 November 15, 2023 $ 600 4.500% October 17, 2022 January 15, 2023 850 3.700% May 16, 2022 August 15, 2022 750 3.350% January 18, 2022 March 15, 2022 1,250 3.600% September 1, 2021 September 1, 2021 371 7.875% August 16, 2021 November 15, 2021 500 4.000% 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, 2023 Stated Capacity Outstanding (Millions) Long-term credit facility (1) $ 3,750 $ — Letters of credit under certain bilateral bank agreements 16 ________________ (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. In the second quarter of 2023, the maturity date of our Credit Agreement was extended one year and now expires October 8, 2027. The amended Credit Agreement allows the co-borrowers to 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, 2029, under certain circumstances. Additionally, the amended Credit Agreement replaces the London Interbank Offered Rate with the Term Secured Overnight Financing Rate as the benchmark interest rate index. 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 Term Secured Overnight Financing Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin 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. 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, 2023, we are in compliance with these covenants. Commercial Paper Program We have a $3.5 billion commercial paper program. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The net proceeds of issuances of the commercial paper notes are expected to be used to fund planned capital expenditures and for other general corporate purposes. At December 31, 2023, $725 million of commercial paper was outstanding at a weighted-average interest rate of 5.6 percent. We had $350 million of commercial paper outstanding at December 31, 2022 at a weighted-average interest rate of 4.8 percent. Cash Payments for Interest (Net of Amounts Capitalized) Cash payments for interest (net of amounts capitalized) were $1.152 billion in 2023, $1.117 billion in 2022, and $1.137 billion in 2021.

Leases

Leases	12 Months Ended
Leases	Dec. 31, 2023
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, 2023 2022 2021 (Millions) Lease Cost: Operating lease cost $ 38 $ 34 $ 35 Variable lease cost 31 26 15 Sublease income (1) — (1) Total lease cost $ 68 $ 60 $ 49 Cash paid for operating lease liabilities $ 37 $ 33 $ 35 December 31, 2023 2022 (Millions) Other Information: Right-of-use asset (included in Regulatory assets, deferred charges, and other ) $ 159 $ 162 Operating lease liabilities: Current (included in Accrued and other current liabilities ) $ 24 $ 25 Noncurrent (included in Regulatory liabilities, deferred income, and other ) $ 148 $ 148 Weighted-average remaining lease term – operating leases (years) 11 13 Weighted-average discount rate – operating leases 4.78% 4.62% At December 31, 2023, 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) 2024 $ 33 2025 27 2026 27 2027 24 2028 19 Thereafter 100 Total future lease payments 230 Less: Amount representing interest 58 Total obligations under operating leases $ 172 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
Equity-Based Compensation	Dec. 31, 2023
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. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. At December 31, 2023, 21 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 12 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). Employees purchased 250 thousand shares at a weighted-average price of $27.56 per share during 2023. Approximately 0.9 million shares were available for purchase under the ESPP at December 31, 2023. 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 2023, 2022, and 2021 of $77 million, $73 million, and $81 million, respectively. Income tax benefit recognized related to the stock-based compensation expense in 2023, 2022, and 2021 was $19 million, $18 million, and $20 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2023, was $70 million, all of which related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years. Nonvested Restricted Stock Units At December 31, 2023 and 2022, we had restricted stock units outstanding, including performance-based shares, of 6.6 million shares and 6.9 million shares, respectively, with a weighted-average fair value of $28.34 and $23.63, respectively. During 2023, we granted 3.8 million shares of restricted stock units with a weighted-average fair value of $27.43. 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, 2023, there were 1.8 million performance-based shares outstanding. Stock Options There were no stock options granted in 2023, 2022, or 2021. At December 31, 2023, we had 1.5 million stock options that were both outstanding and exercisable, with a weighted-average exercise price of $37.17. The weighted-average remaining contractual life for stock options that were both outstanding and exercisable at December 31, 2023, was 1.8 years. Cash received for the exercise of stock options in 2023 and 2022 was $2 million and $49 million, respectively, and the related income tax benefit recognized in both 2023 and 2022 was $2 million.

Fair Value Measurements, Guaran

Fair Value Measurements, Guarantees, and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2023
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, 2023: Measured on a recurring basis: ARO Trust investments $ 269 $ 269 $ 269 $ — $ — Commodity derivative assets (1) 310 310 141 112 57 Commodity derivative liabilities (1) (285) (285) (3) (278) (4) Interest rate derivatives 6 6 — 6 — Additional disclosures: Long-term debt, including current portion (25,713) (25,553) — (25,553) — Guarantees (37) (28) — (12) (16) Assets (liabilities) at December 31, 2022: Measured on a recurring basis: ARO Trust investments $ 230 $ 230 $ 230 $ — $ — Commodity derivative assets (2) 166 166 20 132 14 Commodity derivative liabilities (2) (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) (1) Commodity derivative assets and liabilities exclude $2 million of net cash collateral in Level 1. (2) Commodity derivative assets and liabilities exclude $202 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 AROs. 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) from commodity derivatives and Net processing commodity expenses in our Consolidated Statement of Income. See Note 16 – Commodity 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, 2023 2022 (Millions) Balance at beginning of period $ (56) $ (15) Gains (losses) included in our Consolidated Statement of Income 91 (31) Purchases, issuances, and settlements 20 (5) Transfers into Level 3 — (24) Transfers out of Level 3 (2) 19 Balance at end of period $ 53 $ (56) A substantial portion of the carrying value of our Level 3 derivatives at December 31, 2023, 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. Interest rate derivatives: At December 31, 2023, we held forward starting interest rate swap agreements with notional amounts totaling $1.15 billion. During January 2024 we terminated certain of these agreements totaling $750 million of notional value coinciding with the issuance of long-term debt (see Note 12 – Debt and Banking Arrangements). The fair value of these derivatives is determined using discounted cash flows considering forward interest rates and the terms of the agreements, corroborated by counterparty valuations, and is classified as a Level 2 measurement. We designated these derivatives as cash flow hedges to reduce interest rate exposure on future debt issuances. Gains and losses on these derivative instruments are reflected as a component of AOCI and will be amortized to earnings as a component of Interest expense in our Consolidated Statement of Income. These forward starting interest rate swaps are reported in Derivative assets and Derivative liabilities in our Consolidated Balance Sheet. 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, as well as the deferred consideration obligation associated with the RMM Acquisition (see Note 3 – Acquisitions and Divestitures), all 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, Inc., (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 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 liquidity exposure is approximately $23 million at December 31, 2023. 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. Concentration of Credit Risk Accounts receivable The following table summarizes concentration of receivables, net of allowances: December 31, 2023 2022 (Millions) NGLs, natural gas, and related products and services $ 589 $ 505 Regulated interstate natural gas transportation and storage 310 311 Marketing of natural gas and NGLs 321 858 Upstream activities 72 97 Accounts Receivable related to revenues from contracts with customers 1,292 1,771 Receivables from derivatives 311 889 Other accounts receivable 52 63 Trade accounts and other receivables - net $ 1,655 $ 2,723 Customers include producers, distribution companies, industrial users, gas marketers, and pipelines primarily located in the continental United States. As a general policy, collateral is not required for receivables with the exception of the marketing receivables discussed below. Customers’ financial condition and credit worthiness are evaluated regularly and, based upon this evaluation, we may obtain collateral to support receivables. We use established credit policies to determine and monitor the creditworthiness of gas marketing and trading counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include U.S. government securities. We also utilize netting agreements whenever possible to mitigate exposure to gas marketing and trading counterparty credit risk. When more than one derivative transaction with the same counterparty is outstanding and a legally enforceable netting agreement exists with that counterparty, the “net” mark-to-market exposure represents a reasonable measure of our credit risk with that counterparty.

Commodity Derivatives

Commodity Derivatives	12 Months Ended
Commodity Derivatives	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivatives [Text Block]	Note 16 – 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. 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 derivatives are recorded as operating activities. We enter into commodity 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, 2023, the notional volume of the net long (short) positions for our commodity derivative contracts were as follows: Commodity Unit of Measure Net Long (Short) Position Index Risk Natural Gas MMBtu 820,590,728 Central Hub Risk - Henry Hub Natural Gas MMBtu (40,757,055) Basis Risk Natural Gas MMBtu 3,091,504 Central Hub Risk - Mont Belvieu Natural Gas Liquids Barrels (1,218,000) Basis Risk Natural Gas Liquids Barrels (50,000) Central Hub Risk - WTI Crude Oil Barrels (155,000) Commodity Derivatives Financial Statement Presentation The fair value of commodity derivatives, which are not designated as hedging instruments for accounting purposes, was reflected as follows: December 31, December 31, Commodity Derivatives Categories Assets (Liabilities) Assets (Liabilities) (Millions) Current $ 623 $ (496) $ 1,099 $ (1,278) Noncurrent 243 (345) 269 (734) Total commodity derivatives $ 866 $ (841) $ 1,368 $ (2,012) Counterparty and collateral netting offset (552) 554 (1,034) 1,236 Amounts recognized in our Consolidated Balance Sheet $ 314 $ (287) $ 334 $ (776) The pre-tax effects of commodity derivative instruments in our Consolidated Statement of Income were as follows: Gain (Loss) Year Ended December 31, 2023 2022 2021 (Millions) Net gain (loss) from commodity derivatives within Total revenues : Realized commodity derivatives designated as hedging instruments $ — $ — $ (55) Realized commodity derivatives not designated as hedging instruments 253 (91) 16 Unrealized commodity derivatives not designated as hedging instruments 703 (296) (109) $ 956 $ (387) $ (148) Net gain (loss) from commodity derivatives within Net processing commodity expenses : Realized commodity derivatives not designated as hedging instruments $ (4) $ 16 $ 2 Unrealized commodity derivatives not designated as hedging instruments (43) 47 — $ (47) $ 63 $ 2 Total net gain (loss) from commodity derivatives $ 909 $ (324) $ (146) Contingent Features Generally, collateral may be provided in the form of 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, 2023, the contractually required collateral in the event of a credit rating downgrade to non-investment grade status was $15 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, 2023, and 2022, net cash collateral held on deposit in broker margin accounts was $2 million and $202 million, respectively.

Contingencies and Commitments

Contingencies and Commitments	12 Months Ended
Contingencies and Commitments	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Contingencies and Commitments [Text Block]	Note 17 – Contingencies 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, plus fees and interest. 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. On May 26, 2023, the Alaska Supreme Court issued its Opinion substantially affirming the Superior Court’s decision. On July 18, 2023, the Superior Court granted our stay of execution of the monetary judgment portions of the judgment while we seek review before the United States Supreme Court. On September 25, 2023, we filed a Petition for a Writ of Certiorari with the United States Supreme Court, which was subsequently denied in January 2024. The North Pole claims were also settled in January 2024. During 2023, we recorded pre-tax charges of $125 million to Income (loss) from discontinued operations in our Consolidated Statement of Income related to these matters. Payments were made in January 2024 and the claims against us are now resolved. 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, which obligations survived Chesapeake’s bankruptcy proceedings. Prior to its bankruptcy, Chesapeake reached a settlement to resolve substantially all Pennsylvania royalty cases pending. During the pendency of the bankruptcy, that settlement was renegotiated. The settlement applies to both Chesapeake and us and does not require any contribution from us. On August 23, 2021, after referral to the United States District Court for the Southern District of Texas by the bankruptcy court, the court approved the settlement. Two objectors filed an appeal with the United States Court of Appeals for the Fifth Circuit. On June 8, 2023, the Court of Appeals vacated the settlement approval and remanded to the United States District Court for the Southern District of Texas with instructions to dismiss the settlement proceedings for lack of jurisdiction. On August 31, 2023, the bankruptcy court entered an order finding the settlement agreements to be null and void. Certain plaintiffs have filed a notice of dismissal of their claims against Chesapeake that arose prior to February 8, 2021 in the United States District Court for the Middle District of Pennsylvania lawsuits. The notice states that plaintiffs are not releasing their claims against the other defendants, including us, or claims against Chesapeake that arose after February 9, 2021. We continue to believe the claims against us are subject to indemnity obligations owed to us by Chesapeake. 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 appealed to the Delaware Supreme Court. The Delaware Supreme Court held oral argument en banc on July 12, 2023. On October 10, 2023, the Delaware Supreme Court issued an opinion affirming the Court of Chancery’s ruling. On October 25, 2023, Energy Transfer filed a motion for reargument with the Delaware Supreme Court. On November 28, 2023, we received a $627 million payment from Energy Transfer for the final order and judgment. On the same day, we paid attorney fees which had been incurred on a contingent fee basis. This resulted in a net gain of $534 million reported as Net gain from Energy Transfer litigation judgment in our Consolidated Statement of Income and included as a component of Modified EBITDA within our Other segment for the year ended December 31, 2023. 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, 2023, we have accrued liabilities totaling $ 48 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, 2023, we have accrued liabilities of $12 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, 2023, 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, 2023, we have accrued environmental liabilities of $26 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, 2023, 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 $243 million at December 31, 2023. Commitments for Gas & NGL Marketing Services pipeline transportation capacity and storage capacity are approximately $687 million at December 31, 2023.

Segment Disclosures

Segment Disclosures	12 Months Ended
Segment Disclosures	Dec. 31, 2023
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: ◦ Income (loss) from discontinued operations; ◦ Provision (benefit) for income taxes; ◦ Interest expense; ◦ Equity earnings (losses); ◦ Other investing income (loss) – net; ◦ 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. Significant noncash items which are components of Modified EBITDA may include unrealized net gain (loss) from commodity derivatives within Total revenues, unrealized net gain (loss) from commodity derivatives within Net processing commodity expenses for our Gas & NGL Marketing segment, charges associated with lower of cost or net realizable value adjustments to our Gas & NGL Marketing segment inventory within Product sales and Product costs in our Consolidated Statement of Income, and impairments of certain assets within Other (income) expense – net within Operating income (loss) . 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, 2023 2022 2021 (Millions) Modified EBITDA by segment: Transmission & Gulf of Mexico $ 3,068 $ 2,674 $ 2,621 Northeast G&P 1,916 1,796 1,712 West 1,238 1,211 961 Gas & NGL Marketing Services 950 (40) 22 Total reportable segments 7,172 5,641 5,316 Modified EBITDA of other business activities 841 434 178 8,013 6,075 5,494 Accretion expense associated with asset retirement obligations for nonregulated operations (59) (51) (45) Depreciation and amortization expenses (2,071) (2,009) (1,842) Equity earnings (losses) 589 637 608 Other investing income (loss) – net 108 16 7 Proportional Modified EBITDA of equity-method investments (939) (979) (970) Interest expense (1,236) (1,147) (1,179) (Provision) benefit for income taxes (1,005) (425) (511) Income (loss) from discontinued operations (97) — — Net income (loss) $ 3,303 $ 2,117 $ 1,562 The following table reflects the reconciliation of Segment revenues to Total revenues as reported in our 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) 2023 Segment revenues: Service revenues External $ 3,766 $ 1,868 $ 1,376 $ 1 $ 15 $ — $ 7,026 Internal 92 28 126 — 1 (247) — Total service revenues 3,858 1,896 1,502 1 16 (247) 7,026 Total service revenues – commodity consideration 38 5 103 — — — 146 Product sales External 146 34 80 2,382 137 — 2,779 Internal 106 98 361 (322) 305 (548) — Total product sales 252 132 441 2,060 442 (548) 2,779 Net gain (loss) from commodity derivatives Realized 2 — 89 115 47 — 253 Unrealized — — — 702 1 — 703 Total net gain (loss) from commodity derivatives (2) 2 — 89 817 48 — 956 Total revenues $ 4,150 $ 2,033 $ 2,135 $ 2,878 $ 506 $ (795) $ 10,907 Other financial information: Additions to long-lived assets $ 2,501 $ 340 $ 1,186 $ 7 $ 279 $ — $ 4,313 Proportional Modified EBITDA of equity-method investments 205 574 162 — (2) — 939 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) from commodity derivatives Realized — — (4) 17 (104) — (91) Unrealized — — — (321) 25 — (296) Total net gain (loss) from 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 Transmission & Gulf of Mexico Northeast G&P West Gas & NGL Marketing Services (1) Other Eliminations Total (Millions) 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) from commodity derivatives Realized — — (44) 25 (20) — (39) Unrealized — — — (109) — — (109) Total net gain (loss) from 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 ______________ (1) 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. (2) We record transactions that qualify as commodity 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 from commodity 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, 2023 December 31, 2022 December 31, 2023 December 31, 2022 (Millions) Transmission & Gulf of Mexico $ 19,705 $ 17,795 $ 652 $ 629 Northeast G&P 13,319 13,539 3,477 3,566 West 12,188 10,710 477 843 Gas & NGL Marketing Services 77 130 — — Other 1,252 1,143 8 10 Total 46,541 43,317 $ 4,614 $ 5,048 Total current assets 4,513 3,797 Regulatory assets, deferred charges, and other 1,573 1,319 Total assets $ 52,627 $ 48,433

Subsequent Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2023
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Note 19 – Subsequent Events Quarterly Dividends to Common Stockholders On January 30, 2024, our board of directors approved a regular quarterly dividend to common stockholders of $0.475 per share payable on March 25, 2024. Gulf Coast Storage Acquisition See Note 3 – Acquisitions and Divestitures for discussion. Long-term Debt Issuance In January 2024, we issued $1.1 billion of 4.9 percent senior unsecured notes due March 15, 2029, and $1 billion of 5.15 percent senior unsecured notes due March 15, 2034 (see Note 12 – Debt and Banking Arrangements). We used a portion of the proceeds in January 2024 to pay down $725 million of commercial paper outstanding at December 31, 2023.

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
Schedule II - Valuation and Qualifying Accounts	Dec. 31, 2023
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) 2023 Deferred tax asset valuation allowance (1) $ 200 $ (17) $ — $ — $ 183 2022 Deferred tax asset valuation allowance (1) 297 (97) — — 200 2021 Deferred tax asset valuation allowance (1) 325 (28) — — 297 __________ (1) Deducted from related assets.

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
Pay vs Performance Disclosure - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net income (loss) attributable to The Williams Companies, Inc.	$ 3,179	$ 2,049	$ 1,517

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

General, Description of Busin_2

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
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.
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 commodity 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, Northwest Pipeline, and MountainWest 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 include 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, trackers, 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, 2023 and 2022 are as follows: December 31, 2023 2022 (Millions) Current assets reported within Other current assets and deferred charges $ 95 $ 138 Noncurrent assets reported within Regulatory assets, deferred charges, and other 527 459 Total regulated assets $ 622 $ 597 Current liabilities reported within Accrued and other current liabilities $ 77 $ 201 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,288 1,233 Total regulated liabilities $ 1,365 $ 1,434
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. 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 nonregulated 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 commodity 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 and Divestitures), 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]	Commodity 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 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 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 from physically settled commodity derivative contracts for commodity sales transactions are recognized in Net gain (loss) from commodity derivatives in our Consolidated Statement of Income. Realized and unrealized gains and losses from non-designated commodity derivative contracts for commodity sales transactions that are financially settled are reported in Net gain (loss) from commodity derivatives in our Consolidated Statement of Income. Net gains and losses from 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 – Commodity 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) from 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) from 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, 2023 and 2022, 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 former is included in Interest expense and 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 may also include any dilutive effect of our preferred stock. 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 business, natural gas 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, 2023 and 2022.
Inventories [Policy Text Block]	Inventories Inventories in our Consolidated Balance Sheet primarily consist of NGLs, materials and supplies, and natural gas in underground storage 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 in our Consolidated Statement of Income (for natural gas marketing inventory as these sales are presented net of the related costs) or in Product costs in our Consolidated Statement of Income 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, Transco, Northwest Pipeline, and MountainWest 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, Transco, Northwest Pipeline, and MountainWest 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.
Goodwill [Policy Text Block]	Goodwill Goodwill included within Intangible assets – net of accumulated amortization in our Consolidated Balance Sheet, as of December 31, 2023, represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, an impairment charge is recorded for the difference (not to exceed the carrying value of goodwill). Judgments and assumptions are inherent in our management’s estimates of fair value.
Intangible assets [Policy Text Block]	Other identifiable intangible assets Our other identifiable 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 other identifiable intangible assets are generally amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.
Impairment of property, plant, and equipment, intangible assets, and investments [Policy Text Block]	Impairment of property, plant, and equipment, intangible assets, and investments We evaluate our property, plant, and equipment and intangible assets for impairment when, in our judgment, events or circumstances, including probable abandonment, indicate that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes, including selling the assets in the near term or holding them for their remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment to be recognized in our consolidated financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist. For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. We evaluate our investments for impairment when, in our judgment, events or circumstances indicate that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in our consolidated financial statements as an impairment charge. Judgment and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.
Equity-method investment basis differences [Policy Text Block]	Equity-method investment basis differences Differences between the carrying value of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in our Consolidated Statement of Income includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.
Leases [Policy Text Block]	Leases We recognize a lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. We have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset. Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 20 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset. We use judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available. When permitted under our lease agreements, we may sublease certain unused office space for fixed periods that could extend up to the length of the original lease agreement.
Pension and other postretirement benefits [Policy Text Block]	Pension and other postretirement benefits The funded status of each of the pension and other postretirement benefit plans is recognized separately in our Consolidated Balance Sheet as either an asset or liability. The plans’ benefit obligations and net periodic benefit costs (credits) are actuarially determined and impacted by various assumptions and estimates. The discount rates are determined separately for each of our pension and other postretirement benefit plans based on an approach specific to our plans. The year-end discount rates are determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows of each plan. The expected long-term rates of return on plan assets are determined by combining a review of the historical returns within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital market projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class. Unrecognized actuarial gains and losses are deferred and recorded in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost (credit). The unrecognized net actuarial losses deferred in AOCI at December 31, 2023 and 2022 were $17 million and $18 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 9 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.)
New Accounting Pronouncements, Policy	Accounting standards issued but not yet adopted In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures , which requires disclosure of significant segment expenses and expanded interim disclosures. This ASU is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, and early adoption is permitted. We do not expect adoption of ASU 2023-07 will have a material impact on our financial statements. In December 2023, the FASB issued ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures , which requires disclose of specific categories in the rate reconciliation and additional information for reconciling items that meet a quantitative threshold. This ASU is effective for fiscal years beginning after December 15, 2024, and early adoption is permitted. We do not expect adoption of ASU 2023-09 will have a material impact on our financial statements.

General, Description of Busin_3

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 and 2022 are as follows: December 31, 2023 2022 (Millions) Current assets reported within Other current assets and deferred charges $ 95 $ 138 Noncurrent assets reported within Regulatory assets, deferred charges, and other 527 459 Total regulated assets $ 622 $ 597 Current liabilities reported within Accrued and other current liabilities $ 77 $ 201 Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other 1,288 1,233 Total regulated liabilities $ 1,365 $ 1,434

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
Variable Interest Entities (Tables)	Dec. 31, 2023
Variable Interest Entity Disclosures [Abstract]
Schedule of Variable Interest Entities [Table Text Block]	The following table presents amounts included in our Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs: December 31, 2023 2022 (Millions) Assets (liabilities): Cash and cash equivalents $ 33 $ 49 Trade accounts and other receivables – net 215 136 Inventories 5 4 Other current assets and deferred charges 4 7 Property, plant, and equipment – net 5,046 5,154 Intangible assets – net of accumulated amortization 2,049 2,158 Regulatory assets, deferred charges, and other 31 29 Accounts payable (109) (76) Accrued and other current liabilities (28) (34) Regulatory liabilities, deferred income, and other (268) (275)

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)		12 Months Ended
Acquisitions and Divestitures (Tables)	Jan. 03, 2024	Dec. 31, 2023
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. for 2023, 2022, and 2021, are presented as if the Gulf Coast Storage Acquisition had been completed on January 1, 2023, the DJ Basin Acquisitions and MountainWest Acquisition had been completed on January 1, 2022, 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 acquisitions 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 transactions or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements. Year Ended December 31, 2023 As Reported Pro Forma Gulf Coast Storage Pro Forma DJ Basin (1) Pro Forma MountainWest (1) Pro Forma Combined (Millions) Revenues $ 10,907 $ 202 $ 270 $ 35 $ 11,414 Net income (loss) attributable to The Williams Companies, Inc. 3,179 53 17 6 3,255 Year Ended December 31, 2022 As Reported Pro Forma DJ Basin Pro Forma MountainWest Pro Forma Trace (1) Pro Forma Combined (Millions) Revenues $ 10,965 $ 218 $ 265 $ 45 $ 11,493 Net income (loss) attributable to The Williams Companies, Inc. 2,049 13 170 18 2,250 Year Ended December 31, 2021 As Reported Pro Forma Trace Pro Forma Sequent (1) 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 (1) Excludes results from operations acquired in the acquisition for the period beginning on the acquisition date, as these results are included in the amounts as reported.
Gulf Coast Storage Acquisition \| Subsequent Event [Member]
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired, which will be included in our Transmission & Gulf of Mexico segment, and liabilities assumed at January 3, 2024. The allocation is considered preliminary because the valuation work has not been completed due to the ongoing review of the valuation results and validation of significant inputs and assumptions. Preliminary fair value measurements were made for certain acquired assets and liabilities, primarily property, plant, and equipment; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified. The fair value of accounts receivable acquired, included in Other current assets in the following table, equals contractual amounts receivable. (Millions) Cash and cash equivalents $ 46 Other current assets 18 Property, plant, and equipment – net 2,042 Other noncurrent assets 2 Total assets acquired $ 2,108 Current liabilities $ (10) Noncurrent liabilities (107) Total liabilities assumed $ (117) Net assets acquired $ 1,991
Cureton Acquisition
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed		The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in our West segment, and liabilities assumed at November 30, 2023. The allocation is considered preliminary because the valuation work has not been completed due to the ongoing review of the valuation results and validation of significant inputs and assumptions. Preliminary fair value measurements were made for certain acquired assets and liabilities, primarily property, plant, and equipment and other intangible assets; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified. The fair value of accounts receivable acquired, included in Other current assets in the following table, equals contractual amounts receivable. (Millions) Cash and cash equivalents $ 2 Other current assets 21 Property, plant, and equipment – net 437 Intangible assets – net of accumulated amortization 117 Other noncurrent assets 4 Total identifiable assets acquired $ 581 Current liabilities $ (25) Noncurrent liabilities (16) Total liabilities assumed $ (41) Net identifiable assets acquired $ 540 Goodwill included in Intangible assets – net of accumulated amortization 6 Net assets acquired $ 546
RMM Acquisition
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed		The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in our West segment, and liabilities assumed at November 30, 2023. The net assets acquired primarily reflect the noncash consideration transferred, which includes the fair value of both our previous equity-method investment and the deferred consideration obligation. The allocation is considered preliminary because the valuation work has not been completed due to the ongoing review of the valuation results and validation of significant inputs and assumptions. Preliminary fair value measurements were made for certain acquired assets and liabilities, primarily property, plant, and equipment and other intangible assets; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified. The fair value of accounts receivable acquired, included in Other current assets in the following table, equals contractual amounts receivable. (Millions) Cash and cash equivalents $ 28 Other current assets 4 Investments 20 Property, plant, and equipment – net 1,041 Intangible assets – net of accumulated amortization 61 Other noncurrent assets 12 Total identifiable assets acquired $ 1,166 Current liabilities $ (44) Noncurrent liabilities (103) Total liabilities assumed $ (147) Net identifiable assets acquired $ 1,019 Goodwill included in Intangible assets – net of accumulated amortization 57 Net assets acquired $ 1,076
MountainWestAcquisition
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed		The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in our Transmission & Gulf of Mexico segment, and liabilities assumed at February 14, 2023. The fair value of accounts receivable acquired equals contractual amounts receivable. After the March 31, 2023, financial statements were issued, we identified adjustments to the preliminary purchase price allocation, primarily resulting in an increase of $19 million in trade accounts and other receivables and decreases of $73 million in property, plant, and equipment and $60 million in other noncurrent liabilities. (Millions) Cash and cash equivalents $ 23 Trade accounts and other receivables 33 Other current assets 26 Investments 20 Property, plant, and equipment – net 1,019 Other noncurrent assets 33 Total identifiable assets acquired $ 1,154 Current liabilities $ (47) Long-term debt (Note 12) (365) Other noncurrent liabilities (95) Total liabilities assumed $ (507) Net identifiable assets acquired $ 647 Goodwill included in Intangible assets – net of accumulated amortization 400 Net assets acquired $ 1,047
Trace Midstream Acquisition
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed		We accounted for the Trace 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 our West segment, and liabilities assumed at April 29, 2022. The fair value of accounts receivable acquired equals contractual amounts receivable. The valuation techniques used consisted of the income approach for valuation of intangible assets and the cost approach for property, plant, and equipment. (Millions) Cash and cash equivalents $ 39 Trade accounts and other receivables 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 our 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 commodity derivative assets and liabilities. (Millions) Cash and cash equivalents $ 8 Trade accounts and other receivables 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
Revenue Recognition (Tables)	Dec. 31, 2023
Revenue Recognition [Abstract]
Disaggregation of Revenue [Table Text Block]	The following table presents our revenue disaggregated by major service line: Regulated Interstate Transportation & Storage Gulf of Mexico Midstream & Storage Northeast West Midstream Gas & NGL Marketing Services Other Eliminations Total (Millions) 2023 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 3,334 $ — $ — $ — $ — $ — $ (60) $ 3,274 Gathering, processing, transportation, fractionation, and storage: Monetary consideration — 443 1,782 1,478 — — (170) 3,533 Commodity consideration — 38 5 103 — — — 146 Other 19 11 87 12 1 — (15) 115 Total service revenues 3,353 492 1,874 1,593 1 — (245) 7,068 Product sales 140 120 132 441 4,615 442 (962) 4,928 Total revenues from contracts with customers 3,493 612 2,006 2,034 4,616 442 (1,207) 11,996 Other revenues (1) 38 15 27 101 4,294 64 (2) 4,537 Other adjustments (2) — — — — (6,032) — 406 (5,626) Total revenues $ 3,531 $ 627 $ 2,033 $ 2,135 $ 2,878 $ 506 $ (803) $ 10,907 2022 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 3,139 $ — $ — $ — $ — $ — $ (72) $ 3,067 Gathering, processing, transportation, fractionation, and storage: Monetary consideration (3) — 381 1,526 1,518 — — (167) 3,258 Commodity consideration — 64 14 182 — — — 260 Other (3) 10 11 102 12 3 — (16) 122 Total service revenues 3,149 456 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 3,328 707 1,776 2,553 10,771 706 (2,068) 17,773 Other revenues (1) 28 10 26 8 7,929 (55) (11) 7,935 Other adjustments (2) — — — — (15,467) — 724 (14,743) Total revenues $ 3,356 $ 717 $ 1,802 $ 2,561 $ 3,233 $ 651 $ (1,355) $ 10,965 Regulated Interstate Transportation & Storage Gulf of Mexico Midstream & Storage Northeast West Midstream Gas & NGL Marketing Services Other Eliminations Total (Millions) 2021 Revenues from contracts with customers: Service revenues: Regulated interstate natural gas transportation and storage $ 2,988 $ — $ — $ — $ — $ — $ (33) $ 2,955 Gathering, processing, transportation, fractionation, and storage: Monetary consideration (3) — 358 1,425 1,227 — — (133) 2,877 Commodity consideration — 52 7 179 — — — 238 Other (3) 10 8 78 9 3 1 (16) 93 Total service revenues 2,998 418 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 3,086 687 1,609 2,058 6,407 334 (1,397) 12,784 Other revenues (1) 13 8 25 (32) 2,632 11 (13) 2,644 Other adjustments (2) — — — — (4,828) — 27 (4,801) Total revenues $ 3,099 $ 695 $ 1,634 $ 2,026 $ 4,211 $ 345 $ (1,383) $ 10,627 ______________________________ (1) Revenues not derived from contracts with customers primarily consist of physical product sales related to commodity derivative contracts, realized and unrealized gains and losses associated with our commodity derivative contracts, which are reported in Net gain (loss) from commodity derivatives in our 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 our Consolidated Statement of Income. (3) Certain contractual reimbursements of operating and maintenance costs totaling $186 million and $171 million for 2022 and 2021, respectively, previously included in Other are now presented in Monetary consideration to conform to the current presentation.
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, 2023 2022 (Millions) Balance at beginning of year $ 29 $ 22 Revenue recognized in excess of amounts invoiced 183 208 Minimum volume commitments invoiced (176) (201) Balance at end of year $ 36 $ 29 Contract Liabilities The following table presents a reconciliation of our contract liabilities: Year Ended December 31, 2023 2022 (Millions) Balance at beginning of year $ 1,043 $ 1,126 Payments received and deferred 190 180 Significant financing component 9 9 Contract liability acquired (disposed) – net 115 2 Recognized in revenue (276) (274) Balance at end of year $ 1,081 $ 1,043
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, 2023. Contract Liabilities Remaining Performance Obligations (Millions) 2024 (one year) $ 165 $ 3,828 2025 (one year) 145 3,467 2026 (one year) 139 3,289 2027 (one year) 131 2,627 2028 (one year) 112 2,365 Thereafter 389 13,548 Total $ 1,081 $ 29,124

Provision (Benefit) for Incom_2

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
Provision (Benefit) for Income Taxes (Tables)	Dec. 31, 2023
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 from continuing operations includes: Year Ended December 31, 2023 2022 2021 (Millions) Current: Federal $ 3 $ (25) $ (1) State 21 19 3 24 (6) 2 Deferred: Federal 872 424 421 State 109 7 88 981 431 509 Provision (benefit) for income taxes $ 1,005 $ 425 $ 511
Provision for income taxes at federal statutory rate [Table Text Block]	Reconciliations from the Provision (benefit) at statutory rate from continuing operations to recorded Provision (benefit) for income taxes are as follows: Year Ended December 31, 2023 2022 2021 (Millions) Provision (benefit) at statutory rate $ 925 $ 534 $ 435 Increases (decreases) in taxes resulting from: State income taxes (net of federal benefit) 129 113 71 State deferred income tax rate change (25) (92) — Federal valuation allowance — (70) 3 Federal settlements — (45) — Impact of nontaxable noncontrolling interests (26) (14) (9) Other – net 2 (1) 11 Provision (benefit) for income taxes $ 1,005 $ 425 $ 511
Deferred tax liabilities and Deferred tax assets [Table Text Block]	Significant components of Deferred income tax liabilities are as follows: December 31, 2023 2022 (Millions) Gross deferred income tax liabilities: Property, plant and equipment $ 3,541 $ 3,171 Investments 1,740 1,784 Other 146 138 Total gross deferred income tax liabilities 5,427 5,093 Gross deferred income tax assets: Accrued liabilities 935 1,108 Foreign tax credits 35 91 Federal loss carryovers 398 730 State losses and credits 293 356 Other 103 121 Total gross deferred income tax assets 1,764 2,406 Less valuation allowance 183 200 Net deferred income tax assets 1,581 2,206 Deferred income tax liabilities $ 3,846 $ 2,887

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
Employee Benefit Plans (Tables)	Dec. 31, 2023
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 2023 2022 2023 2022 (Millions) Change in benefit obligation: Benefit obligation at beginning of year $ 940 $ 1,133 $ 152 $ 200 Service cost 23 28 1 1 Interest cost 46 31 7 6 Plan participants’ contributions — — 2 2 Benefits paid (71) (78) (13) (12) Net actuarial loss (gain) (1) 68 (162) (4) (45) Settlements — (12) — — Net increase (decrease) in benefit obligation 66 (193) (7) (48) Benefit obligation at end of year 1,006 940 145 152 Change in plan assets: Fair value of plan assets at beginning of year 1,117 1,336 253 287 Actual return on plan assets 120 (132) 17 (27) Employer contributions 1 3 3 3 Plan participants’ contributions — — 2 2 Benefits paid (71) (78) (13) (12) Settlements — (12) — — Net increase (decrease) in fair value of plan assets 50 (219) 9 (34) Fair value of plan assets at end of year 1,167 1,117 262 253 Funded status — overfunded (underfunded) $ 161 $ 177 $ 117 $ 101 Amounts recognized in the Consolidated Balance Sheet: Noncurrent assets $ 187 $ 201 $ 120 $ 105 Current liabilities (4) (2) (3) (4) Noncurrent liabilities (22) (22) — — Funded status — overfunded (underfunded) $ 161 $ 177 $ 117 $ 101 Accumulated benefit obligation $ 998 $ 930 ____________ (1) 2023 amounts are due primarily to changes in the following factors: Pension Benefits - interest crediting rate assumption and discount rate assumptions. 2022 amounts are due primarily to changes in the following factors: Pension Benefits - discount rate assumptions, partially offset by interest crediting rate assumption; Other Postretirement Benefits - discount rate assumption.
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. 2023 2022 (Millions) Projected benefit obligation $ 26 $ 24 Accumulated benefit obligation 24 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 2023 2022 2023 2022 (Millions) Net actuarial gain (loss) $ (45) $ (45) $ 19 $ 18
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 2023 2022 2021 2023 2022 2021 (Millions) Components of net periodic benefit cost (credit): Service cost $ 23 $ 28 $ 30 $ 1 $ 1 $ 1 Interest cost 46 31 28 7 6 5 Expected return on plan assets (57) (44) (43) (10) (10) (10) Amortization of net actuarial loss (gain) 5 12 14 (3) — — Net actuarial loss from settlements — 3 1 — — — Reclassification to regulatory liability — — — — 1 2 Net periodic benefit cost (credit) (1) $ 17 $ 30 $ 30 $ (5) $ (2) $ (2) ____________ (1) Components other than Service cost are included in Other income (expense) – net below Operating income (loss) in our 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 2023 2022 2021 2023 2022 2021 (Millions) Net actuarial gain (loss) arising during the year $ (5) $ (14) $ 40 $ 3 $ 14 $ 29 Amortization of net actuarial loss (gain) 5 12 14 (2) — — Net actuarial loss from settlements — 3 1 — — — Total recognized in Other comprehensive income (loss) $ — $ 1 $ 55 $ 1 $ 14 $ 29
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 2023 2022 2021 2023 2022 2021 Benefit obligations: Discount rate 4.98 % 5.16 % 2.82 % 5.01 % 5.20 % 2.93 % Rate of compensation increase 3.52 3.58 3.67 N/A N/A N/A Cash balance interest crediting rate 4.50 3.50 3.00 N/A N/A N/A Net periodic benefit cost (credit): Discount rate 5.16 % 2.84 % 2.45 % 5.20 % 2.93 % 2.59 % Expected long-term rate of return on plan assets 5.17 3.81 3.69 4.04 3.67 3.61 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
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: 2023 Pension Benefits Other Postretirement Benefits Level 1 (1) Level 2 (2) Total Level 1 (1) Level 2 (2) Total (Millions) Cash management funds $ 17 $ — $ 17 $ 99 $ — $ 99 Government debt securities 61 17 78 9 2 11 Corporate debt securities — 311 311 — 44 44 Other 2 5 7 1 — 1 $ 80 $ 333 413 $ 109 $ 46 155 Commingled investment funds (3): Equities 287 41 Fixed income 467 66 Total assets at fair value $ 1,167 $ 262 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 ____________ (1) Level 1 includes assets with fair values based on quoted prices in active markets for identical assets. Cash management funds and U.S. Treasury securities are included in this level. (2) Level 2 includes assets with fair values determined by using significant other observable inputs. This level includes 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) 2024 $ 95 $ 12 2025 96 12 2026 90 11 2027 87 11 2028 84 11 2029-2033 397 49

Investing Activities (Tables)

Investing Activities (Tables)	12 Months Ended
Investing Activities (Tables)	Dec. 31, 2023
Investments [Abstract]
Investments [Table Text Block]	Ownership Interest at December 31, 2023 December 31, 2023 2022 (Millions) Equity method: Appalachia Midstream Investments (1) $ 2,886 $ 2,975 Blue Racer 50% 398 383 OPPL 50% 387 386 Discovery 60% 361 345 Gulfstream 50% 210 220 Laurel Mountain 69% 184 205 RMM (2) 100% — 395 Other Various 188 139 4,614 5,048 Other 23 17 $ 4,637 $ 5,065 ___________ (1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale region with an approximate average 66 percent interest. (2) RMM is a wholly owned subsidiary as of November 30, 2023. See Note 3 – Acquisitions and Divestitures.
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, 2023 2022 2021 (Millions) Appalachia Midstream Investments $ 59 $ 83 $ 84 Discovery 40 41 — Aux Sable Liquid Products LP 38 — — Cardinal Pipeline Company, LLC — 16 — Gulfstream — 14 26 Other 4 12 5 $ 141 $ 166 $ 115
Investment Income	Other investing income (loss) – net The following table presents certain items reflected in Other investing income (loss) – net in our Consolidated Statement of Income: Year Ended December 31, 2023 2022 2021 (Millions) Interest income $ 79 $ 15 $ 7 Gain on remeasurement of RMM investment (Note 3) 30 — — Other (1) 1 — Other investing income (loss) – net $ 108 $ 16 $ 7
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, 2023 2022 2021 (Millions) Appalachia Midstream Investments $ 405 $ 415 $ 433 Gulfstream 98 89 90 Blue Racer 62 49 47 OPPL 56 34 26 RMM 49 52 45 Discovery 49 49 44 Laurel Mountain 42 112 33 Other 35 65 39 $ 796 $ 865 $ 757
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, 2023 2022 (Millions) Assets (liabilities): Current assets $ 669 $ 964 Noncurrent assets 11,058 12,701 Current liabilities (358) (632) Noncurrent liabilities (3,619) (3,789) Year Ended December 31, 2023 2022 2021 (Millions) Gross revenue $ 3,714 $ 5,520 $ 4,688 Operating income 966 1,268 1,191 Net income 748 1,102 1,006

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
Property, Plant, and Equipment (Tables)	Dec. 31, 2023
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 in our Consolidated Balance Sheet for the years ended: Estimated Depreciation December 31, 2023 2022 (Millions) Nonregulated: Natural gas gathering and processing facilities 5 - 40 $ 21,357 $ 19,163 Construction in progress Not applicable 1,138 997 Oil and gas properties Units of production 1,111 874 Other 0 - 45 3,268 2,998 Regulated: Natural gas transmission facilities 1.25 - 8.33 21,083 19,521 Construction in progress Not applicable Not applicable 1,124 708 Other 5 - 45 0.00 - 33.33 2,761 2,796 Total property, plant, and equipment, at cost 51,842 47,057 Accumulated depreciation and amortization (17,531) (16,168) Property, plant, and equipment — net $ 34,311 $ 30,889 __________ (1) Estimated useful life and depreciation rates are presented as of December 31, 2023. 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 AROs, of which $1.978 billion and $1.827 billion are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued and other current liabilities at December 31, 2023 and 2022, respectively. Year Ended December 31, 2023 2022 (Millions) Balance at beginning of year $ 1,914 $ 1,665 Liabilities incurred 42 77 Liabilities settled (43) (22) Accretion 97 85 Revisions (1) 74 109 Balance at end of year $ 2,084 $ 1,914 ___________ (1)

Goodwill and Other Intangible_2

Goodwill and Other Intangible Assets (Tables)	12 Months Ended
Goodwill and Other Intangible Assets (Tables)	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill [Table Text Block]	Changes in the carrying amount of goodwill, included in Intangible assets – net of accumulated amortization in our Consolidated Balance Sheet, by reportable segment for the periods indicated are as follows: Transmission & Gulf of Mexico West Total (Millions) December 31, 2021 $ — $ — $ — December 31, 2022 — — — MountainWest Acquisition (Note 3) 400 400 Cureton Acquisition (Note 3) 6 6 RMM Acquisition (Note 3) 57 57 December 31, 2023 $ 400 $ 63 $ 463
Schedule of Finite-Lived Intangible Assets [Table Text Block]	The gross carrying amount and accumulated amortization of other intangible assets, included in Intangible assets – net of accumulated amortization in our Consolidated Balance Sheet, at December 31 are as follows: 2023 2022 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (Millions) Customer relationships $ 10,237 $ (3,155) $ 10,065 $ (2,801) Transportation and storage capacity contracts 267 (223) 267 (172) Other 6 (2) 6 (2) Other intangible assets $ 10,510 $ (3,380) $ 10,338 $ (2,975)

Accrued and Other Current Lia_2

Accrued and Other Current Liabilities (Tables)	12 Months Ended
Accrued and Other Current Liabilities (Tables)	Dec. 31, 2023
Accrued Liabilities, Current [Abstract]
Accrued and Other Current Liabilities [Table Text Block]	December 31, 2023 2022 (Millions) Interest on debt $ 322 $ 274 Employee costs 197 218 Contract liabilities 159 141 Alaska refinery contamination litigation (Note 17) 134 21 Asset retirement obligations (Note 9) 106 87 Regulatory liabilities (Note 1) 77 201 Operating lease liabilities (Note 13) 24 25 Other, including accrued loss contingencies 265 303 $ 1,284 $ 1,270

Debt and Banking Arrangements (

Debt and Banking Arrangements (Tables)	12 Months Ended
Debt and Banking Arrangements (Tables)	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	Long-Term Debt December 31, 2023 2022 (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 790 809 Other financing obligation — Leidy South 76 77 Other financing obligation — Dalton 250 252 MountainWest: 3.53% Notes due 2028 (Note 3) 100 — 3.91% Notes due 2038 (Note 3) 150 — 4.875% Notes due 2041 (Note 3) 180 — Northwest Pipeline: 7.125% Debentures due 2025 85 85 4% Notes due 2027 500 500 Williams: 4.5% Notes due 2023 — 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 5.4% Notes due 2026 1,100 — 3.75% Notes due 2027 1,450 1,450 5.3% Notes due 2028 900 — 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 1,000 5.65% Notes due 2033 750 — 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 750 750 7.7% Notes due 2027 2 2 RMM deferred consideration obligation (Note 3) 665 — Unamortized debt issuance costs (140) (135) Net unamortized debt premium (discount) (114) (55) Total long-term debt, including current portion 25,713 22,554 Long-term debt due within one year (2,337) (627) Long-term debt $ 23,376 $ 21,927
Schedule of Maturities of Long-term Debt [Table Text Block]	The following table presents aggregate minimum maturities of long-term debt, other financing obligations, and the RMM deferred consideration obligation, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years: December 31, 2023 (Millions) 2024 $ 2,338 2025 2,263 2026 2,345 2027 1,993 2028 1,445
Schedule of Debt Issuances	Our senior unsecured public debt issuances for the past three years and subsequent to the balance sheet date are as follows: Issue Date Maturity Date Amount Rate (Millions) January 5, 2024 March 15, 2029 $ 1,100 4.900% January 5, 2024 March 15, 2034 1,000 5.150% August 10, 2023 (1) March 2, 2026 350 5.400% August 10, 2023 August 15, 2028 900 5.300% March 2, 2023 March 2, 2026 750 5.400% March 2, 2023 March 15, 2033 750 5.650% August 8, 2022 August 15, 2032 1,000 4.650% August 8, 2022 August 15, 2052 750 5.300% October 8, 2021 (2) March 15, 2031 600 2.600% October 8, 2021 October 15, 2051 650 3.500% March 2, 2021 March 15, 2031 900 2.600% (1) Additional issuance of the 5.40 percent senior notes due 2026 issued on March 2, 2023, and trade interchangeably with such notes. (2) Additional issuance of the 2.6 percent senior notes due 2031 issued on March 2, 2021, and trade interchangeably with such notes.
Schedule of Extinguishment of Debt	Our senior unsecured public debt retirements for the past three years are as follows: Date of Retirement Maturity Date Amount Rate (Millions) November 15, 2023 November 15, 2023 $ 600 4.500% October 17, 2022 January 15, 2023 850 3.700% May 16, 2022 August 15, 2022 750 3.350% January 18, 2022 March 15, 2022 1,250 3.600% September 1, 2021 September 1, 2021 371 7.875% August 16, 2021 November 15, 2021 500 4.000%
Schedule of Line of Credit Facilities [Table Text Block]	Credit Facility December 31, 2023 Stated Capacity Outstanding (Millions) Long-term credit facility (1) $ 3,750 $ — Letters of credit under certain bilateral bank agreements 16 ________________ (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
Leases (Tables)	Dec. 31, 2023
Leases [Abstract]
Lease, Cost [Table Text Block]	Year Ended December 31, 2023 2022 2021 (Millions) Lease Cost: Operating lease cost $ 38 $ 34 $ 35 Variable lease cost 31 26 15 Sublease income (1) — (1) Total lease cost $ 68 $ 60 $ 49 Cash paid for operating lease liabilities $ 37 $ 33 $ 35 December 31, 2023 2022 (Millions) Other Information: Right-of-use asset (included in Regulatory assets, deferred charges, and other ) $ 159 $ 162 Operating lease liabilities: Current (included in Accrued and other current liabilities ) $ 24 $ 25 Noncurrent (included in Regulatory liabilities, deferred income, and other ) $ 148 $ 148 Weighted-average remaining lease term – operating leases (years) 11 13 Weighted-average discount rate – operating leases 4.78% 4.62%
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	At December 31, 2023, 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) 2024 $ 33 2025 27 2026 27 2027 24 2028 19 Thereafter 100 Total future lease payments 230 Less: Amount representing interest 58 Total obligations under operating leases $ 172

Fair Value Measurements, Guar_2

Fair Value Measurements, Guarantees, and Concentration of Credit Risk (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023: Measured on a recurring basis: ARO Trust investments $ 269 $ 269 $ 269 $ — $ — Commodity derivative assets (1) 310 310 141 112 57 Commodity derivative liabilities (1) (285) (285) (3) (278) (4) Interest rate derivatives 6 6 — 6 — Additional disclosures: Long-term debt, including current portion (25,713) (25,553) — (25,553) — Guarantees (37) (28) — (12) (16) Assets (liabilities) at December 31, 2022: Measured on a recurring basis: ARO Trust investments $ 230 $ 230 $ 230 $ — $ — Commodity derivative assets (2) 166 166 20 132 14 Commodity derivative liabilities (2) (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) (1) Commodity derivative assets and liabilities exclude $2 million of net cash collateral in Level 1. (2) Commodity derivative assets and liabilities exclude $202 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, 2023 2022 (Millions) Balance at beginning of period $ (56) $ (15) Gains (losses) included in our Consolidated Statement of Income 91 (31) Purchases, issuances, and settlements 20 (5) Transfers into Level 3 — (24) Transfers out of Level 3 (2) 19 Balance at end of period $ 53 $ (56)
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, 2023 2022 (Millions) NGLs, natural gas, and related products and services $ 589 $ 505 Regulated interstate natural gas transportation and storage 310 311 Marketing of natural gas and NGLs 321 858 Upstream activities 72 97 Accounts Receivable related to revenues from contracts with customers 1,292 1,771 Receivables from derivatives 311 889 Other accounts receivable 52 63 Trade accounts and other receivables - net $ 1,655 $ 2,723

Commodity Derivatives (Tables)

Commodity Derivatives (Tables)	12 Months Ended
Commodity Derivatives (Tables)	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	At December 31, 2023, the notional volume of the net long (short) positions for our commodity derivative contracts were as follows: Commodity Unit of Measure Net Long (Short) Position Index Risk Natural Gas MMBtu 820,590,728 Central Hub Risk - Henry Hub Natural Gas MMBtu (40,757,055) Basis Risk Natural Gas MMBtu 3,091,504 Central Hub Risk - Mont Belvieu Natural Gas Liquids Barrels (1,218,000) Basis Risk Natural Gas Liquids Barrels (50,000) Central Hub Risk - WTI Crude Oil Barrels (155,000)
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location	The fair value of commodity derivatives, which are not designated as hedging instruments for accounting purposes, was reflected as follows: December 31, December 31, Commodity Derivatives Categories Assets (Liabilities) Assets (Liabilities) (Millions) Current $ 623 $ (496) $ 1,099 $ (1,278) Noncurrent 243 (345) 269 (734) Total commodity derivatives $ 866 $ (841) $ 1,368 $ (2,012) Counterparty and collateral netting offset (552) 554 (1,034) 1,236 Amounts recognized in our Consolidated Balance Sheet $ 314 $ (287) $ 334 $ (776)
Pretax Effect Of Interest Rate And Energy Related Derivatives	The pre-tax effects of commodity derivative instruments in our Consolidated Statement of Income were as follows: Gain (Loss) Year Ended December 31, 2023 2022 2021 (Millions) Net gain (loss) from commodity derivatives within Total revenues : Realized commodity derivatives designated as hedging instruments $ — $ — $ (55) Realized commodity derivatives not designated as hedging instruments 253 (91) 16 Unrealized commodity derivatives not designated as hedging instruments 703 (296) (109) $ 956 $ (387) $ (148) Net gain (loss) from commodity derivatives within Net processing commodity expenses : Realized commodity derivatives not designated as hedging instruments $ (4) $ 16 $ 2 Unrealized commodity derivatives not designated as hedging instruments (43) 47 — $ (47) $ 63 $ 2 Total net gain (loss) from commodity derivatives $ 909 $ (324) $ (146)

Segment Disclosures (Tables)

Segment Disclosures (Tables)	12 Months Ended
Segment Disclosures (Tables)	Dec. 31, 2023
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, 2023 2022 2021 (Millions) Modified EBITDA by segment: Transmission & Gulf of Mexico $ 3,068 $ 2,674 $ 2,621 Northeast G&P 1,916 1,796 1,712 West 1,238 1,211 961 Gas & NGL Marketing Services 950 (40) 22 Total reportable segments 7,172 5,641 5,316 Modified EBITDA of other business activities 841 434 178 8,013 6,075 5,494 Accretion expense associated with asset retirement obligations for nonregulated operations (59) (51) (45) Depreciation and amortization expenses (2,071) (2,009) (1,842) Equity earnings (losses) 589 637 608 Other investing income (loss) – net 108 16 7 Proportional Modified EBITDA of equity-method investments (939) (979) (970) Interest expense (1,236) (1,147) (1,179) (Provision) benefit for income taxes (1,005) (425) (511) Income (loss) from discontinued operations (97) — — Net income (loss) $ 3,303 $ 2,117 $ 1,562
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 our 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) 2023 Segment revenues: Service revenues External $ 3,766 $ 1,868 $ 1,376 $ 1 $ 15 $ — $ 7,026 Internal 92 28 126 — 1 (247) — Total service revenues 3,858 1,896 1,502 1 16 (247) 7,026 Total service revenues – commodity consideration 38 5 103 — — — 146 Product sales External 146 34 80 2,382 137 — 2,779 Internal 106 98 361 (322) 305 (548) — Total product sales 252 132 441 2,060 442 (548) 2,779 Net gain (loss) from commodity derivatives Realized 2 — 89 115 47 — 253 Unrealized — — — 702 1 — 703 Total net gain (loss) from commodity derivatives (2) 2 — 89 817 48 — 956 Total revenues $ 4,150 $ 2,033 $ 2,135 $ 2,878 $ 506 $ (795) $ 10,907 Other financial information: Additions to long-lived assets $ 2,501 $ 340 $ 1,186 $ 7 $ 279 $ — $ 4,313 Proportional Modified EBITDA of equity-method investments 205 574 162 — (2) — 939 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) from commodity derivatives Realized — — (4) 17 (104) — (91) Unrealized — — — (321) 25 — (296) Total net gain (loss) from 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 Transmission & Gulf of Mexico Northeast G&P West Gas & NGL Marketing Services (1) Other Eliminations Total (Millions) 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) from commodity derivatives Realized — — (44) 25 (20) — (39) Unrealized — — — (109) — — (109) Total net gain (loss) from 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 ______________ (1) 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. (2) We record transactions that qualify as commodity 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 from commodity 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, 2023 December 31, 2022 December 31, 2023 December 31, 2022 (Millions) Transmission & Gulf of Mexico $ 19,705 $ 17,795 $ 652 $ 629 Northeast G&P 13,319 13,539 3,477 3,566 West 12,188 10,710 477 843 Gas & NGL Marketing Services 77 130 — — Other 1,252 1,143 8 10 Total 46,541 43,317 $ 4,614 $ 5,048 Total current assets 4,513 3,797 Regulatory assets, deferred charges, and other 1,573 1,319 Total assets $ 52,627 $ 48,433

General, Description of Busin_4

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
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	100%
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%
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, 2023	Dec. 31, 2022
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets, Current	$ 95	$ 138
Regulatory Assets, Noncurrent	527	459
Total regulated assets	622	597
Regulatory liabilities (Note 1)	77	201
Regulatory Liabilities, Noncurrent	1,288	1,233
Total regulated liabilities	$ 1,365	1,434
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	$ 0	(24)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Retirement Benefits, Description [Abstract]
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ 17	$ 18
Pension Benefits [Member]
Retirement Benefits, Description [Abstract]
Approximate Amortization Period Of Net Actuarial Gain Loss	9 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%

Share Repurchase Program (Detai

Share Repurchase Program (Details) - USD ($) $ in Millions	12 Months Ended
Share Repurchase Program (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Sep. 03, 2021
Equity, Class of Treasury Stock [Line Items]
Stock Repurchase Program, Authorized Amount				$ 1,500
Purchases of treasury stock	$ 130	$ 9	$ 0

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Variable Interest Entity [Line Items]
Equity-method investments	$ 4,614	$ 5,048
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	2,150	152	$ 1,680	$ 142
Receivables, Net, Current	1,655	2,723
Inventory, Net	274	320
Other current assets and deferred charges	195	279
Property, Plant and Equipment, Net	34,311	30,889
Intangible assets – net of accumulated amortization	7,593	7,363
Other Assets, Noncurrent	1,573	1,319
Accounts payable	(1,379)	(2,327)
Accrued Liabilities, Current	(1,284)	(1,270)
Other Liabilities and Deferred Revenue, Noncurrent	(4,684)	(4,684)
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	33	49
Receivables, Net, Current	215	136
Inventory, Net	5	4
Other current assets and deferred charges	4	7
Property, Plant and Equipment, Net	5,046	5,154
Intangible assets – net of accumulated amortization	2,049	2,158
Other Assets, Noncurrent	31	29
Accounts payable	(109)	(76)
Accrued Liabilities, Current	(28)	(34)
Other Liabilities and Deferred Revenue, Noncurrent	$ (268)	$ (275)
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	$ 44
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	$ 27

Acquisitions (Details)

Acquisitions (Details) - USD ($) $ in Millions										1 Months Ended	6 Months Ended	8 Months Ended	9 Months Ended	11 Months Ended	12 Months Ended
Acquisitions (Details) - USD ($) $ in Millions		Jan. 03, 2024	Dec. 31, 2023	Nov. 30, 2023	Feb. 14, 2023	Dec. 31, 2022	Aug. 31, 2022	Apr. 29, 2022	Jul. 01, 2021	Dec. 31, 2023	Dec. 31, 2021	Dec. 31, 2022	Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Business Acquisition [Line Items]
Payments to Acquire Businesses, Net of Cash Acquired															$ 1,568		$ 933		$ 151
Revenues															10,907		10,965		10,627
Modified EBITDA Earnings Loss															8,013		6,075		5,494
Goodwill			$ 463			$ 0				$ 463	$ 0	$ 0	$ 463	$ 463	463		0		0
Net income (loss) attributable to The Williams Companies, Inc.															3,179		2,049		1,517
Payments to Acquire Productive Assets															4,313		3,598		1,855
Pro Forma [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue															11,414		11,493		10,933
Business Acquisition, Pro Forma Net Income (Loss)															3,255		2,250		1,563
Product [Member]
Business Acquisition [Line Items]
Revenues															2,779		4,556		4,536
Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1]														956		(387)		(148)
Gain (Loss) on Derivative Instruments \| Energy Related Derivative \| Not Designated as Hedging Instrument [Member]
Business Acquisition [Line Items]
Unrealized Gain (Loss) on Derivatives															703		(296)		(109)
Operating Segments [Member]
Business Acquisition [Line Items]
Modified EBITDA Earnings Loss															7,172		5,641		5,316
Transmission And Gulf Of Mexico [Member]
Business Acquisition [Line Items]
Goodwill			400			0				400	0	0	400	400	400		0		0
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															146		228		231
Transmission And Gulf Of Mexico [Member] \| Operating Segments [Member]
Business Acquisition [Line Items]
Revenues															4,150		4,047		3,786
Modified EBITDA Earnings Loss															3,068		2,674		2,621
Payments to Acquire Productive Assets															2,501		1,420		861
Transmission And Gulf Of Mexico [Member] \| Operating Segments [Member] \| Product [Member]
Business Acquisition [Line Items]
Revenues															252		404		349
Transmission And Gulf Of Mexico [Member] \| Operating Segments [Member] \| Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1]														2		0		0
West [Member]
Business Acquisition [Line Items]
Goodwill			63			0				63	0	$ 0	63	63	63		0		0
West [Member] \| Product [Member]
Business Acquisition [Line Items]
Revenues															80		145		60
West [Member] \| Operating Segments [Member]
Business Acquisition [Line Items]
Revenues															2,135		2,561		2,026
Modified EBITDA Earnings Loss															1,238		1,211		961
Payments to Acquire Productive Assets															1,186		1,507		209
West [Member] \| Operating Segments [Member] \| Product [Member]
Business Acquisition [Line Items]
Revenues															441		841		643
West [Member] \| Operating Segments [Member] \| Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1]														89		(4)		(44)
Gas & NGL Marketing Services \| Product [Member]
Business Acquisition [Line Items]
Revenues	[2]														2,382		4,052		4,094
Gas & NGL Marketing Services \| Operating Segments [Member]
Business Acquisition [Line Items]
Revenues	[2]														2,878		3,233		4,211
Modified EBITDA Earnings Loss															950		(40)		22
Payments to Acquire Productive Assets	[2]														7		4		1
Gas & NGL Marketing Services \| Operating Segments [Member] \| Product [Member]
Business Acquisition [Line Items]
Revenues	[2]														2,060		3,534		4,292
Gas & NGL Marketing Services \| Operating Segments [Member] \| Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1],[2]														817		(304)		(84)
Gulf Coast Storage Acquisition \| Pro Forma [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue															202
Business Acquisition, Pro Forma Net Income (Loss)															53
Gulf Coast Storage Acquisition \| Transmission And Gulf Of Mexico [Member] \| Selling, general and administrative expenses [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs															1
Cureton Acquisition
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				100%
Business Combination, Consideration Transferred				$ 546
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents				2
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other				21
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment				437
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles				117
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets				4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets				581
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other				(25)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other				(16)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities				(41)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net				540
Goodwill				6
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net				$ 546
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				24%
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension				10 years
Cureton Acquisition \| West [Member] \| Selling, general and administrative expenses [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs															6
Cureton Acquisition \| West [Member] \| Operating Segments [Member]
Business Acquisition [Line Items]
Revenues										35
Modified EBITDA Earnings Loss										7
RMM Acquisition
Business Acquisition [Line Items]
Business Combination, Consideration Transferred				$ 704
Business Combination, Consideration Transferred, Liabilities Incurred			$ 665			$ 0
Business Combination, Step Acquisition, Equity Interest in Acquiree, Fair Value				406
Gain on remeasurement of equity-method investment (Note 2)				30											30		$ 0		0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents				28
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other				4
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Investments				20
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment				1,041
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles				61
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets				12
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets				1,166
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other				(44)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other				(103)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities				(147)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net				1,019
Goodwill				57
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net				1,076
Business Acquisition, Goodwill, Expected Tax Deductible Amount				$ 57
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				18%
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension				10 years
RMM Acquisition \| West [Member] \| Rocky Mountain Midstream Holdings LLC [Member]
Business Acquisition [Line Items]
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage						50%						50%					50%
Business Acquisition, Percentage of Voting Interests Acquired				50%
RMM Acquisition \| West [Member] \| Operating Segments [Member]
Business Acquisition [Line Items]
Revenues										53
Modified EBITDA Earnings Loss										$ 12
DJ Basin Acquisitions \| Pro Forma [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue															270	[3]	$ 218
Business Acquisition, Pro Forma Net Income (Loss)															17	[3]	13
MountainWestAcquisition
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired					100%
Business Combination, Consideration Transferred					$ 1,080
Business Combination, Consideration Transferred, Liabilities Incurred					430
Payments to Acquire Businesses, Net of Cash Acquired															1,024
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Receivables													19
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment													(73)
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Liabilities													$ (60)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents					23
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables					33
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other					26
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Investments					20
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment					1,019
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets					33
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets					1,154
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other					(47)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-Term Debt					(365)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other					(95)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities					(507)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net					647
Goodwill					400
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net					1,047
Business Acquisition, Goodwill, Expected Tax Deductible Amount					$ 400
MountainWestAcquisition \| Pro Forma [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue															35	[3]	265
Business Acquisition, Pro Forma Net Income (Loss)															6	[3]	170
MountainWestAcquisition \| Transmission And Gulf Of Mexico [Member]
Business Acquisition [Line Items]
Business Combination, Transition Related Costs														27
MountainWestAcquisition \| Transmission And Gulf Of Mexico [Member] \| Selling, general and administrative expenses [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs															$ 16
MountainWestAcquisition \| Transmission And Gulf Of Mexico [Member] \| Operating Segments [Member]
Business Acquisition [Line Items]
Revenues														225
Modified EBITDA Earnings Loss														$ 122
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	[3]	118
Business Acquisition, Pro Forma Net Income (Loss)																	$ 18	[3]	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 Acquisition, Percentage of Voting Interests Acquired									100%
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	[3]																		188
Business Acquisition, Pro Forma Net Income (Loss)	[3]																		$ 4
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 \| 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
Subsequent Event [Member] \| Gulf Coast Storage Acquisition
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		100%
Business Combination, Consideration Transferred		$ 1,950
Business Combination, Consideration Transferred, Liabilities Incurred		100
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents		46
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other		18
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		2,042
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets		2
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets		2,108
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other		(10)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other		(107)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities		(117)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		$ 1,991

[1]We record transactions that qualify as commodity 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 from commodity derivatives held for energy trading purposes are presented on a net basis in revenue.[2]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.[3] Excludes results from operations acquired in the acquisition for the period beginning on the acquisition date, as these results are included in the amounts as reported.

Divestitures (Details)

Divestitures (Details) - USD ($) $ in Millions		12 Months Ended
Divestitures (Details) - USD ($) $ in Millions	Sep. 29, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Business		$ 129	$ 0	$ 0
Certain Gulf Coast Liquids Pipelines
Business Acquisition [Line Items]
Disposal Group, Consideration	$ 348
Certain Gulf Coast Liquids Pipelines \| Transmission And Gulf Of Mexico [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Business	$ 129

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Operating Costs and Expenses	$ 1,984	$ 1,817	$ 1,548
Accounts payable	1,379	2,327
Revenues	10,907	10,965	10,627
Investee
Related Party Transaction [Line Items]
Operating Costs and Expenses	776	1,346	948
Other Operating Income	5	76	46
Accounts Receivable, after Allowance for Credit Loss, Current	2	17
Accounts payable	33	87
OperatingFeesAndCostsBilledToThirdParty	64	65	$ 70
Director
Related Party Transaction [Line Items]
Revenues	90	180
Cost of Revenue	$ 25	$ 86

Revenue by Category (Details)

Revenue by Category (Details) - USD ($) $ in Millions		12 Months Ended
Revenue by Category (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022		Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ 11,996	$ 17,773		$ 12,784
Revenue Not from Contract with Customer	[1]	4,537	7,935		2,644
Revenue Not from Contract with Customer, Other	[2]	(5,626)	(14,743)		(4,801)
Total revenues		10,907	10,965		10,627
Operating Expense
Disaggregation of Revenue [Line Items]
Recovery of Direct Costs			186		171
Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,274	3,067		2,955
Regulated Service [Member] \| Regulated Interstate Transportation & Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,334
NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,533	3,258	[3]	2,877	[3]
NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		146	260		238
Total revenues		146	260		238
Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		115	122	[3]	93	[3]
Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		7,068	6,707		6,163
Total revenues		7,026	6,536		6,001
Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,928	11,066		6,621
Total revenues		2,779	4,556		4,536
Regulated Interstate Transportation & Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,493	3,328		3,086
Revenue Not from Contract with Customer	[1]	38	28		13
Revenue Not from Contract with Customer, Other	[2]	0	0		0
Total revenues		3,531	3,356		3,099
Regulated Interstate Transportation & Storage \| Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax			3,139		2,988
Regulated Interstate Transportation & Storage \| NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	[3]	0	[3]
Regulated Interstate Transportation & Storage \| NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0		0
Regulated Interstate Transportation & Storage \| Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		19	10	[3]	10	[3]
Regulated Interstate Transportation & Storage \| Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,353	3,149		2,998
Regulated Interstate Transportation & Storage \| Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		140	179		88
Gulf of Mexico Midstream and Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		612	707		687
Revenue Not from Contract with Customer	[1]	15	10		8
Revenue Not from Contract with Customer, Other	[2]	0	0		0
Total revenues		627	717		695
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		443	381	[3]	358	[3]
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		38	64		52
Gulf of Mexico Midstream and Storage [Member] \| Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		11	11	[3]	8	[3]
Gulf of Mexico Midstream and Storage [Member] \| Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		492	456		418
Gulf of Mexico Midstream and Storage [Member] \| Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		120	251		269
Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,006	1,776		1,609
Revenue Not from Contract with Customer	[1]	27	26		25
Revenue Not from Contract with Customer, Other	[2]	0	0		0
Total revenues		2,033	1,802		1,634
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		1,782	1,526	[3]	1,425	[3]
Northeast Midstream [Member] \| NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		5	14		7
Northeast Midstream [Member] \| Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		87	102	[3]	78	[3]
Northeast Midstream [Member] \| Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,874	1,642		1,510
Northeast Midstream [Member] \| Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		132	134		99
West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,034	2,553		2,058
Revenue Not from Contract with Customer	[1]	101	8		(32)
Revenue Not from Contract with Customer, Other	[2]	0	0		0
Total revenues		2,135	2,561		2,026
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		1,478	1,518	[3]	1,227	[3]
West Midstream [Member] \| NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		103	182		179
West Midstream [Member] \| Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		12	12	[3]	9	[3]
West Midstream [Member] \| Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,593	1,712		1,415
West Midstream [Member] \| Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		441	841		643
Gas & NGL Marketing Services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,616	10,771		6,407
Revenue Not from Contract with Customer	[1]	4,294	7,929		2,632
Revenue Not from Contract with Customer, Other	[2]	(6,032)	(15,467)		(4,828)
Total revenues		2,878	3,233		4,211
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	[3]	0	[3]
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		1	3	[3]	3	[3]
Gas & NGL Marketing Services \| Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1	3		3
Gas & NGL Marketing Services \| Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,615	10,768		6,404
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		442	706		334
Revenue Not from Contract with Customer	[1]	64	(55)		11
Revenue Not from Contract with Customer, Other	[2]	0	0		0
Total revenues		506	651		345
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	[3]	0	[3]
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	0	[3]	1	[3]
Other [Member] \| Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0		1
Other [Member] \| Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		442	706		333
Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(1,207)	(2,068)		(1,397)
Revenue Not from Contract with Customer	[1]	(2)	(11)		(13)
Revenue Not from Contract with Customer, Other	[2]	406	724		27
Total revenues		(803)	(1,355)		(1,383)
Intersegment Eliminations [Member] \| Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(60)	(72)		(33)
Intersegment Eliminations [Member] \| NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(170)	(167)	[3]	(133)	[3]
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		(15)	(16)	[3]	(16)	[3]
Intersegment Eliminations [Member] \| Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(245)	(255)		(182)
Intersegment Eliminations [Member] \| Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ (962)	$ (1,813)		$ (1,215)

[1] Revenues not derived from contracts with customers primarily consist of physical product sales related to commodity derivative contracts, realized and unrealized gains and losses associated with our commodity derivative contracts, which are reported in Net gain (loss) from commodity derivatives in our 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. 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 our Consolidated Statement of Income. Certain contractual reimbursements of operating and maintenance costs totaling $186 million and $171 million for 2022 and 2021, respectively, previously included in Other are now presented in Monetary consideration to conform to the current presentation.

Revenue Recognition Contract As

Revenue Recognition Contract Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Contract With Customer, Asset [Line Items]
Contract with Customer, Asset, Net - Beginning of Period	$ 29	$ 22
Contract with Customer, Asset, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	183	208
Contract with Customer, Asset, Reclassified to Receivable	(176)	(201)
Contract with Customer, Asset, Net - End of Period	$ 36	$ 29

Revenue Recognition Contract Li

Revenue Recognition Contract Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Contract With Customer, Liability [Line Items]
Contract with Customer, Liability - Beginning of Period	$ 1,043	$ 1,126
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	190	180
Other Significant Noncash Transaction, Value of Consideration Received	9	9
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination	115	2
Contract with Customer, Liability, Revenue Recognized	(276)	(274)
Contract with Customer, Liability - End of Period	$ 1,081	$ 1,043

Revenue Recognition Contract _2

Revenue Recognition Contract Liabilities Performance Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	$ 1,081	$ 1,043	$ 1,126
Revenue, Remaining Performance Obligation, Amount	29,124
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	165
Revenue, Remaining Performance Obligation, Amount	3,828
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	145
Revenue, Remaining Performance Obligation, Amount	3,467
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	139
Revenue, Remaining Performance Obligation, Amount	3,289
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	131
Revenue, Remaining Performance Obligation, Amount	2,627
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	112
Revenue, Remaining Performance Obligation, Amount	2,365
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	389
Revenue, Remaining Performance Obligation, Amount	$ 13,548
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	1 year
Performance Obligations Related To Contract Liabilities [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
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, 2023 USD ($)
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 29,124
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,828
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,467
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,289
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	2,627
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	2,365
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 13,548
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	1 year
Remaining Performance Obligations [Member] \| Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Current :
Federal	$ 3	$ (25)	$ (1)
State	21	19	3
Total	24	(6)	2
Deferred:
Federal	872	424	421
State	109	7	88
Total	981	431	509
Less: Provision (benefit) for income taxes	$ 1,005	$ 425	$ 511

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Effective Income Tax Rate Reconciliation [Abstract]
Provision (benefit) at statutory rate	$ 925	$ 534	$ 435
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	129	113	71
State deferred income tax rate change	(25)	(92)	0
Federal valuation allowance	0	(70)	3
Federal settlements	0	(45)	0
Impact of nontaxable noncontrolling interests	(26)	(14)	(9)
Other – net	2	(1)	11
Less: Provision (benefit) for income taxes	$ 1,005	$ 425	$ 511

Provision (Benefit) for Incom_5

Provision (Benefit) for Income Taxes Deferred Tax Table (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Jun. 30, 2022
Gross deferred income tax liabilities:
Property, plant and equipment	$ 3,541	$ 3,171
Investments	1,740	1,784
Other	146	138
Total gross deferred income tax liabilities	5,427	5,093
Gross deferred income tax assets:
Accrued liabilities	935	1,108
Foreign tax credits	35	91	$ 70
Federal loss carryovers	398	730
State losses and credits	293	356
Other	103	121
Total gross deferred income tax assets	1,764	2,406
Less valuation allowance	183	200
Net deferred income tax assets	1,581	2,206
Deferred income tax liabilities	$ 3,846	$ 2,887

Provision (Benefit) for Incom_6

Provision (Benefit) for Income Taxes Textuals (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jun. 30, 2022
Income Tax Contingency [Line Items]
State deferred income tax rate change	$ (25)	$ (92)	$ 0
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	35	91		$ 70
Income Taxes Paid	31	13
Proceeds from Income Tax Refunds			$ 45
Total interest and penalties accrued as uncertain tax positions	0	0
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Income Taxes Paid	$ 5
Proceeds from Income Tax Refunds		7
Tax Adjustments, Settlements, and Unusual Provisions		$ 45

EBPs Funded Status (Details)

EBPs Funded Status (Details) - USD ($) $ in Millions		12 Months Ended
EBPs Funded Status (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
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		$ 60	$ 53	$ 45
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year		940	1,133
Service cost		23	28	30
Interest cost		46	31	28
Plan participants’ contributions		0	0
Benefits paid		(71)	(78)
Net actuarial loss (gain) (1)	[1]	68	(162)
Settlements		0	(12)
Net increase (decrease) in benefit obligation		66	(193)
Benefit obligation at end of year		1,006	940	1,133
Other Postretirement Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year		152	200
Service cost		1	1	1
Interest cost		7	6	5
Plan participants’ contributions		2	2
Benefits paid		(13)	(12)
Net actuarial loss (gain) (1)	[1]	(4)	(45)
Settlements		0	0
Net increase (decrease) in benefit obligation		(7)	(48)
Benefit obligation at end of year		$ 145	$ 152	$ 200

[1]2023 amounts are due primarily to changes in the following factors: Pension Benefits - interest crediting rate assumption and discount rate assumptions. 2022 amounts are due primarily to changes in the following factors: Pension Benefits - discount rate assumptions, partially offset by interest crediting rate assumption; Other Postretirement Benefits - discount rate assumption.

EBP Asset rollforward and B.S.

EBP Asset rollforward and B.S. classification (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Net regulatory liabilities	$ 123	$ 130
Pension Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	1,117	1,336
Actual return on plan assets	120	(132)
Employer contributions	1	3
Plan participants’ contributions	0	0
Benefits paid	(71)	(78)
Settlements	0	(12)
Net increase (decrease) in fair value of plan assets	50	(219)
Fair value of plan assets at end of year	1,167	1,117
Funded status — overfunded (underfunded)	161	177
Amounts recognized in the Consolidated Balance Sheet:
Noncurrent assets	187	201
Current liabilities	(4)	(2)
Noncurrent liabilities	(22)	(22)
Funded status - overfunded (underfunded)	161	177
Accumulated benefit obligation	998	930
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	26	24
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	24	22
Fair value of plan assets	0	0
Amounts recognized in Accumulated other comprehensive income (loss):
Net actuarial gain (loss)	(45)	(45)
Other Postretirement Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	253	287
Actual return on plan assets	17	(27)
Employer contributions	3	3
Plan participants’ contributions	2	2
Benefits paid	(13)	(12)
Settlements	0	0
Net increase (decrease) in fair value of plan assets	9	(34)
Fair value of plan assets at end of year	262	253
Funded status — overfunded (underfunded)	117	101
Amounts recognized in the Consolidated Balance Sheet:
Noncurrent assets	120	105
Current liabilities	(3)	(4)
Noncurrent liabilities	0	0
Funded status - overfunded (underfunded)	117	101
Amounts recognized in Accumulated other comprehensive income (loss):
Net actuarial gain (loss)	$ 19	$ 18

EBP Net Periodic Benefit Cost &

EBP Net Periodic Benefit Cost & OCI (Details 2) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost		$ 23	$ 28	$ 30
Interest cost		46	31	28
Expected return on plan assets		(57)	(44)	(43)
Amortization of net actuarial loss (gain)		5	12	14
Net actuarial loss from settlements		0	3	1
Reclassification to regulatory liability		0	0	0
Net periodic benefit cost (credit) (1)	[1]	17	30	30
Items Recognized in Other Comprehensive Income (Loss)
Net actuarial gain (loss) arising during the year		(5)	(14)	40
Amortization of net actuarial loss (gain)		5	12	14
Net actuarial loss from settlements		0	3	1
Total recognized in Other comprehensive income (loss)		0	1	55
Other Postretirement Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost		1	1	1
Interest cost		7	6	5
Expected return on plan assets		(10)	(10)	(10)
Amortization of net actuarial loss (gain)		(3)	0	0
Net actuarial loss from settlements		0	0	0
Reclassification to regulatory liability		0	1	2
Net periodic benefit cost (credit) (1)	[1]	(5)	(2)	(2)
Items Recognized in Other Comprehensive Income (Loss)
Net actuarial gain (loss) arising during the year		3	14	29
Amortization of net actuarial loss (gain)		(2)	0	0
Net actuarial loss from settlements		0	0	0
Total recognized in Other comprehensive income (loss)		$ 1	$ 14	$ 29

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

EBP Key Assumptions (Details 3)

EBP Key Assumptions (Details 3)	12 Months Ended
EBP Key Assumptions (Details 3)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	4.98%	5.16%	2.82%
Rate of compensation increase	3.52%	3.58%	3.67%
Cash balance interest crediting rate	4.50%	3.50%	3%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	5.16%	2.84%	2.45%
Expected long-term rate of return on plan assets	5.17%	3.81%	3.69%
Rate of compensation increase	3.58%	3.67%	3.76%
Cash balance interest crediting rate	3.50%	3%	3%
Other Postretirement Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	5.01%	5.20%	2.93%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	5.20%	2.93%	2.59%
Expected long-term rate of return on plan assets	4.04%	3.67%	3.61%
Health care cost trend rate assumed for next fiscal year	7%
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	2034

EBP Plan Assets (Details 4)

EBP Plan Assets (Details 4) - USD ($) $ in Millions		12 Months Ended
EBP Plan Assets (Details 4) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
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		$ 1,167	$ 1,117	$ 1,336
Pension Benefits [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	80	104
Pension Benefits [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	333	306
Pension Benefits [Member] \| Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		$ 413	410
Pension Benefits [Member] \| Equity securities
Defined Benefit Plan Disclosure [Line Items]
Plan asset target allocation		25%
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]	$ 17	45
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		17	45
Pension Benefits [Member] \| Government debt securities \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	61	58
Pension Benefits [Member] \| Government debt securities \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	17	18
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		78	76
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]	311	284
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		311	284
Pension Benefits [Member] \| Other \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	2	1
Pension Benefits [Member] \| Other \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	5	4
Pension Benefits [Member] \| Other \| Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		7	5
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]	287	273
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]	467	434
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		262	253	$ 287
Other Postretirement Benefits [Member] \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	109	113
Other Postretirement Benefits [Member] \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	46	42
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	155
Other Postretirement Benefits [Member] \| Cash management funds \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	99	105
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		99	105
Other Postretirement Benefits [Member] \| Government debt securities \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	9	8
Other Postretirement Benefits [Member] \| Government debt securities \| Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	2	3
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	11
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]	44	39
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		44	39
Other Postretirement Benefits [Member] \| Other \| Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	1	0
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		1	0
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]	41	38
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]	$ 66	$ 60

[1]Level 1 includes assets with fair values based on quoted prices in active markets for identical assets. Cash management funds and U.S. Treasury securities are included in this level.[2]Level 2 includes assets with fair values determined by using significant other observable inputs. This level includes 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, 2023 USD ($)
Pension Benefits [Member]
Expected benefit payments
2024	$ 95
2025	96
2026	90
2027	87
2028	84
2029-2033	397
Expected total plans contribution, approximate	2
Other Postretirement Benefits [Member]
Expected benefit payments
2024	12
2025	12
2026	11
2027	11
2028	11
2029-2033	49
Expected total plans contribution, approximate	$ 3

Investing Activities (Details)

Investing Activities (Details) - USD ($) $ in Millions			12 Months Ended
Investing Activities (Details) - USD ($) $ in Millions		Nov. 30, 2023	Dec. 31, 2023		Dec. 31, 2022	Dec. 31, 2021
Schedule of Investments [Line Items]
Equity-method investments			$ 4,614		$ 5,048
Other Investments and Securities, at Cost			23		17
Equity-method investment, payments to purchase or contributions			141		166	$ 115
Investments			4,637		5,065
Equity-method investment, difference between carrying amount and underlying equity			773		1,100
Investment Income, Interest			79		15	7
Investment Income Nonoperating Other			(1)		1	0
Other investing income (loss) - net			108		16	7
Distributions from equity-method investees (Note 8)			796		865	757
Current assets			4,513		3,797
Current liabilities			(5,830)		(4,890)
Revenues			10,907		10,965	10,627
Operating income			966		1,268	1,191
Net income			3,303		2,117	1,562
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Schedule of Investments [Line Items]
Current assets			669		964
Noncurrent assets			11,058		12,701
Current liabilities			(358)		(632)
Noncurrent liabilities			(3,619)		(3,789)
Revenues			3,714		5,520	4,688
Net income			$ 748		1,102	1,006
Appalachia Midstream Investments [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage			66%
Equity-method investments	[1]		$ 2,886		2,975
Equity-method investment, payments to purchase or contributions			59		83	84
Equity-method investment, difference between carrying amount and underlying equity			1,100		1,100
Distributions from equity-method investees (Note 8)			$ 405		415	433
Blue Racer Midstream LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage			50%
Equity-method investments			$ 398		383
Distributions from equity-method investees (Note 8)			$ 62		49	47
Overland Pass Pipeline Company LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage			50%
Equity-method investments			$ 387		386
Distributions from equity-method investees (Note 8)			$ 56		34	26
Discovery Producer Services LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage			60%
Equity-method investments			$ 361		345
Equity-method investment, payments to purchase or contributions			40		41	0
Distributions from equity-method investees (Note 8)			$ 49		49	44
Gulfstream Natural Gas System, LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage			50%
Equity-method investments			$ 210		220
Equity-method investment, payments to purchase or contributions			0		14	26
Distributions from equity-method investees (Note 8)			$ 98		89	90
Laurel Mountain Midstream, LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage			69%
Equity-method investments			$ 184		205
Distributions from equity-method investees (Note 8)			$ 42		112	33
Rocky Mountain Midstream Holdings LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage			100%
Equity-method investments			$ 0	[2]	395
Distributions from equity-method investees (Note 8)			49		52	45
Other [Member]
Schedule of Investments [Line Items]
Equity-method investments			188		139
Equity-method investment, payments to purchase or contributions			4		12	5
Distributions from equity-method investees (Note 8)			35		65	39
Aux Sable Liquid Products LP [Member]
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions			38		0	0
Cardinal Pipeline Company, LLC
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions			0		16	0
RMM Acquisition
Schedule of Investments [Line Items]
Gain on remeasurement of equity-method investment (Note 2)		$ 30	$ 30		$ 0	$ 0

[1]Includes equity-method investments in multiple gathering systems in the Marcellus Shale region with an approximate average 66 percent interest.[2] RMM is a wholly owned subsidiary as of November 30, 2023. See Note 3 – Acquisitions and Divestitures.

Property, Plant, and Equipmen_2

Property, Plant, and Equipment (Details PPE) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 51,842	$ 47,057
Accumulated depreciation and amortization		(17,531)	(16,168)
Property, plant, and equipment - net		34,311	30,889
Depreciation and amortization expenses		1,660	1,498	$ 1,496
Interest Costs Capitalized		54	20	$ 11
Nonregulated [Member] \| Natural gas gathering and processing facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		21,357	19,163
Nonregulated [Member] \| Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		1,138	997
Nonregulated [Member] \| Oil and Gas Properties
Property, Plant, and Equipment
Property, plant, and equipment, at cost		1,111	874
Nonregulated [Member] \| Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		3,268	2,998
Regulated [Member] \| Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		1,124	708
Regulated [Member] \| Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		2,761	2,796
Regulated [Member] \| Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		21,083	19,521
Regulated [Member] \| Acquisition Adjustment Of Regulated Facilities [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Plant Acquisition Adjustments for Intangible Utility Plants		$ 389	$ 428
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] \| 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%
Minimum [Member] \| Regulated [Member] \| Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, Plant, and Equipment, Depreciation Rate	[1]	1.25%
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] \| 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%
Maximum [Member] \| Regulated [Member] \| Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, Plant, and Equipment, Depreciation Rate	[1]	8.33%

[1]Estimated useful life and depreciation rates are presented as of December 31, 2023. 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, 2023	Dec. 31, 2022
Asset Retirement Obligations
Asset Retirement Obligations, Noncurrent		$ 1,978	$ 1,827
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year		1,914	1,665
Liabilities incurred		42	77
Liabilities settled		(43)	(22)
Accretion		97	85
Revisions (1)	[1]	74	109
Balance at end of year		2,084	$ 1,914
Asset Retirement Obligation Costs [Member]
Unusual or Infrequent Item [Line Items]
Transco's annual funding commitment for ARO		$ 16

[1]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 2023 and 2022 revisions reflect changes in removal cost estimates and increases in inflation rates, partially offset by increases in discount rates.

Goodwill and Other Intangible_3

Goodwill and Other Intangible Assets (Details) - USD ($) $ in Millions		12 Months Ended
	Nov. 30, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Feb. 14, 2023
Finite-Lived Intangible Assets [Line Items]
Goodwill		$ 463	$ 0	$ 0
Finite-Lived Intangible Assets, Gross		10,510	10,338
Finite-Lived Intangible Assets, Accumulated Amortization		(3,380)	(2,975)
Customer relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross		10,237	10,065
Finite-Lived Intangible Assets, Accumulated Amortization		$ (3,155)	(2,801)
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life		30 years
Amortization of Intangible Assets		$ 360	353	332
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months		368
Finite-Lived Intangible Assets, Amortization Expense, Year Two		368
Finite-Lived Intangible Assets, Amortization Expense, Year Three		364
Finite-Lived Intangible Assets, Amortization Expense, Year Four		360
Finite-Lived Intangible Assets, Amortization Expense, Year Five		360
Transportation and Storage Capacity [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross		267	267
Finite-Lived Intangible Assets, Accumulated Amortization		(223)	(172)
Amortization of Intangible Assets		51	158	14
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months		21
Finite-Lived Intangible Assets, Amortization Expense, Year Two		10
Finite-Lived Intangible Assets, Amortization Expense, Year Three		7
Finite-Lived Intangible Assets, Amortization Expense, Year Four		4
Finite-Lived Intangible Assets, Amortization Expense, Year Five		2
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)
MountainWestAcquisition
Finite-Lived Intangible Assets [Line Items]
Goodwill					$ 400
Goodwill, Period Increase (Decrease)		400
Cureton Acquisition
Finite-Lived Intangible Assets [Line Items]
Goodwill	$ 6
Goodwill, Period Increase (Decrease)		6
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	20 years
RMM Acquisition
Finite-Lived Intangible Assets [Line Items]
Goodwill	$ 57
Goodwill, Period Increase (Decrease)		57
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	20 years
Transmission And Gulf Of Mexico [Member]
Finite-Lived Intangible Assets [Line Items]
Goodwill		400	0	0
Transmission And Gulf Of Mexico [Member] \| MountainWestAcquisition
Finite-Lived Intangible Assets [Line Items]
Goodwill, Period Increase (Decrease)		400
West [Member]
Finite-Lived Intangible Assets [Line Items]
Goodwill		63	$ 0	$ 0
West [Member] \| Cureton Acquisition
Finite-Lived Intangible Assets [Line Items]
Goodwill, Period Increase (Decrease)		6
West [Member] \| RMM Acquisition
Finite-Lived Intangible Assets [Line Items]
Goodwill, Period Increase (Decrease)		$ 57

Accrued and Other Current Lia_3

Accrued and Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Accrued Liabilities [Line Items]
Interest on debt	$ 322	$ 274
Employee costs	197	218
Contract liabilities	159	141
Alaska refinery contamination litigation (Note 17)	134	21
Asset retirement obligations (Note 9)	106	87
Regulatory liabilities (Note 1)	77	201
Operating lease liabilities (Note 13)	24	25
Other, including accrued loss contingencies	265	303
Other accrued liabilities	$ 1,284	$ 1,270

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022	Nov. 15, 2023	Aug. 10, 2023		Mar. 02, 2023	Aug. 08, 2022	Oct. 08, 2021		Mar. 02, 2021
Long-term Debt
Unamortized debt issuance costs		$ (140)	$ (135)
Net unamortized debt premium (discount)		(114)	(55)
Total long-term debt, including current portion		25,713	22,554
Long-term debt due within one year		(2,337)	(627)
Long-term debt		23,376	21,927
RMM Acquisition
Long-term Debt
Business Combination, Consideration Transferred, Liabilities Incurred		665	0
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%
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%
Transcontinental Gas Pipe Line Company, LLC [Member] \| Atlantic Sunrise [Member]
Long-term Debt
Other financing obligations		$ 790	809
Long-term debt interest rate		9%
Transcontinental Gas Pipe Line Company, LLC [Member] \| Leidy South
Long-term Debt
Other financing obligations		$ 76	77
Long-term debt interest rate		13%
Transcontinental Gas Pipe Line Company, LLC [Member] \| Dalton [Member]
Long-term Debt
Other financing obligations		$ 250	252
Long-term debt interest rate		9%
MountainWest [Member] \| 3.53 Percent Senior Unsecured Notes due 2028
Long-term Debt
Long-term debt		$ 100	0
Long-term debt interest rate		3.53%
MountainWest [Member] \| 3.91 Percent Senior Unsecured Notes due 2038
Long-term Debt
Long-term debt		$ 150	0
Long-term debt interest rate		3.91%
MountainWest [Member] \| 4.875 Percent Senior Unsecured Notes due 2041
Long-term Debt
Long-term debt		$ 180	0
Long-term debt interest rate		4.875%
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	[1]	$ 0
The Williams Companies, Inc. [Member] \| 4.5% Senior Unsecured Notes Due 2023 [Member]
Long-term Debt
Long-term debt		$ 0	600
Long-term debt interest rate		4.50%		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] \| 5.40 Percent Senior Unsecured Notes Due 2026
Long-term Debt
Long-term debt		$ 1,100	0
Long-term debt interest rate		5.40%			5.40%	[2]	5.40%
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] \| 5.30 Percent Senior Unsecured Notes Due 2028
Long-term Debt
Long-term debt		$ 900	0
Long-term debt interest rate		5.30%			5.30%
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%
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%	[3]	2.60%
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] \| 4.65 Percent Senior Unsecured Notes Due 2032
Long-term Debt
Long-term debt		$ 1,000	1,000
Long-term debt interest rate		4.65%						4.65%
The Williams Companies, Inc. [Member] \| 5.65 Percent Senior Unsecured Notes Due 2033
Long-term Debt
Long-term debt		$ 750	0
Long-term debt interest rate		5.65%					5.65%
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] \| 5.3 Percent Senior Unsecured Notes Due 2052
Long-term Debt
Long-term debt		$ 750	750
Long-term debt interest rate		5.30%						5.30%
The Williams Companies, Inc. [Member] \| 7.7% Notes due 2027
Long-term Debt
Long-term debt		$ 2	$ 2
Long-term debt interest rate		7.70%

[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.[2]Additional issuance of the 5.40 percent senior notes due 2026 issued on March 2, 2023, and trade interchangeably with such notes.[3]Additional issuance of the 2.6 percent senior notes due 2031 issued on March 2, 2021, and trade interchangeably with such notes.

Long-Term Debt Maturities (Deta

Long-Term Debt Maturities (Details) $ in Millions	Dec. 31, 2023 USD ($)
Aggregate minimum maturities of long-term debt
2024	$ 2,338
2025	2,263
2026	2,345
2027	1,993
2028	$ 1,445

Long-Term Debt Issuances and Re

Long-Term Debt Issuances and Retirements (Details) - USD ($) $ in Millions

Nov. 15, 2023

Oct. 17, 2022

May 16, 2022

Jan. 18, 2022

Sep. 01, 2021

Aug. 16, 2021

Jan. 05, 2024

Dec. 31, 2023

Aug. 10, 2023

Mar. 02, 2023

Aug. 08, 2022

Oct. 08, 2021

Mar. 02, 2021

The Williams Companies, Inc. [Member] | 4.9 Percent Senior Unsecured Notes Due 2029 | Subsequent Event [Member]

Debt Instrument [Line Items]

Long-term debt face amount

$ 1,100

Long-term debt interest rate

4.90%

The Williams Companies, Inc. [Member] | 5.15 Percent Senior Unsecured Notes Due 2034 | Subsequent Event [Member]

Debt Instrument [Line Items]

Long-term debt face amount

$ 1,000

Long-term debt interest rate

5.15%

The Williams Companies, Inc. [Member] | 5.40 Percent Senior Unsecured Notes Due 2026

Debt Instrument [Line Items]

Long-term debt face amount

$ 350

[1]

$ 750

Long-term debt interest rate

5.40%

[1]

5.40%

The Williams Companies, Inc. [Member] | 5.30 Percent Senior Unsecured Notes Due 2028

Debt Instrument [Line Items]

Long-term debt face amount

$ 900

Long-term debt interest rate

5.30%

The Williams Companies, Inc. [Member] | 5.65 Percent Senior Unsecured Notes Due 2033

Debt Instrument [Line Items]

Long-term debt face amount

$ 750

Long-term debt interest rate

5.65%

The Williams Companies, Inc. [Member] | 4.65 Percent Senior Unsecured Notes Due 2032

Debt Instrument [Line Items]

Long-term debt face amount

$ 1,000

Long-term debt interest rate

4.65%

The Williams Companies, Inc. [Member] | 5.3 Percent Senior Unsecured Notes Due 2052

Debt Instrument [Line Items]

Long-term debt face amount

$ 750

Long-term debt interest rate

5.30%

The Williams Companies, Inc. [Member] | 2.6 Percent Senior Unsecured Notes Due 2031

Debt Instrument [Line Items]

Long-term debt face amount

$ 600

[2]

$ 900

Long-term debt interest rate

2.60%

[2]

2.60%

The Williams Companies, Inc. [Member] | 3.5 Percent Senior Unsecured Notes Due 2051

Debt Instrument [Line Items]

Long-term debt face amount

$ 650

Long-term debt interest rate

3.50%

The Williams Companies, Inc. [Member] | 4.5% Senior Unsecured Notes Due 2023 [Member]

Debt Instrument [Line Items]

Long-term debt interest rate

4.50%