Kinder Morgan (KMI) 10-K20 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
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Period End Date	Dec. 31, 2023
Document Transition Report	false
Entity File Number	001-35081
Entity Registrant Name	Kinder Morgan, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	80-0682103
Entity Address, Address Line One	1001 Louisiana Street
Entity Address, Address Line Two	Suite 1000
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	369-9000
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
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 33,533,173,723
Entity Common Stock, Shares Outstanding		2,219,369,970
Entity Central Index Key	0001506307
Document Fiscal Period Focus	FY
Amendment Flag	false
Class P
Entity Information [Line Items]
Title of 12(b) Security	Class P Common Stock
Trading Symbol	KMI
Security Exchange Name	NYSE
2.250% Senior Notes due March 2027
Entity Information [Line Items]
Title of 12(b) Security	2.250% Senior Notes due 2027
Trading Symbol	KMI 27 A
Security Exchange Name	NYSE

Audit Information

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2023
Auditor [Abstract]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Houston, Texas
Auditor Firm ID	238

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues
Revenues	$ 15,334	$ 19,200	$ 16,610
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)	4,938	9,255	6,493
Operations and maintenance	2,807	2,655	2,368
Depreciation, depletion and amortization	2,250	2,186	2,135
General and administrative	668	637	655
Taxes, other than income taxes	421	441	426
(Gain) loss on divestitures and impairments, net (Note 4)	(15)	(32)	1,624
Other expense (income), net	2	(7)	(7)
Total Operating Costs, Expenses and Other	11,071	15,135	13,694
Operating Income	4,263	4,065	2,916
Other Income (Expense)
Earnings from equity investments	838	803	591
Amortization of excess cost of equity investments	(66)	(75)	(78)
Interest, net	(1,797)	(1,513)	(1,492)
Other, net (Note 3)	(37)	55	282
Total Other Expense	(1,062)	(730)	(697)
Income Before Income Taxes	3,201	3,335	2,219
Income Tax Expense	(715)	(710)	(369)
Net Income	2,486	2,625	1,850
Net Income Attributable to Noncontrolling Interests	(95)	(77)	(66)
Net Income Attributable to Kinder Morgan, Inc.	$ 2,391	$ 2,548	$ 1,784
Class P Common Stock
Basic Earnings Per Share	$ 1.06	$ 1.12	$ 0.78
Diluted Earnings Per Share	$ 1.06	$ 1.12	$ 0.78
Basic Weighted Average Shares Outstanding	2,234	2,258	2,266
Diluted Weighted Average Shares Outstanding	2,234	2,258	2,266
Services
Revenues
Revenues	$ 8,371	$ 8,145	$ 7,757
Commodity sales
Revenues
Revenues	6,786	10,897	8,714
Other
Revenues
Revenues	$ 177	$ 158	$ 139

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net income	$ 2,486	$ 2,625	$ 1,850
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) from derivative instruments (net of taxes of $(47), $92, and $131, respectively)	155	(312)	(432)
Reclassification into earnings of net derivative instruments loss (gain) to net income (net of taxes of $12, $(95), and $(83), respectively)	(35)	320	273
Benefit plan adjustments (net of taxes of $(20), $(1), and $(47), respectively)	65	1	155
Total other comprehensive income (loss)	185	9	(4)
Comprehensive income	2,671	2,634	1,846
Comprehensive income attributable to noncontrolling interests	(95)	(77)	(66)
Comprehensive income attributable to KMI	$ 2,576	$ 2,557	$ 1,780

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Change in fair value of derivative instruments, tax	$ (47)	$ 92	$ 131
Reclassification of change in fair value of derivative instruments to net income, tax	12	(95)	(83)
Benefit plan adjustments, tax	$ (20)	$ (1)	$ (47)

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 83	$ 745
Restricted deposits	13	49
Accounts receivable	1,588	1,840
Fair value of derivative contracts	126	231
Inventories	525	634
Other current assets	207	304
Total current assets	2,542	3,803
Property, plant and equipment, net	37,297	35,599
Investments	7,874	7,653
Goodwill	20,121	19,965
Other intangibles, net	1,957	1,809
Deferred charges and other assets	1,229	1,249
Total Assets	71,020	70,078
Current liabilities
Current portion of debt	4,049	3,385
Accounts payable	1,366	1,444
Accrued interest	513	515
Accrued taxes	272	264
Fair value of derivative contracts	205	465
Other current liabilities	816	857
Total current liabilities	7,221	6,930
Long-term debt
Outstanding	27,880	28,288
Debt fair value adjustments	187	115
Total long-term debt	28,067	28,403
Deferred income taxes	1,388	623
Other long-term liabilities and deferred credits	2,615	2,008
Total long-term liabilities and deferred credits	32,070	31,034
Total Liabilities	39,291	37,964
Commitments and contingencies (Notes 9, 13, 17 and 18)
Stockholders’ Equity
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,219,729,644 and 2,247,681,626 shares, respectively, issued and outstanding	22	22
Additional paid-in capital	41,190	41,673
Accumulated deficit	(10,689)	(10,551)
Accumulated other comprehensive loss	(217)	(402)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,306	30,742
Noncontrolling interests	1,423	1,372
Total Stockholders’ Equity	31,729	32,114
Total Liabilities and Stockholders’ Equity	$ 71,020	$ 70,078

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Stockholders’ Equity
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	4,000,000,000	4,000,000,000
Common stock, shares issued (in shares)	2,219,729,644	2,247,681,626
Common stock, shares outstanding (in shares)	2,219,729,644	2,247,681,626

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash Flows From Operating Activities
Net income	$ 2,486	$ 2,625	$ 1,850
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	2,250	2,186	2,135
Deferred income taxes	710	692	355
Amortization of excess cost of equity investments	66	75	78
Change in fair market value of derivative contracts	(126)	56	20
(Gain) loss on divestitures and impairments, net (Note 4)	(15)	(32)	1,624
Gain on sale of interest in equity investment (Note 3)	0	0	(206)
Earnings from equity investments	(838)	(803)	(591)
Distributions of equity investment earnings	755	725	720
Pension contributions net of noncash pension benefit expenses	77	(50)	(39)
Changes in components of working capital, net of the effects of acquisitions and dispositions
Accounts receivable	301	(220)	(265)
Inventories	188	(183)	(202)
Other current assets	108	(51)	(109)
Accounts payable	(201)	161	387
Accrued interest, net of interest rate swaps	(13)	50	(17)
Other current liabilities	(58)	6	165
Change in deferred revenues (Note 15)	870	(24)	(28)
Rate reparations, refunds and other litigation reserve adjustments	(19)	(190)	(57)
Other, net	(50)	(56)	(112)
Net Cash Provided by Operating Activities	6,491	4,967	5,708
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired (Note 3)	(1,842)	(487)	(1,547)
Capital expenditures	(2,317)	(1,621)	(1,281)
Sales of property, plant and equipment, investments, and other net assets, net of removal costs	(28)	6	406
Contributions to investments	(212)	(229)	(38)
Distributions from equity investments in excess of cumulative earnings	228	156	163
Other, net	(4)	0	(8)
Net Cash Used in Investing Activities	(4,175)	(2,175)	(2,305)
Cash Flows From Financing Activities
Issuances of debt	7,590	9,058	5,959
Payments of debt	(7,356)	(9,735)	(6,831)
Debt issue costs	(20)	(25)	(27)
Dividends (Note 11)	(2,529)	(2,504)	(2,443)
Repurchases of shares (Note 11)	(522)	(368)	0
Proceeds from sale of noncontrolling interests (Note 3)	0	557	0
Contributions from noncontrolling interests	3	2	4
Distributions to investment partner	0	0	(82)
Distributions to noncontrolling interests	(151)	(116)	(20)
Other, net	(29)	(14)	(25)
Net Cash Used in Financing Activities	(3,014)	(3,145)	(3,465)
Net Decrease in Cash, Cash Equivalents and Restricted Deposits	(698)	(353)	(62)
Cash, Cash Equivalents and Restricted Deposits, beginning of period	794	1,147	1,209
Cash, Cash Equivalents and Restricted Deposits, end of period	96	794	1,147
Cash and Cash Equivalents, beginning of period	745	1,140	1,184
Restricted Deposits, beginning of period	49	7	25
Cash and Cash Equivalents, end of period	83	745	1,140
Restricted Deposits, end of period	13	49	7
Noncash Investing and Financing Activities
Assets contributed to equity investment	16	0	0
Net increase in property, plant and equipment from both accruals and contractor retainage	120	72	74
ROU assets and operating lease obligations recognized (Note 17)	56	22	59
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,844	1,460	1,529
Cash paid during the period for income taxes, net	$ 11	$ 13	$ 10

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Millions, $ in Millions	Total	Impact of Adoption of ASU	Adjusted Balance	Common stock	Common stock Adjusted Balance	Additional paid-in capital	Additional paid-in capital Impact of Adoption of ASU	Additional paid-in capital Adjusted Balance	Accumulated deficit	Accumulated deficit Adjusted Balance	Accumulated other comprehensive loss	Accumulated other comprehensive loss Adjusted Balance	Stockholders’ equity attributable to KMI	Stockholders’ equity attributable to KMI Impact of Adoption of ASU	Stockholders’ equity attributable to KMI Adjusted Balance	Non-controlling interests	Non-controlling interests Adjusted Balance
Balance at Dec. 31, 2020	$ 31,838			$ 23		$ 41,756			$ (9,936)		$ (407)		$ 31,436			$ 402
Balance (shares) at Dec. 31, 2020				2,264
Repurchases of shares	0
Repurchases of shares (shares)				0
Restricted shares	50					50							50
Restricted shares (shares)				3
Net income	1,850								1,784				1,784			66
Dividends	(2,443)								(2,443)				(2,443)
Distributions	(20)												0			(20)
Contributions	4												0			4
Reclassification of redeemable noncontrolling interest	646												0			646
Other comprehensive (loss) income	(4)										(4)		(4)
Balance at Dec. 31, 2021	$ 31,921	$ (11)	$ 31,910	$ 23	$ 23	41,806	$ (11)	$ 41,795	(10,595)	$ (10,595)	(411)	$ (411)	30,823	$ (11)	$ 30,812	1,098	$ 1,098
Balance (shares) at Dec. 31, 2021				2,267	2,267
Accounting Standards Update	Accounting Standards Update 2020-06
Repurchases of shares	$ (368)			$ (1)		(367)							(368)
Repurchases of shares (shares)				(21)
EP Trust I Preferred security conversions	1					1							1
Restricted shares	54					54							54
Restricted shares (shares)				2
Net income	2,625								2,548				2,548			77
Dividends	(2,504)								(2,504)				(2,504)
Distributions	(116)												0			(116)
Contributions	2												0			2
Impact of change in ownership interest in subsidiary	501					190							190			311
Other comprehensive (loss) income	9										9		9
Balance at Dec. 31, 2022	32,114			$ 22		41,673			(10,551)		(402)		30,742			1,372
Balance (shares) at Dec. 31, 2022				2,248
Repurchases of shares	(522)					(522)							(522)
Repurchases of shares (shares)				(32)
Restricted shares	44					44							44
Restricted shares (shares)				4
Net income	2,486								2,391				2,391			95
Dividends	(2,529)								(2,529)				(2,529)
Distributions	(151)												0			(151)
Contributions	3												0			3
Acquisition (Note 3)	104												0			104
Other	(5)					(5)							(5)
Other comprehensive (loss) income	185										185		185
Balance at Dec. 31, 2023	$ 31,729			$ 22		$ 41,190			$ (10,689)		$ (217)		$ 30,306			$ 1,423
Balance (shares) at Dec. 31, 2023				2,220

General (Notes)

General (Notes)	12 Months Ended
General (Notes)	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	1. General We are one of the largest energy infrastructure companies in North America. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO 2 , renewable fuels and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum coke, and ethanol and other renewable fuels and feedstocks.

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
Summary of Significant Accounting Policies (Notes)	Dec. 31, 2023
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	2. Summary of Significant Accounting Policies Basis of Presentation Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation. Use of Estimates Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including those related to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements. Cash Equivalents and Restricted Deposits We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less. Amounts included in the restricted deposits in the accompanying consolidated financial statements represent a combination of restricted cash amounts required to be set aside by regulatory agencies to cover obligations for our captive insurance subsidiary, cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions and escrow deposits. Allowance for Credit Losses We evaluate our financial assets measured at amortized cost and off-balance sheet credit exposures for expected credit losses over the contractual term of the asset or exposure. We consider available information relevant to assessing the collectability of cash flows including the expected risk of credit loss even if that risk is remote. We measure expected credit losses on a collective (pool) basis when similar risk characteristics exist, and we reflect the expected credit losses on the amortized cost basis of the financial asset as of the reporting date. Our financial instruments primarily consist of our accounts receivable from customers, notes receivable from affiliates and contingent liabilities such as proportional guarantees of debt obligations of an equity investee. We utilized historical analysis of credit losses experienced over the previous five years along with current conditions and reasonable and supportable forecasts of future conditions in our evaluation of collectability of our financial assets. Our allowance for credit losses as of both December 31, 2023 and 2022 was $1 million and is included in “Other current assets” in our accompanying consolidated balance sheets. Inventories Our inventories consist of materials and supplies and products such as natural gas, NGL, crude oil, condensate, refined petroleum products and transmix. We report products inventory at the lower of weighted-average cost or net realizable value. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence. Property, Plant and Equipment, net Capitalization, Depreciation and Depletion and Disposals We report property, plant and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in the period incurred. The following table summarizes our significant policies related to our property, plant and equipment. The application of these policies can involve significant estimates. Asset Accounting Area Policy Straight-line assets Depreciation rates • Depreciable lives are based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets. Gains and losses • A gain or loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sale proceeds received or when held for sale, the market value of the asset. • A gain on an asset disposal is recognized in income in the period that the sale is closed. • A loss is recognized when the asset is sold or when classified as held for sale. • Gains and losses are recorded in operating costs, expenses and other. Composite assets Depreciation rates • A single depreciation rate is applied to the total cost of a functional group of assets that have similar economic characteristics until the net book value of the composite group equals the salvage value. • Interstate natural gas FERC-regulated entities use the depreciation rates approved by the FERC. • A depreciation rate for other composite assets is based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets. Gains and losses • Gains and losses are credited or charged to accumulated depreciation, net of salvage and cost of removal. • Gains and losses on FERC-approved operating unit sales and land sales are recorded in operating costs, expenses and other. Oil and gas producing activities(a) Successful efforts method of accounting • Costs that are incurred to acquire leasehold and subsequent development costs are capitalized. • Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. • Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. • The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. • Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset. Enhanced recovery techniques • In some cases, the cost of the CO 2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. • The cost of CO 2 associated with pressure maintenance operations for reservoir management is expensed when it is injected. • When CO 2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. • Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. (a) Gains and losses associated with assets in our oil and gas producing activities have a similar treatment as with that associated with our straight-line assets. Circumstances may develop which cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year. Asset Retirement Obligations We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. The majority of our asset retirement obligations are associated with our CO 2 business where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors, but we also have obligations for certain gathering and long-haul pipelines and certain processing plants. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. The fair value estimates are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include estimates and assumptions related to timing of settlement and retirement costs, which we base on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted to reflect the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service. Our estimates of retirement costs could change as a result of changes in cost estimates and/or timing of the obligation. The following table summarizes changes in the asset retirement obligations included in our accompanying consolidated balance sheets: December 31, 2023 2022 (In millions) Balance at beginning of period $ 204 $ 196 Accretion expense 12 12 New obligations 22 2 Settlements (7) (6) Balance at end of period(a) $ 231 $ 204 (a) Balances at both December 31, 2023 and 2022 include For certain assets, we currently cannot reasonably estimate the fair value of the asset retirement obligations because the associated assets have indeterminate lives. These assets include certain pipelines, processing plants and distribution facilities, and liquids and bulk terminal facilities. Based on the widespread use of hydrocarbons domestically and for international export, management expects supply and demand to exist for the foreseeable future. Therefore, the remaining useful lives of these assets are indeterminate due to prolonged expected demand. Additionally, these assets could also benefit from potential future conversion opportunities. For example, certain assets could be converted to transport, handle or store products other than traditional hydrocarbons. Under our integrity program, individual asset parts are replaced regularly. Although some of the individual asset parts may be replaced, the assets themselves may remain intact indefinitely. For these assets, an asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation. Long-lived Asset Impairments We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable. In addition to our annual goodwill impairment test discussed further below, to the extent triggering events exist, we complete a review of the carrying value of our long-lived assets, including property, plant and equipment as well as other intangibles, and record, as applicable, the appropriate impairments using a two-step approach. To determine if a long-lived asset is recoverable, we compare the asset’s estimated undiscounted cash flows to its carrying value (step 1). Because the impairment test for long-lived assets held in use is based on estimated undiscounted cash flows, there may be instances where an asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset or asset group. If the carrying value of a long-lived asset or asset group is in excess of estimated undiscounted cash flows, we typically use discounted cash flow analyses to calculate the fair value of the long-lived asset to determine if an impairment is required and the amount of the impairment losses to be recognized (step 2). We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on estimated future oil and gas production volumes. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on estimated future oil and gas production volumes. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment. Refer to Note 4 for further information. Equity Method of Accounting and Basis Differences We use the equity method of accounting for investments which we do not control, but for which we have the ability to exercise significant influence. The carrying values of these investments are impacted by our share of investee income or loss, distributions, amortization or accretion of basis differences and other-than-temporary impairments. The difference between the carrying value of an investment and our share of the investment’s underlying equity in net assets is referred to as a basis difference. If the basis difference is assigned to depreciable or amortizable assets and liabilities, the basis difference is amortized or accreted as part of our share of investee earnings. To the extent that the basis difference relates to goodwill, referred to as equity method goodwill, the amount is not amortized. We evaluate our equity method investments for other-than-temporary impairment. When an other-than-temporary impairment is recognized, the loss is recorded as a reduction in equity earnings. Goodwill Goodwill is the cost of an acquisition of a business in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually and in interim periods if indicators of impairment exist. This test requires us to assign goodwill to an appropriate reporting unit and compare the fair value of a reporting unit to its carrying value. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value an impairment is measured and recorded at the amount by which the reporting unit’s carrying value exceeds its fair value. We evaluate goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. For purposes of our May 31, 2023 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO 2 ; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (vi) Terminals; and (vii) Energy Transition Ventures. Generally, the evaluation of goodwill for impairment involves a quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test. A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit. Refer to Note 8 for further information. Other Intangibles Excluding goodwill, our other intangible assets include customer contracts and other relationships and agreements. Our intangible assets primarily relate to customer contracts or other relationships for the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline, and other refined petroleum products, petroleum coke, metals and ores, the gathering of natural gas and the production and supply of RNG. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate. We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. Among the factors we weigh, depending on the nature of the asset, are the effects of obsolescence, new technology, and competition. The following tables summarize our other intangible assets as of December 31, 2023 and 2022 and our amortization expense for the years ended December 31, 2023, 2022 and 2021: Weighted Average Amortization Period December 31, 2023 2022 (Years) (In millions) Gross 11.3 $ 3,543 $ 3,382 Accumulated amortization (1,586) (1,573) Net carrying amount $ 1,957 $ 1,809 December 31, 2023 2022 2021 (In millions) Amortization expense $ 202 $ 253 $ 237 Our estimated amortization expense for our intangible assets for each of the next five fiscal years is: 2024 2025 2026 2027 2028 (In millions) Estimated amortization expenses $ 198 $ 193 $ 191 $ 191 $ 190 Revenue Recognition The majority of our revenues are accounted for under Topic 606, Revenue from Contracts with Customers ; however, to a limited extent, some revenues are accounted for under other guidance such as Topic 842, Leases or Topic 815, Derivatives and Hedging Activities . Revenue from Contracts with Customers We review our contracts with customers using the following steps to recognize revenue based on the transfer of goods or services to customers and in amounts that reflect the consideration the company expects to receive for those goods or services. The steps include: (i) identify the contract; (ii) identify the performance obligations of the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and then (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions. Our customer sales contracts primarily include sales of natural gas, NGL, crude oil, CO 2 and transmix, as described below. Generally, for the majority of these contracts (i) each unit (Bcf, gallon, barrel, etc.) of commodity is a separate performance obligation, as our promise is to sell multiple distinct units of commodity at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied. Our customer services contracts are primarily for transportation service, storage service, gathering and processing service, and terminaling, as described below. Generally, for the majority of these contracts (i) our promise is to transfer (or stand ready to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights). Firm Services Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows: • Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is satisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the beginning of each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., we expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation) continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time. • Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future period and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to deliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e., breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods. Non-Firm Services Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period). Contract Balances Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. We recognize contract assets in those instances where billing occurs subsequent to revenue recognition, and our right to invoice the customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of the contract for which we record revenue ratably per unit over the life of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognize as revenue on a straight-line basis over the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future period, which we subsequently recognize as revenue when the customer makes up the volumes or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed rates per volume that decrease over the life of the contract where we apply revenue levelization for amounts received for our future performance obligations. We reassess amounts recorded as contract assets or liabilities upon contract modification. Refer to Note 15 for further information. Costs of Sales Costs of sales primarily includes the cost to purchase energy commodities sold, including natural gas, crude oil, NGL and other refined petroleum products, adjusted for the effects of our energy commodity hedging activities, as applicable. Costs of our crude oil, gas and CO 2 producing activities, such as those in our CO 2 business segment, are not accounted for as costs of sales. Operations and Maintenance Operations and maintenance includes costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our crude oil, gas and CO 2 producing activities included within operations and maintenance totaled $393 million, $367 million and $180 million for the years ended December 31, 2023, 2022 and 2021, respectively. Environmental Matters We capitalize certain environmental expenditures required to obtain rights-of-way, regulatory approvals or permitting as part of the construction of facilities we use in our business operations. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs, such as after the completion of a feasibility study or commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities assumed in a business combination. We routinely conduct reviews of potential environmental issues and claims that assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims we may have against others. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. Leases We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one Our operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, are reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842 , such as land easements, are reassessed when the agreements are modified. Refer to Note 17 for further information. Share-based Compensation We recognize compensation expense ratably over the vesting period of the restricted stock award based on the grant-date fair value, which is determined based on the market price of our Class P common stock on the grant date, less estimated forfeitures. Forfeiture rates are estimated based on historical forfeitures under our restricted stock award plans. Upon vesting, the restricted stock award will be paid in shares of our Class P common stock. Pensions and Other Postretirement Benefits We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheets. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—net of income taxes in “Accumulated other comprehensive loss,” wi

Acquisitions and Divestitures (

Acquisitions and Divestitures (Notes)	12 Months Ended
Acquisitions and Divestitures (Notes)	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Acquisitions and Divestitures	3. Acquisitions and Divestitures Business Combinations For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of these items requires management’s judgment and the utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions. Our allocation of the purchase price for acquisitions completed during the years ended December 31, 2023, 2022 and 2021 are detailed below: Assignment of Purchase Price Ref Acquisition Purchase price Current assets Property, plant & equipment Other long-term assets Current liabilities Long-term liabilities Non-controlling interest Resulting goodwill (In millions) (1) STX Midstream(a) $ 1,831 $ 41 $ 1,199 $ 552 $ (11) $ (2) $ (104) $ 156 (2) Diamond M 13 — 25 — — (12) — — (3) North American Natural Resources 132 2 5 64 — — — 61 (4) Mas Ranger, LLC 358 9 31 320 (2) — — — (5) Kinetrex Energy 318 18 49 272 (6) (68) — 53 (6) Stagecoach 1,258 53 1,187 24 (6) — — — (a) The purchase price allocation for the STX Midstream Acquisition is preliminary. (1) STX Midstream Pipeline System (STX Midstream) Acquisition On December 28, 2023, we completed the acquisition of STX Midstream from NextEra Energy Partners for a purchase price of $1,831 million, including preliminary purchase price adjustments for working capital. Other long-term assets includes $357 million related to customer relationships with weighted average amortization period of 15 years and $192 million related to a 50% equity investment interest in Dos Caminos, LLC. The acquisition includes a 90% interest in NET Mexico Pipeline LLC. The goodwill consists primarily of synergies expected from the business combination and is tax deductible. The acquired assets are included in our Natural Gas business segment. The determination of fair value utilized valuation methodologies including discounted cash flows for the customer relationships intangible assets and the equity method investment and the replacement cost approach for the property, plant and equipment. The significant assumptions made in performing these valuations include the discount rate utilized to value the customer relationships intangible assets and equity method investment and replacement costs used to value property, plant and equipment. (2) Diamond M Acquisition On June 1, 2023, we completed the acquisition of the Diamond M Field from Parallel Petroleum LLC for a purchase price of $13 million, including purchase price adjustments for working capital. The acquired assets, which are adjacent to our SACROC field, are included in our CO 2 business segment. (3) North American Natural Resources Acquisition On August 11, 2022, we completed the acquisition of seven landfill assets with the purchase of North American Natural Resources, Inc. and, its sister companies, North American Biofuels, LLC and North American-Central, LLC (NANR) consisting of GTE facilities in Michigan and Kentucky for $132 million, including purchase price adjustments for working capital. Other long-term assets within the purchase price allocation consists of intangibles related to gas rights and customer contracts with a weighted average amortization period of approximately 13 years. The goodwill associated with this acquisition is tax deductible. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO 2 business segment. During November 2023, the seller exercised its option to repurchase one of the landfill assets for an insignificant amount. (4) Mas Ranger Acquisition On July 19, 2022, we completed an acquisition of three landfill assets with the purchase of Mas Ranger, LLC and its subsidiaries from Mas CanAm, LLC, comprising an RNG facility in Arlington, Texas and medium Btu facilities in Shreveport, Louisiana and Victoria, Texas for $358 million including purchase price adjustments for working capital. Other long-term assets within the purchase price allocation reflects an intangible related to a customer contract with an amortization period of approximately 17 years. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO 2 business segment. (5) Kinetrex Acquisition On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including purchase price adjustments for working capital. Other long-term assets within the purchase price allocation includes $63 million related to an equity investment and $199 million related to a customer relationship with an amortization period of approximately 10 years. Kinetrex was a supplier of LNG in the Midwest and a producer and supplier of RNG under long-term contracts to transportation service providers. At the acquisition date, Kinetrex had a 50% interest in the largest RNG facility in Indiana, and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO 2 business segment. (6) Stagecoach Acquisition On July 9, 2021 and November 24, 2021, we completed the acquisitions of Stagecoach and its subsidiaries, a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,258 million, including a purchase price adjustment for working capital. Other long-term assets within the purchase price allocation relates to customer contracts with a weighted average amortization period of less than two Pro Forma Information Pro forma consolidated income statement information that gives effect to the above acquisitions as if they had occurred as of January 1 of each year preceding each transaction is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income. Divestitures Sale of Interest in ELC On September 26, 2022, we completed the sale of a 25.5% ownership interest in ELC. We received net proceeds of $557 million which were used to reduce short-term borrowings. As we continue to have a controlling financial interest in ELC, we recorded an increase of $190 million to “Additional paid in capital” for the impact of the change in our ownership interest in ELC, which is reflected on our accompanying consolidated statement of stockholders’ equity for the year ended December 31, 2022. We continue to own a 25.5% interest in and operate ELC. We continue to consolidate ELC. We have determined that ELC is a variable interest entity and Southern Liquefaction Company, LLC (SLC), which is indirectly controlled by us, is the primary beneficiary because it has the ability to direct the activities that most significantly impact ELC’s economic performance and the right to receive benefits and the obligation to absorb losses. In addition to being the operator of ELC, the evaluation of ELC as a variable interest entity and SLC as the primary beneficiary included consideration of the following: (i) a liquefaction service agreement between ELC and its customer was designed for recovery by ELC of actual costs for operating and maintaining ELC’s facilities, which reduces the risk for all equity owners to absorb losses resulting from cost variability; and (ii) substantially all ELC’s activities involve KMI subsidiaries under common control that provide services for and benefit from the operations of ELC. The following table shows the carrying amount and classification of ELC’s assets and liabilities in our consolidated balance sheets: December 31, 2023 2022 (In millions) Assets Current assets $ 46 $ 34 Property, plant and equipment, net 1,162 1,197 Deferred charges and other assets 5 6 Liabilities Current liabilities $ 15 $ 15 Other long-term liabilities and deferred credits 25 5 We receive distributions from ELC, indirectly, through our interest in SLC, but otherwise, the assets of ELC cannot be used to settle our obligations. ELC’s creditors have no recourse against our general credit and the obligations of ELC may only be settled using the assets of ELC. ELC does not guarantee our debt or other similar commitments. Sale of an Interest in NGPL Holdings LLC On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $412 million for our proportionate share of the interests sold, which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of income for the year ended December 31, 2021. After a subsequent transfer of third party interest, we and Arclight now each hold a 37.5% interest in NGPL Holdings.

Gains and Losses on Divestiture

Gains and Losses on Divestitures, Impairments and Other Write-downs (Notes)	12 Months Ended
	Dec. 31, 2023
Impairments [Abstract]
Impairments, Divestitures And Other Write-downs	4. Losses and Gains on Divestitures, Impairments and Other Write-downs During the years ended December 31, 2023, 2022, and 2021, we recorded net pre-tax losses (gains) of $52 million, $(32) million and $1,535 million, respectively, reflecting net losses (gains) on divestitures, impairments and other write downs as detailed further below. The year ended December 31, 2021 amount primarily includes pre-tax long-lived asset impairments of $ 1,634 million We recognized the following non-cash pre-tax losses (gains) on divestitures, impairments or other write-downs on assets and equity investments during the years ended December 31, 2023, 2022, and 2021: Year Ended December 31, 2023 2022 2021 (In millions) Natural Gas Pipelines Impairments of long-lived assets(a) $ — $ — $ 1,600 Gain on sale of interest in NGPL Holdings(b) — — (206) Loss on write-down of related party note receivable(c) — — 117 Gains on divestitures of long-lived assets (10) (10) (1) Products Pipelines Impairment of equity investment(d) 67 — — Gain on divestiture of long-lived asset — (12) — Terminals Impairments of long-lived assets — — 34 (Gains) losses on divestitures of long-lived assets (1) (9) 2 CO 2 Gains on divestitures of long-lived assets (1) (1) (8) Other gains on divestitures of long-lived assets (3) — (3) Pre-tax losses (gains) on divestitures, impairments and other write-downs, net $ 52 $ (32) $ 1,535 (a) 2021 amount represents non-cash impairments associated with our South Texas gathering and processing assets. (b) See Note 3. (c) See “— Investment in Ruby ” below for a further discussion. (d) See “— Investments ” below for a further discussion. Impairments Investments During the first quarter of 2023, we recognized an impairment of $67 million related to our investment in Double Eagle Pipeline LLC (Double Eagle). The impairment was driven by lower expected renewal rates on contracts that expired in the second half of 2023. The impairment is recognized on our accompanying consolidated statement of income for the year ended December 31, 2023 within “Earnings from equity investments.” Our investment in Double Eagle and associated earnings is included within our Products Pipelines business segment. Long-lived Assets During the second quarter of 2021, we evaluated our South Texas gathering and processing assets within our Natural Gas Pipeline business segment for impairment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024. To compute the estimated undiscounted future cash flows we used the forecast of expected revenues adjusted for upcoming contract expirations. This analysis indicated that our South Texas gathering and processing assets failed step one. In step two, we utilized an income approach to estimate fair value and compared it to the carrying value. The significant assumptions made in calculating fair value include estimates of future cash flows and discount rates. We applied an approximate 8.5% discount rate, a Level 3 input, which we believed represented the estimated weighted average cost of capital of a theoretical market participant. As a result of our evaluation, we recognized a non-cash, long-lived asset impairment of $1,600 million during the year ended December 31, 2021. Investment in Ruby During the first quarter of 2021, we recognized a pre-tax charge of $117 million related to a write-down of our subordinated note receivable from our former equity investee, Ruby, which is included within “Earnings from equity investments” in our accompanying consolidated statement of income for the year ended December 31, 2021. The write-down was driven by the impairment recognized by Ruby of its assets. Ruby Chapter 11 Bankruptcy Filing The balance of Ruby Pipeline, L.L.C.’s 2022 unsecured notes matured on April 1, 2022 in the principal amount of $475 million. Although Ruby had sufficient liquidity to operate its business, it lacked sufficient liquidity to satisfy its obligations under the 2022 unsecured notes on the maturity date of April 1, 2022. Accordingly, on March 31, 2022, Ruby filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Ruby, as the debtor, continued to operate in the ordinary course as a debtor in possession under the jurisdiction of the United States Bankruptcy Court. We fully impaired our equity investment in Ruby in the fourth quarter of 2019 and fully impaired our investment in Ruby’s subordinated notes in the first quarter of 2021. We had no amounts included in our “Investments” on our accompanying consolidated balance sheet associated with Ruby as of December 31, 2022. On January 13, 2023, the bankruptcy court confirmed a plan of reorganization satisfactory to all interested parties regarding Ruby, which involved payment of Ruby’s outstanding senior notes with the proceeds from the sale of Ruby to Tallgrass, a settlement by KMI and Pembina of certain potential causes of action relating to the bankruptcy, and cash on hand. Our payment to the bankruptcy estate, net of payments it received in respect of a long-term subordinated note receivable from Ruby, was approximately $28.5 million which was accrued for as of December 31, 2022 and included within “Other, net” in our accompanying consolidated statement of income for the year ended December 31, 2022. Consummation of the settlement and the sale of Ruby to Tallgrass occurred on January 13, 2023.

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
Income Taxes (Notes)	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income Taxes	5. Income Taxes The components of “Income Before Income Taxes” are as follows: Year Ended December 31, 2023 2022 2021 (In millions) U.S. $ 3,192 $ 3,318 $ 2,217 Foreign 9 17 2 Total Income Before Income Taxes $ 3,201 $ 3,335 $ 2,219 Components of the income tax provision applicable for federal, foreign and state taxes are as follows: Year Ended December 31, 2023 2022 2021 (In millions) Current tax expense State $ 5 $ 14 $ 11 Foreign — 4 3 Total 5 18 14 Deferred tax expense Federal 619 642 334 State 91 50 21 Total 710 692 355 Total tax provision $ 715 $ 710 $ 369 The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows: Year Ended December 31, 2023 2022 2021 (In millions, except percentages) Federal income tax $ 672 21.0 % $ 700 21.0 % $ 466 21.0 % Increase (decrease) as a result of: State income tax, net of federal benefit 64 2.0 % 69 2.0 % 50 2.2 % Dividend received deduction (34) (1.1) % (36) (1.1) % (46) (2.1) % Release of valuation allowance — — % — — % (38) (1.7) % General business credit (1) — % — — % (36) (1.6) % Other 14 0.4 % (23) (0.7) % (27) (1.2) % Total $ 715 22.3 % $ 710 21.2 % $ 369 16.6 % Deferred tax assets and liabilities result from the following: December 31, 2023 2022 (In millions) Deferred tax assets Employee benefits $ 114 $ 116 Net operating loss carryforwards 2,024 2,007 Tax credit carryforwards 300 303 Interest expense limitation 266 82 Other 181 192 Valuation allowances (77) (79) Total deferred tax assets 2,808 2,621 Deferred tax liabilities Property, plant and equipment 215 163 Investments(a) 3,951 3,056 Other 30 25 Total deferred tax liabilities 4,196 3,244 Net deferred tax liability $ (1,388) $ (623) (a) Amounts as of December 31, 2023 and 2022 are primarily associated with KMI’s investment in KMP. Deferred Tax Assets and Valuation Allowances A reconciliation of our valuation allowances for the year ended December 31, 2023 is as follows: Year Ended December 31, 2023 (In millions) Balance at beginning of period $ 79 Statute expirations for state NOL and foreign tax credits (5) Currency fluctuation 3 Balance at end of period $ 77 The following table provides details related to our deferred tax assets and valuation allowances as of December 31, 2023: Unused Amount Deferred Tax Asset Valuation Allowance Expiration Period (In millions) Net Operating Loss U.S. federal net operating loss $ 6,565 $ 1,379 $ — Indefinite U.S. federal net operating loss 1,716 360 — 2035 - 2037 State losses 5,293 254 (46) 2024 - 2043 Foreign losses 90 31 (31) Indefinite Tax Credits General business credits 300 300 — 2036 - 2042 Use of a portion of our U.S. federal carryforwards is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation rules of Internal Revenue Service regulations. If certain substantial changes in our ownership occur, there would be an annual limitation on the amount of carryforwards that could be utilized. Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution. A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows: Year Ended December 31, 2023 2022 2021 (In millions) Balance at beginning of period $ 23 $ 21 $ 18 Reductions based on statute expirations (5) (5) — Audit settlement (1) — — Additions to state reserves for prior years 1 7 3 Balance at end of period $ 18 $ 23 $ 21 Amounts which, if recognized, would affect the effective tax rate $ 18 In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will increase by $4 million during the next year, primarily due to additions for state filing positions taken in prior years, offset by releases from statute expirations. The following table summarizes information of our open tax years: Jurisdiction Open Tax Year U.S. 2019 - 2023 Various states 2012 - 2023 Foreign 2008 - 2023

Property, Plant and Equipment,

Property, Plant and Equipment, net (Notes)	12 Months Ended
Property, Plant and Equipment, net (Notes)	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, net	6. Property, Plant and Equipment, net As of December 31, 2023 and 2022, our property, plant and equipment, net consisted of the following: Straight-Line Estimated Useful Life Composite December 31, 2023 2022 (Years) (%) (In millions) Interstate Natural Gas FERC-Regulated Pipelines (Natural gas) 0.80-6.67 $ 12,019 $ 11,793 Equipment (Natural gas) 0.80-6.67 9,190 8,839 Other(a) 0.00-25 823 833 Accumulated depreciation, depletion and amortization (10,301) (9,883) Depreciable assets 11,731 11,582 Land and land rights-of-way(b) 399 388 Construction work in process 394 258 Total interstate natural gas FERC-regulated 12,524 12,228 Other Pipelines (Natural gas, liquids, crude oil and CO 2 ) 5-40 0.09-33.33 9,631 8,329 Equipment (Natural gas, liquids, crude oil, CO 2 and terminals) 5-40 0.09-33.33 19,974 18,645 Other(a) 3-10 0.00-33.33 4,773 4,791 Accumulated depreciation, depletion and amortization (11,774) (10,529) Depreciable assets 22,604 21,236 Land and land rights-of-way(c) 1,518 1,350 Construction work in process 651 785 Total other 24,773 23,371 Property, plant and equipment, net $ 37,297 $ 35,599 (a) Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and miscellaneous property, plant and equipment. (b) Balances as of both December 31, 2023 and 2022 include land rights-of-way of $346 million which are depreciable. (c) Balances as of December 31, 2023 and 2022 include land rights-of-way of $720 million and $551 million, respectively, which are depreciable. Depreciation, depletion and amortization expense for property, plant and equipment was $2,020 million, $1,905 million and $1,873 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Investments (Notes)

Investments (Notes)	12 Months Ended
Investments (Notes)	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
Investments	7. Investments Our investments primarily consist of equity investments where we hold significant influence over investee actions and for which we apply the equity method of accounting. The following table provides details on our investments as of December 31, 2023 and 2022 and our earnings (loss) from these respective investments for the years ended December 31, 2023, 2022 and 2021: Ownership Interest Equity Investments Earnings (Loss) from December 31, December 31, Year Ended December 31, 2023 2023 2022 2023 2022 2021 (In millions) Citrus Corporation 50% $ 1,789 $ 1,781 $ 143 $ 145 $ 151 SNG 50% 1,668 1,669 140 145 128 PHP 27.74% 763 666 70 70 63 NGPL Holdings(a) 37.5% 623 610 121 111 94 Gulf Coast Express Pipeline LLC 34% 566 597 93 91 86 Products (SE) Pipe Line Corporation 51.17% 369 348 65 51 48 MEP 50% 342 371 87 10 (17) Utopia Holding LLC 50% 322 325 22 20 20 Gulf LNG Holdings Group, LLC 50% 275 311 25 24 22 EagleHawk 25% 273 273 18 13 8 Dos Caminos, LLC 50% 192 — — — — Red Cedar Gathering Company 49% 155 155 15 17 10 Watco Companies, LLC (b) 84 79 10 9 9 Cortez Pipeline Company 52.98% 30 31 25 30 29 Double Eagle(c) 50% 14 90 (42) 18 9 Ruby(d) — — — — (116) All others 409 347 46 49 47 Total investments $ 7,874 $ 7,653 $ 838 $ 803 $ 591 Amortization of excess cost $ (66) $ (75) $ (78) (a) Our investment in NPGL Holdings includes a related party promissory note receivable from NGPL Holdings with quarterly interest payments at 6.75%. As of December 31, 2023, we and Arclight each hold a 37.5% interest and Brookfield holds a 25% interest in NGPL Holdings. The outstanding principal amount of our related party promissory note receivable at both December 31, 2023 and 2022 was $375 million. For the years ended December 31, 2023, 2022 and 2021, we recognized $25 million, $25 million and $27 million, respectively, of interest within “Earnings from equity investments” on our accompanying consolidated statements of income. (b) We hold a preferred equity investment in Watco Companies, LLC (Watco). We own 50,000 Class B preferred shares and pursuant to the terms of the investment, receive priority, cumulative cash and stock distributions from the preferred shares at a rate of 3.00% per quarter. We do not hold any voting powers, but the class does provide us certain approval rights, including the right to appoint one of the members to Watco’s board of managers. (c) Loss for the year ended December 31, 2023 includes $67 million of our share of a non-cash impairment charge (pre-tax). For further information, see Note 4 “Losses and Gains on Divestitures, Impairments and Other Write-downs —Investments. ” (d) As of January 13, 2023, we no longer own an interest in Ruby. The loss from our investment in Ruby for the year ended December 31, 2021 includes a non-cash impairment charge of $117 million related to a write-down of our subordinated note receivable from Ruby driven by the impairment by Ruby of its assets. For further information regarding our investment in Ruby, see Note 4 “Losses and Gains on Divestitures, Impairments and Other Write-downs —Investment in Ruby. ” Summarized combined financial information for our significant equity investments (listed or described above) is reported below (amounts represent 100% of investee financial information): Year Ended December 31, Income Statement 2023 2022 2021(a) (In millions) Revenues $ 5,981 $ 5,953 $ 5,521 Costs and expenses 4,149 4,193 6,137 Net income (loss) $ 1,832 $ 1,760 $ (616) December 31, Balance Sheet 2023 2022 (In millions) Current assets $ 1,844 $ 1,461 Non-current assets 23,193 23,360 Current liabilities 1,534 1,617 Non-current liabilities 10,102 10,206 Partners’/owners’ equity 13,401 12,998 (a)

Goodwill (Notes)

Goodwill (Notes)	12 Months Ended
Goodwill (Notes)	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill Disclosure [Text Block]	8. Goodwill Changes in the amounts of our goodwill for each of the years ended December 31, 2023 and 2022 are summarized by reporting unit as follows: Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated CO 2 Products Pipelines Products Pipelines Terminals Terminals Energy Transition Ventures Total (In millions) Gross goodwill $ 15,892 $ 4,940 $ 1,528 $ 2,575 $ 221 $ 1,481 $ 63 $ 26,700 Accumulated impairment losses (1,643) (2,597) (600) (1,197) (70) (679) — (6,786) December 31, 2021 14,249 2,343 928 1,378 151 802 63 19,914 Acquisitions(a) — — — — — — 51 51 December 31, 2022 14,249 2,343 928 1,378 151 802 114 19,965 Acquisition of STX Midstream — 156 — — — — — 156 December 31, 2023 14,249 2,499 928 1,378 151 802 114 20,121 Gross goodwill 15,892 5,096 1,528 2,575 221 1,481 114 26,907 Accumulated impairment losses (1,643) (2,597) (600) (1,197) (70) (679) — (6,786) December 31, 2023 $ 14,249 $ 2,499 $ 928 $ 1,378 $ 151 $ 802 $ 114 $ 20,121 (a) Includes goodwill arising from our acquisition of NANR and a $10 million purchase price adjustment related to our acquisition of Kinetrex in 2021 that was attributed to long-term deferred tax liabilities. Results of our May 31, 2023 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded carrying value, with our Terminals reporting unit’s fair value in excess of its carrying values by less than 10% which was impacted by a decline in market multiples. We did not identify any triggers requiring further impairment analysis during the remainder of the year. The fair value estimates used in our goodwill impairment test include Level 3 inputs of the fair value hierarchy. For all reporting units other than Energy Transition Ventures, we estimated fair value based on a market approach utilizing forecasted earnings before interest, income taxes, DD&A expenses, including amortization of excess cost of equity investments, (EBITDA) and the enterprise value to estimated EBITDA multiples of comparable companies for each of our reporting units. The value of each reporting unit was determined from the perspective of a market participant in an orderly transaction between market participants at the measurement date. For Energy Transition Ventures, we estimated fair value based on an income approach, which includes assumptions regarding future cash flows based on primarily on production growth assumptions, terminal values and discount rates. Changes to any one or a combination of these factors would result in a change to the reporting unit fair values, which could lead to future impairment charges. Such potential non-cash impairments could have a significant effect on our results of operations.

Debt (Notes)

Debt (Notes)	12 Months Ended
Debt (Notes)	Dec. 31, 2023
Debt Disclosure [Abstract]
Debt	9. Debt The following table provides detail on the principal amount of our outstanding debt balances: December 31, 2023 2022 (In millions) Credit facility and commercial paper borrowings(a) $ 1,989 $ — Corporate senior notes(b) 3.15%, due January 2023 — 1,000 Floating rate, due January 2023(c) — 250 3.45%, due February 2023 — 625 3.50%, due September 2023 — 600 5.625%, due November 2023 — 750 4.15%, due February 2024 650 650 4.30%, due May 2024 600 600 4.25%, due September 2024 650 650 4.30%, due June 2025 1,500 1,500 1.75%, due November 2026 500 500 6.70%, due February 2027 7 7 2.25%, due March 2027(d) 552 535 6.67%, due November 2027 7 7 4.30%, due March 2028 1,250 1,250 7.25%, due March 2028 32 32 6.95%, due June 2028 31 31 8.05%, due October 2030 234 234 2.00%, due February 2031 750 750 7.40%, due March 2031 300 300 7.80%, due August 2031 537 537 7.75%, due January 2032 1,005 1,005 7.75%, due March 2032 300 300 4.80%, due February 2033 750 750 5.20%, due June 2033 1,500 — 7.30%, due August 2033 500 500 5.30%, due December 2034 750 750 5.80%, due March 2035 500 500 7.75%, due October 2035 1 1 6.40%, due January 2036 36 36 6.50%, due February 2037 400 400 7.42%, due February 2037 47 47 6.95%, due January 2038 1,175 1,175 6.50%, due September 2039 600 600 6.55%, due September 2040 400 400 7.50%, due November 2040 375 375 6.375%, due March 2041 600 600 5.625%, due September 2041 375 375 5.00%, due August 2042 625 625 4.70%, due November 2042 475 475 5.00%, due March 2043 700 700 5.50%, due March 2044 750 750 5.40%, due September 2044 550 550 5.55%, due June 2045 1,750 1,750 5.05%, due February 2046 800 800 5.20%, due March 2048 750 750 3.25%, due August 2050 500 500 3.60%, due February 2051 1,050 1,050 5.45%, due January 2052 750 750 7.45%, due March 2098 26 26 TGP senior notes(b) 7.00%, due March 2027 300 300 7.00%, due October 2028 400 400 2.90%, due March 2030 1,000 1,000 December 31, 2023 2022 8.375%, due June 2032 240 240 7.625%, due April 2037 300 300 EPNG senior notes(b) 7.50%, due November 2026 200 200 3.50%, due February 2032 300 300 8.375%, due June 2032 300 300 CIG senior notes(b) 4.15%, due August 2026 375 375 6.85%, due June 2037 100 100 EPC Building, LLC, promissory note, 3.967%, due January 2022 through December 2035 330 348 Trust I Preferred Securities, 4.75%, due March 2028(e) 221 220 Other miscellaneous debt(f) 234 242 Total debt – KMI and Subsidiaries 31,929 31,673 Less: Current portion of debt 4,049 3,385 Total long-term debt – KMI and Subsidiaries(g) $ 27,880 $ 28,288 (a) Weighted average interest rate on borrowings at December 31, 2023 was 5.68%. (b) Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. (c) As of December 31, 2022, we had outstanding an associated floating-to-fixed interest rate swap agreement which was designated as a cash flow hedge. (d) Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2023 exchange rate of 1.1039 U.S. dollars per Euro and at the December 31, 2022 exchange rate of 1.0705 U.S. dollars per Euro. As of December 31, 2023 and 2022, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase of $9 million and a decrease of $8 million, respectively. As of December 31, 2023, we had outstanding associated cross-currency swap agreements which are designated as cash flow hedges. (e) Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2023, had 4.4 million of 4.75% trust convertible preferred securities outstanding (referred to as the Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We provide a full and unconditional guarantee of the Trust I Preferred Securities. There are no significant restrictions from these securities on our ability to obtain funds from our subsidiaries by distribution, dividend or loan. The Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75% and carry a liquidation value of $50 per security plus accrued and unpaid distributions. The Trust I Preferred Securities outstanding as of December 31, 2023 are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; and (ii) $25.18 in cash without interest. We have the right to redeem these Trust I Preferred Securities at any time. (f) Includes finance lease obligations with monthly installments. The lease terms expire between 2026 and 2070. (g) Excludes our “Debt fair value adjustments” which, as of December 31, 2023 and 2022, increased our combined debt balances by $187 million and $115 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see “— Debt Fair Value Adjustments ” below. On January 31, 2023, we issued in a registered offering, $1,500 million aggregate principal amount of 5.20% senior notes due 2033 for net proceeds of $1,485 million, which were used to repay short-term borrowings, maturing debt and for general corporate purposes. On February 1, 2024, we issued in a registered offering, two series of senior notes consisting of $1,250 million aggregate principal amount of 5.00% senior notes due 2029 and $1,000 million aggregate principal amount of 5.40% senior notes due 2034 and received combined net proceeds of $2,230 million. We and substantially all of our wholly owned domestic subsidiaries are party to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Current Portion of Debt The following table details the components of our “Current portion of debt” reported on our consolidated balance sheets: December 31, 2023 2022 (In millions) $3.5 billion credit facility due August 20, 2027 — — $500 million credit facility due November 16, 2023 — — Commercial paper notes 1,989 — Current portion of senior notes 3.15%, due January 2023(a) — 1,000 Floating rate, due January 2023(b) — 250 3.45%, due February 2023 — 625 3.50%, due September 2023 — 600 5.625%, due November 2023 — 750 4.15%, due February 2024(c) 650 — 4.30%, due May 2024 600 — 4.25%, due September 2024 650 — Trust I Preferred Securities, 4.75% due March 2028(d) 111 111 Current portion of other debt 49 49 Total current portion of debt $ 4,049 $ 3,385 (a) On January 17, 2023, we repaid these senior notes using cash on hand and short-term borrowings. (b) These senior notes had an associated floating-to-fixed interest rate swap agreement which was designated as a cash flow hedge. (c) On February 1, 2024, we repaid these senior notes using cash on hand and short-term borrowings. (d) Reflects the portion of cash consideration payable if all the outstanding securities as of the end of the reporting period were converted by the holders. Credit Facility and Restrictive Covenants We have a $3.5 billion revolving credit facility due August 2027 with a syndicate of lenders, which can be increased by up to $1.0 billion if certain conditions, including the receipt of additional lender commitments, are met. Borrowings under our credit facility can be used for working capital and other general corporate purposes and as backup to our commercial paper program. We had a $500 million credit facility that expired on November 16, 2023. We maintain a $3.5 billion commercial paper program through the private placement of short-term notes which matures in August 2027. The notes mature up to 270 days from the date of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less a discount representing an interest factor or if interest bearing, at par. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility. Depending on the type of loan request, our borrowings under our credit facility bears interest at either (i) SOFR, plus (x) a credit spread adjustment and (y) an applicable margin ranging from 1.000% to 1.750% per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; or (3) SOFR for a one-month eurodollar loan, plus (x) a credit spread adjustment, (y) 1%, and (z) in each case, an applicable margin ranging from 0.100% to 0.750% per annum based on our credit rating. Standby fees for the unused portion of the credit facility will be calculated at a rate ranging from 0.100% to 0.250%. Our credit facility contains financial and various other covenants that apply to us and our subsidiaries and are common in such agreements, including a maximum ratio of Consolidated Net Indebtedness to Consolidated EBITDA (as defined in the credit facility, as amended) of 5.50 to 1.00, for any four-fiscal-quarter period. Other negative covenants include restrictions on our and certain of our subsidiaries’ ability to incur debt, grant liens, make fundamental changes or engage in certain transactions with affiliates, or in the case of certain material subsidiaries, permit restrictions on dividends, distributions or making or prepayments of loans to us or any guarantor. Our credit facility also restricts our ability to make certain restricted payments if an event of default (as defined in the credit facility) has occurred and is continuing or would occur and be continuing. As of December 31, 2023, we had no borrowings outstanding under our credit facility, $1,989 million borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facility as of December 31, 2023 was approximately $1.4 billion. For the years ended December 31, 2023, 2022, and 2021, we were in compliance with all required covenants. Maturities of Debt The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2023, are summarized as follows: Year Total (In millions) 2024 $ 4,049 2025 1,566 2026 1,102 2027 906 2028 1,867 Thereafter 22,439 Total $ 31,929 Debt Fair Value Adjustments The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets: December 31, 2023 2022 (In millions) Purchase accounting debt fair value adjustments $ 430 $ 472 Carrying value adjustment to hedged debt (236) (367) Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a) 185 204 Unamortized debt discounts, net (67) (68) Unamortized debt issuance costs (125) (126) Total debt fair value adjustments $ 187 $ 115 (a) As of December 31, 2023, the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 11 years. Fair Value of Financial Instruments The carrying value and estimated fair value of our outstanding debt balances is disclosed below: December 31, 2023 December 31, 2022 Carrying Estimated Carrying Estimated (In millions) Total debt $ 32,116 $ 31,370 $ 31,788 $ 30,070 (a) Included in the estimated fair value are amounts for our Trust I Preferred Securities of $207 million and $195 million as of December 31, 2023 and 2022, respectively. We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2023 and 2022. Interest Rates, Interest Rate Swaps and Contingent Debt The weighted average interest rate on all of our borrowings was 5.84% during 2023 and 4.76% during 2022. Information on our interest rate swaps is contained in Note 14. For information about our contingent debt agreements, see Note 13 “Commitments and Contingent Liabilities —Contingent Debt ”).

Share-based Compensation and Em

Share-based Compensation and Employee Benefits (Notes)	12 Months Ended
Share-based Compensation and Employee Benefits (Notes)	Dec. 31, 2023
Employee Benefit and Share-Based Payment Arrangement, Noncash Expense [Abstract]
Share-based Compensation and Employee Benefits	10. Share-based Compensation and Employee Benefits Share-based Compensation Class P Common Stock Following is a summary of our stock compensation plans: Directors’ Plan Long Term Incentive Plan Participating individuals Eligible non-employee directors Eligible employees Total number of shares of Class P common stock authorized 1,190,000 63,000,000 Vesting period 6 months 1 year to 10 years Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors We have a Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors (Directors’ Plan). The plan recognizes that the compensation paid to each eligible non-employee director is fixed by our board of directors (Board), generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving some or all of the cash compensation, each eligible non-employee director may elect annually to receive shares of Class P common stock. During the year ended December 31, 2023, we made restricted Class P common stock grants to our non-employee directors of 11,220. Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan We also have a Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan (Long Term Incentive Plan). The following table sets forth a summary of activity and related balances under our Long Term Incentive Plan: Shares Weighted Average Grant Date Fair Value per Share (In thousands, except per share amounts) Outstanding at December 31, 2022 13,288 $ 16.87 Granted 5,253 17.41 Vested (5,226) 16.09 Forfeited (454) 17.03 Outstanding at December 31, 2023 12,861 $ 17.41 The following tables set forth additional information related to our Long Term Incentive Plan: Year Ended December 31, 2023 2022 2021 (In millions, except per share amounts) Weighted average grant date fair value per share $ 17.41 $ 17.31 $ 17.44 Intrinsic value of awards vested during the year 93 47 77 Restricted stock awards expense(a) 63 60 59 Restricted stock awards capitalized(a) 10 9 9 (a) We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements. December 31, 2023 Unrecognized restricted stock awards compensation costs, less estimated forfeitures (in millions) $ 117 Weighted average remaining amortization period 2.06 years Pension and Other Postretirement Benefit (OPEB) Plans Savings Plan We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain collectively bargained participants receive Company contributions in accordance with collective bargaining agreements. A participant becomes fully vested in Company contributions after two years and may take a distribution upon termination of employment or retirement. The total cost for our savings plan was approximately $53 million, $51 million and $48 million for the years ended December 31, 2023, 2022 and 2021, respectively. Pension Plans Our pension plans are defined benefit plans that cover substantially all of our U.S. employees and provide benefits under a cash balance formula. A participant in the cash balance formula accrues benefits through contribution credits based on a combination of age and years of service, multiplied by eligible compensation. Interest is also credited to the participant’s plan account. A participant becomes fully vested in the plan after three years and may take a lump sum or annuity distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees accrue benefits through career pay or final pay formulas. In 2023, we settled approximately $179 million of the retiree benefit obligation for our pension plans through an annuity purchase. The impact of the annuity purchase is reflected in the December 31, 2023 benefit obligation for our pension plans. OPEB Plans We and certain of our subsidiaries provide OPEB benefits, including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees. These plans provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange. Medical benefits under these OPEB plans may be subject to deductibles, co-payment provisions, dollar caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits. Benefit Obligation, Plan Assets and Funded Status . The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 2023 and 2022: Pension Benefits OPEB 2023 2022 2023 2022 (In millions) Change in benefit obligation: Benefit obligation at beginning of period $ 2,077 $ 2,658 $ 195 $ 257 Service cost 55 55 1 1 Interest cost 107 57 10 5 Actuarial loss (gain) 14 (503) (6) (44) Benefits paid (132) (190) (25) (26) Participant contributions — — 1 1 Settlements (219) — — — Other — — 1 1 Benefit obligation at end of period 1,902 2,077 177 195 Change in plan assets: Fair value of plan assets at beginning of period 1,741 2,231 302 382 Actual return on plan assets 122 (350) 44 (63) Employer contributions 50 50 — 7 Participant contributions — — 1 1 Benefits paid (132) (190) (25) (26) Settlements (219) — — — Other — — 1 1 Fair value of plan assets at end of period 1,562 1,741 323 302 Funded status - net (liability) asset at December 31, $ (340) $ (336) $ 146 $ 107 Amounts recognized in the consolidated balance sheets: Non-current benefit asset(a) $ — $ — $ 263 $ 239 Current benefit liability — — (14) (15) Non-current benefit liability (340) (336) (103) (117) Funded status - net (liability) asset at December 31, $ (340) $ (336) $ 146 $ 107 Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets: Unrecognized net actuarial (loss) gain $ (384) $ (455) $ 149 $ 135 Unrecognized prior service (cost) credit — (1) 3 4 Accumulated other comprehensive (loss) income $ (384) $ (456) $ 152 $ 139 Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets: Accumulated benefit obligation $ 1,870 $ 2,047 $ 119 $ 167 Fair value of plan assets 1,562 1,741 2 34 (a) 2023 and 2022 OPEB amounts include $53 million and $45 million, respectively, of non-current benefit assets related to a plan we sponsor which is associated with employee services provided to an unconsolidated joint venture, and for which we have recorded an offsetting related party deferred credit. The 2023 net actuarial loss for the pension plans was primarily due to a decrease in the weighted average discount rate used to determine the benefit obligation as of December 31, 2023. The 2023 net actuarial gain for the OPEB plans was primarily due to changes in the claims cost assumptions. The 2022 net actuarial gain for the pension plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligation as of December 31, 2022. The 2022 net actuarial gain for the OPEB plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligations as of December 31, 2022 and changes in the claims cost assumptions. Plan Assets. The investment policies and strategies are established by our plan’s fiduciary committee for the assets of each of the pension and OPEB plans, which are responsible for investment decisions and management oversight of the plans. The stated philosophy of the fiduciary committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (i) meet or exceed plan actuarial earnings assumptions over the long term and (ii) provide a reasonable return on assets within established risk tolerance guidelines and to maintain the liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the fiduciary committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the fiduciary committee has adopted a strategy of using multiple asset classes. The allowable range for asset allocations in effect for our plans as of December 31, 2023, by asset category, are as follows: Pension Benefits OPEB Cash 0% to 23% Equities 42% to 52% 43% to 71% Fixed income securities 37% to 47% 26% to 50% Real estate 2% to 12% Company securities (KMI Class P common stock and/or debt securities) 0% to 10% Below are the details of our pension and OPEB plan assets by class and a description of the valuation methodologies used for assets measured at fair value. • Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are cash, equities and exchange traded mutual funds. These investments are valued at the closing price reported on the active market on which the individual securities are traded. • Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are short-term investment funds, fixed income securities and derivatives. Short-term investment funds are valued at amortized cost, which approximates fair value. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market. Derivatives are exchange-traded through clearinghouses and are valued based on these prices. • Plan assets with fair values that are based on the net asset value per share, or its equivalent (NAV), as a practical expedient to measure fair value, as reported by the issuers are determined based on the fair value of the underlying securities as of the valuation date and include common/collective trust funds, private investment funds, real estate and limited partnerships. The plan assets measured at NAV are not categorized within the fair value hierarchy described above, but are separately identified in the following tables. Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value by class and categorized by fair value measurement used at December 31, 2023 and 2022: Pension Assets 2023 2022 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Short-term investment funds $ — $ 32 $ 32 $ — $ 27 $ 27 Equities(a) 143 — 143 152 — 152 Fixed income securities — 410 410 — 421 421 Subtotal $ 143 $ 442 585 $ 152 $ 448 600 Measured at NAV Common/collective trusts(b) 976 1,138 Private limited partnerships(c) 1 3 Subtotal 977 1,141 Total plan assets fair value $ 1,562 $ 1,741 (a) Plan assets include $107 and $110 of KMI Class P common stock for 2023 and 2022, respectively. (b) Common/collective trust funds were invested in approximately 64% equities, 23% fixed income securities and 13% real estate in 2023 and 66% equities, 22% fixed income securities and 12% real estate in 2022. (c) Includes assets invested in real estate, venture and buyout funds. OPEB Assets 2023 2022 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Short-term investment funds $ — $ 5 $ 5 $ — $ 3 $ 3 Measured at NAV Common/collective trusts(a) 318 299 Total plan assets fair value $ 323 $ 302 (a) Common/collective trust funds were invested in approximately 62% equities and 38% fixed income securities for 2023 and 61% equities and 39% fixed income securities for 2022. Employer Contributions and Expected Payment of Future Benefits . As of December 31, 2023, we expect the following cash flows under our plans: Pension Benefits OPEB (In millions) Contributions expected in 2024 $ 50 $ — Benefit payments expected in: 2024 $ 190 $ 24 2025 187 22 2026 185 21 2027 179 19 2028 175 18 2029 - 2033 777 67 Actuarial Assumptions and Sensitivity Analysis . Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit obligation as of December 31, 2023 and 2022 and net benefit costs of our pension and OPEB plans for 2023, 2022 and 2021: Pension Benefits OPEB 2023 2022 2023 2022 Assumptions related to benefit obligations: Discount rate 5.13 % 5.41 % 5.08 % 5.38 % Rate of compensation increase 3.50 % 3.50 % n/a n/a Interest crediting rate 3.85 % 3.50 % n/a n/a Pension Benefits OPEB 2023 2022 2021 2023 2022 2021 Assumptions related to benefit costs: Discount rate 5.41 % 2.74 % 2.27 % 5.38 % 2.56 % 2.08 % Expected return on plan assets 7.00 % 6.50 % 6.25 % 6.00 % 5.75 % 5.75 % Rate of compensation increase 3.50 % 3.50 % 3.50 % n/a n/a n/a Interest crediting rate 3.50 % 3.01 % 2.57 % n/a n/a n/a We utilize a full yield curve approach in estimating the service and interest cost components of net periodic benefit cost (credit) for our retirement benefit plans by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ investment policy, and capital market projections for the asset classes in which the portfolio is invested and the target weightings of each asset class. The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the OPEB assets subject to unrelated business income taxes, we utilize an after-tax expected return on plan assets to determine our benefit costs. Actuarial estimates for our OPEB plans assume an annual increase in the per capita cost of covered health care benefits. The initial annual rate of increase is 5.60% which gradually decreases to 4.00% by the year 2047. Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows: Pension Benefits OPEB 2023 2022 2021 2023 2022 2021 (In millions) Components of net benefit cost (credit): Service cost $ 55 $ 55 $ 53 $ 1 $ 1 $ 1 Interest cost 107 57 45 10 5 4 Expected return on assets (117) (142) (133) (13) (17) (16) Amortization of prior service cost (credit) 1 1 — (3) (3) (5) Amortization of net actuarial loss (gain) 35 29 52 (16) (18) (17) Settlement loss 46 — — — — — Net benefit cost (credit) 127 — 17 (21) (32) (33) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 10 (11) (127) (30) 24 (40) Amortization or settlement recognition of net actuarial (loss) gain (81) (29) (52) 16 17 17 Amortization of prior service (cost) credit (1) (1) — 1 2 3 Total recognized in total other comprehensive (income) loss(a) (72) (41) (179) (13) 43 (20) Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ 55 $ (41) $ (162) $ (34) $ 11 $ (53) (a) Excludes $4 million and $3 million for the years ended December 31, 2022 and 2021, respectively, associated with other plans.

Stockholders' Equity (Notes)

Stockholders' Equity (Notes)	12 Months Ended
Stockholders' Equity (Notes)	Dec. 31, 2023
Stockholders' Equity Note [Abstract]
Stockholders’ Equity	11. Stockholders’ Equity Class P Common Stock On July 19, 2017, our Board approved a $2 billion share buy-back program that began in December 2017. On January 18, 2023, our Board approved an increase in our share repurchase authorization to $3 billion. All shares we have repurchased are canceled and are no longer outstanding. Activity under the buy-back program is as follows: Year Ended December 31, 2023 2022 2021 (In millions, except per share amounts) Total value of shares repurchased $ 522 $ 368 $ — Total number of shares repurchased 32 21 — Average repurchase price per share $ 16.56 $ 16.94 $ — Subsequent to December 31, 2023 and through February 16, 2024, we repurchased less than 1 million shares at an average price of $16.50 for $7 million. Since December 2017, in total, we have repurchased 86 million of our shares under the program at an average price of $17.09 per share for $1,472 million, leaving capacity under the program of $1.5 billion . On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the managers party thereto, as sales agents and/or principals, shares having an aggregate offering price of up to $5 billion from time to time during the term of this agreement. During the years ended December 31, 2023, 2022 and 2021 we did not issue any shares under this agreement. Dividends The following table provides information about our per share dividends: Year Ended December 31, 2023 2022 2021 Per share cash dividend declared for the period $ 1.13 $ 1.11 $ 1.08 Per share cash dividend paid in the period 1.1250 1.1025 1.0725 On January 17, 2024, our Board declared a cash dividend of $0.2825 per share for the quarterly period ended December 31, 2023, which was paid on February 15, 2024 to shareholders of record as of January 31, 2024. Adoption of Accounting Pronouncement On January 1, 2022, we adopted Accounting Standards Update (ASU) No. 2020-06, “ Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. ” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in Subtopic 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted earnings per share calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. Using the modified retrospective method, the adoption of this ASU resulted in a pre-tax adjustment of $14 million to unwind the remaining unamortized debt discount within “Debt fair value adjustments” on our consolidated balance sheet and an adjustment of $11 million to unwind the balance of the conversion feature classified in “Additional paid in capital” on our consolidated statement of stockholders’ equity for the year ended December 31, 2022. Accumulated Other Comprehensive Loss Changes in the components of our “Accumulated other comprehensive loss” not including noncontrolling interests are summarized as follows: Net unrealized Pension and Total (In millions) Balance at December 31, 2020 $ (13) $ (394) $ (407) Other comprehensive (loss) gain before reclassifications (432) 155 (277) Losses reclassified from accumulated other comprehensive loss 273 — 273 Net current-period change in accumulated other comprehensive loss (159) 155 (4) Balance at December 31, 2021 (172) (239) (411) Other comprehensive (loss) gain before reclassifications (312) 1 (311) Losses reclassified from accumulated other comprehensive loss 320 — 320 Net current-period change in accumulated other comprehensive loss 8 1 9 Balance at December 31, 2022 (164) (238) (402) Other comprehensive gain before reclassifications 155 65 220 Gains reclassified from accumulated other comprehensive loss (35) — (35) Net current-period change in accumulated other comprehensive loss 120 65 185 Balance at December 31, 2023 $ (44) $ (173) $ (217)

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
Related Party Transactions (Notes)	Dec. 31, 2023
Related Party Transactions [Abstract]
Related Party Transactions	12. Related Party Transactions Affiliate Balances and Activities We have transactions with affiliates which consist of (i) unconsolidated affiliates in which we hold an investment accounted for under the equity method of accounting (see Note 7 for additional information related to these investments); and (ii) external partners of our joint ventures we consolidate. The following tables summarize our affiliate balance sheet balances and income statement activity, other than amounts reported within our “Investments” balances and “Earnings from equity investments” activity: December 31, 2023 2022 (In millions) Balance sheet location Accounts receivable $ 45 $ 39 Other current assets 2 3 $ 47 $ 42 Current portion of debt $ 5 $ 6 Accounts payable 16 19 Other current liabilities 3 8 Long-term debt 137 142 Other long-term liabilities and deferred credits 54 47 $ 215 $ 222 Year Ended December 31, 2023 2022 2021 (In millions) Income statement location Revenues $ 172 $ 172 $ 164 Operating Costs, Expenses and Other Costs of sales $ 132 $ 134 $ 145 Other operating expenses 57 50 52

Commitments and Contingent Liab

Commitments and Contingent Liabilities (Notes)	12 Months Ended
Commitments and Contingent Liabilities (Notes)	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	13. Commitments and Contingent Liabilities Rights-Of-Way Our rights-of-way obligations primarily consist of non-lease agreements that existed at the time of Topic 842 , Leases, adoption, at which time we elected a practical expedient which allowed us to continue our historical treatment. Our future minimum rental commitments related to our rights-of-way obligations were $98 million as of December 31, 2023. Contingent Debt Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote. As of December 31, 2023 and 2022, our contingent debt obligations totaled $154 million and $163 million, respectively. These amounts represent our proportional share of the debt obligations of one equity investee, Cortez Pipeline Company (Cortez). Under such guarantees we are severally liable for our percentage ownership share of Cortez’s debt in the event of its non-performance. The contingent debt obligations balances as of December 31, 2023 and 2022 each included $120 million for 100% guaranteed debt obligations for a subsidiary of Cortez. Guarantees and Indemnifications We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters. While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are also circumstances where the amount and duration are unlimited. Other than with our rights-of-way obligations and contingent debt described above, we are currently not subject to any material requirements to perform under quantifiable arrangements. We are unable to estimate a maximum exposure for our other guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures. See Note 18 for a description of matters that we have identified as contingencies requiring accrual of liabilities and/or disclosure, including any such matters arising under guarantee or indemnification agreements.

Risk Management (Notes)

Risk Management (Notes)	12 Months Ended
Risk Management (Notes)	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management	14. Risk Management Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks. Energy Commodity Price Risk Management As of December 31, 2023, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales: Net open position long/(short) Derivatives designated as hedging contracts Crude oil fixed price (16.9) MMBbl Natural gas fixed price (61.0) Bcf Natural gas basis (35.4) Bcf NGL fixed price (0.6) MMBbl Derivatives not designated as hedging contracts Crude oil fixed price (1.2) MMBbl Crude oil basis (4.1) MMBbl Natural gas fixed price (7.5) Bcf Natural gas basis (101.6) Bcf NGL fixed price (0.7) MMBbl As of December 31, 2023, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2028. Interest Rate Risk Management We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of December 31, 2023: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments Fixed-to-variable interest rate contracts(a)(b) $ 6,200 Fair value hedge March 2035 Treasury locks(c) 1,000 Cash flow hedge March 2024 (a) The principal amount of hedged senior notes consisted of $1,450 million included in “Current portion of debt” and $4,750 million included in “Long-term debt” on our accompanying consolidated balance sheet. (b) During the year ended December 31, 2023, certain optional expedients as set forth in Topic 848 – Reference Rate Reform were elected on certain of these contracts to preserve fair value hedge accounting treatment. See Note 19 “Recent Accounting Pronouncements” for further information on Topic 848. (c) The treasury lock agreements were terminated on January 29, 2024 concurrently with the issuance of senior notes which closed on February 1, 2024 (see Note 9 “Debt”). Foreign Currency Risk Management We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of December 31, 2023: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments EUR-to-USD cross currency swap contracts(a) $ 543 Cash flow hedge March 2027 (a) These s waps eliminate the foreign currency risk associated with our Euro-denominated debt. Impact of Derivative Contracts on Our Consolidated Financial Statements The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets: Fair Value of Derivative Contracts Location Derivatives Asset Derivatives Liability December 31, December 31, 2023 2022 2023 2022 (In millions) Derivatives designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Fair value of derivative contracts) $ 77 $ 150 $ (75) $ (156) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 12 6 (29) (91) Subtotal 89 156 (104) (247) Interest rate contracts Fair value of derivative contracts/(Fair value of derivative contracts) — — (120) (144) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 37 39 (158) (261) Subtotal 37 39 (278) (405) Foreign currency contracts Fair value of derivative contracts/(Fair value of derivative contracts) — — (2) (3) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (2) (32) Subtotal — — (4) (35) Total 126 195 (386) (687) Derivatives not designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Fair value of derivative contracts) 49 80 (8) (162) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 3 23 (1) (19) Subtotal 52 103 (9) (181) Interest rate contracts Fair value of derivative contracts/(Fair value of derivative contracts) — 1 — — Total 52 104 (9) (181) Total derivatives $ 178 $ 299 $ (395) $ (868) The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements. Balance sheet asset fair value measurements by level Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral held(a) Net amount (In millions) As of December 31, 2023 Energy commodity derivative contracts(b) $ 65 $ 75 $ — $ 140 $ (16) $ — $ 124 Interest rate contracts — 38 — 38 — — 38 As of December 31, 2022 Energy commodity derivative contracts(b) $ 115 $ 144 $ — $ 259 $ (186) $ — $ 73 Interest rate contracts — 40 — 40 — — 40 Balance sheet liability Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral posted(a) Net amount (In millions) As of December 31, 2023 Energy commodity derivative contracts(b) $ (17) $ (96) $ — $ (113) $ 16 $ (85) $ (182) Interest rate contracts — (278) — (278) — — (278) Foreign currency contracts — (4) — (4) — — (4) As of December 31, 2022 Energy commodity derivative contracts(b) (23) (405) — (428) 186 (30) (272) Interest rate contracts — (405) — (405) — — (405) Foreign currency contracts — (35) — (35) — — (35) (a) Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table. (b) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps. The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of income and comprehensive income: Derivatives in fair value hedging relationships Location Gain/(loss) recognized in income on derivatives and related hedged item Year Ended December 31, 2023 2022 2021 (In millions) Interest rate contracts Interest, net $ 138 $ (738) $ (322) Hedged fixed rate debt(a) Interest, net $ (132) $ 743 $ 326 (a) As of December 31, 2023, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $236 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet. Derivatives in cash flow hedging relationships Gain/(loss) recognized in OCI on derivatives(a) Location Gain/(loss) reclassified from Accumulated OCI into income(b) Year Ended Year Ended December 31, December 31, 2023 2022 2021 2023 2022 2021 (In millions) (In millions) Energy commodity derivative contracts $ 182 $ (338) $ (475) Revenues—Commodity sales $ 103 $ (491) $ (271) Costs of sales (73) 144 20 Interest rate contracts (10) 7 5 Interest, net — — — Foreign currency contracts 30 (73) (93) Other, net 17 (68) (105) Total $ 202 $ (404) $ (563) Total $ 47 $ (415) $ (356) (a) We expect to reclassify an approximately $10 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2023 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices. (b) During the years ended December 31, 2023, 2022 and 2021, we recognized gains of none, $121 million and $41 million, respectively, associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred). Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives Year Ended December 31, 2023 2022 2021 (In millions) Energy commodity derivative contracts Revenues—Commodity sales $ 75 $ 137 $ (652) Costs of sales 100 (190) 152 Earnings from equity investments 2 (11) (5) Interest rate contracts Interest, net 1 (10) 12 Total(a) $ 178 $ (74) $ (493) (a) The years ended December 31, 2023, 2022 and 2021 include approximate gains (losses) of $58 million, $(11) million and $(479) million, respectively, associated with natural gas, crude and NGL derivative contract settlements. Credit Risks In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2023 and 2022, we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2023 and 2022, we had cash margins of $63 million and $1 million, respectively, posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The balance at December 31, 2023 represents the initial margin requirements of $22 million, offset by counterparty variation margin requirements of $85 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty. We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of December 31, 2023, based on our current mark-to- market positions and posted collateral, we estimate that if our credit rating were downgraded one notch, we would not be required to post additional collateral. If we were downgraded two notches, we estimate that we would be required to post $54 million of additional collateral.

Revenue Recognition (Notes)

Revenue Recognition (Notes)	12 Months Ended
Revenue Recognition (Notes)	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Revenue Recognition	15. Revenue Recognition Nature of Revenue by Segment Natural Gas Pipelines Segment We provide various types of natural gas transportation and storage services, natural gas and NGL sales contracts, and various types of gathering and processing services for producers, including receiving, compressing, transporting and re-delivering quantities of natural gas and/or NGLs made available to us by producers to a specified delivery location. Natural Gas Transportation and Storage Contracts The natural gas we receive under our transportation and storage contracts remains under the control of our customers. Under firm service contracts, the customer generally pays a two-part transaction price that includes (i) a fixed take-or-pay reservation fee and (ii) a fee-based per-unit rate for quantities of natural gas actually transported or injected into/withdrawn from storage. Under non-firm service contracts, generally described as interruptible service, the customer pays a transaction price on a fee-based per-unit rate for the quantities actually transported or injected into/withdrawn from storage. Natural Gas and NGL Sales Contracts Our sales and purchases of natural gas and NGL are primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales. These customer contracts generally provide for the customer to nominate a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold. Gathering and Processing Contracts We provide various types of gathering and processing services for producers, including receiving, processing, compressing, transporting and re-delivering quantities of natural gas made available to us by producers to a specified delivery location. This integrated service can be firm if subject to a minimum volume commitment or acreage dedication or non-firm when offered on an as requested, non-guaranteed basis. In our gathering contracts we generally promise to provide the contracted integrated services each day over the life of the contract. The customer pays a transaction price typically based on a per-unit rate for the quantities actually gathered and/or processed, including amounts attributable to deficiency quantities associated with minimum volume contracts. Products Pipelines Segment We provide crude oil and refined petroleum transportation and storage services on a firm or non-firm basis. For our firm transportation service, the customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it flows volumes into our pipeline. The customer pays a transaction price typically based on a per-unit rate for quantities transported, including amounts attributable to deficiency quantities. Our firm storage service generally includes a fixed take-or-pay monthly reservation fee for the portion of storage capacity reserved by the customer and a per-unit rate for actual quantities injected into/withdrawn from storage. Under the non-firm transportation and storage service the customer typically pays a per-unit rate for actual quantities of product injected into/withdrawn from storage and/or transported. We sell transmix, crude oil or other commodity products. The customer’s contracts generally include a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold. Terminals Segment We provide various types of liquid tank and bulk terminal services. These services are generally comprised of inbound, storage and outbound handling of customer products. Liquids Tank Services Firm Storage and Handling Contracts: We have liquids tank storage and handling service contracts that include a promised tank storage capacity provision and prepaid volume throughput of the stored product. In these contracts, the customers have fixed take-or-pay monthly obligation which generally include a per-unit rate for any quantities we handle at the request of the customer in excess of the prepaid volume throughput amount and also typically include per-unit rates for additional, ancillary services that may be periodically requested by the customer. Firm Handling Contracts: For our firm handling service contracts, we typically promise to handle on a stand-ready basis throughput volumes up to the customer’s minimum volume commitment amount. The customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it used the handling service. The customer pays a transaction price typically based on a per-unit rate for volumes handled, including amounts attributable to deficiency quantities. Bulk Services Our bulk storage and handling contracts generally include inbound handling of our customers’ dry bulk material product (e.g., petcoke, metals, ores) into our storage facility and outbound handling of these products from our storage facility. These services are provided on both a firm basis, including amounts attributable to deficiency quantities, and non-firm basis where the customer pays a transaction price typically based on a per-unit rate for quantities handled on an as requested, non-guaranteed basis. CO 2 Segment Our crude oil, NGL, CO 2 and natural gas production customer sales contracts typically include a specified quantity and quality of commodity product to be delivered and sold to the customer at a specified delivery point. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold. Disaggregation of Revenues The following tables present our revenues disaggregated by segment, revenue source and type of revenue for each revenue source: Year Ended December 31, 2023 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,543 $ 171 $ 819 $ 1 $ 3 $ 4,537 Fee-based services 1,008 1,036 427 40 (9) 2,502 Total services 4,551 1,207 1,246 41 (6) 7,039 Commodity sales Natural gas sales 2,651 — — 85 (12) 2,724 Product sales 1,110 1,635 33 1,114 (8) 3,884 Total commodity sales 3,761 1,635 33 1,199 (20) 6,608 Total revenues from contracts with customers 8,312 2,842 1,279 1,240 (26) 13,647 Other revenues(c) Leasing services(d) 475 200 638 55 — 1,368 Derivatives adjustments on commodity sales 285 — — (107) — 178 Other 96 24 — 21 — 141 Total other revenues 856 224 638 (31) — 1,687 Total revenues $ 9,168 $ 3,066 $ 1,917 $ 1,209 $ (26) $ 15,334 Year Ended December 31, 2022 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,547 $ 207 $ 763 $ 1 $ (3) $ 4,515 Fee-based services 926 962 426 46 — 2,360 Total services 4,473 1,169 1,189 47 (3) 6,875 Commodity sales Natural gas sales 6,266 — — 94 (20) 6,340 Product sales 1,433 2,032 29 1,426 (7) 4,913 Total commodity sales 7,699 2,032 29 1,520 (27) 11,253 Total revenues from contracts with customers 12,172 3,201 1,218 1,567 (30) 18,128 Other revenues(c) Leasing services(d) 474 194 574 60 — 1,302 Derivatives adjustments on commodity sales (26) (3) — (325) — (354) Other 66 26 — 32 — 124 Total other revenues 514 217 574 (233) — 1,072 Total revenues $ 12,686 $ 3,418 $ 1,792 $ 1,334 $ (30) $ 19,200 Year Ended December 31, 2021 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,402 $ 259 $ 751 $ 1 $ (2) $ 4,411 Fee-based services 746 949 375 45 (1) 2,114 Total services 4,148 1,208 1,126 46 (3) 6,525 Commodity sales Natural gas sales 6,463 — — 32 (15) 6,480 Product sales 1,260 845 24 1,070 (50) 3,149 Total commodity sales 7,723 845 24 1,102 (65) 9,629 Total revenues from contracts with customers 11,871 2,053 1,150 1,148 (68) 16,154 Other revenues(c) Leasing services(d) 473 172 565 56 — 1,266 Derivatives adjustments on commodity sales (700) (1) — (222) — (923) Other 65 21 — 27 — 113 Total other revenues (162) 192 565 (139) — 456 Total revenues $ 11,709 $ 2,245 $ 1,715 $ 1,009 $ (68) $ 16,610 (a) Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c)). (b) Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as “Fee-based services.” (c) Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 14 for additional information related to our derivative contracts. (d) Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases. Contract Balances As of December 31, 2023 and 2022, our contract asset balances were $34 million and $33 million, respectively. Of the contract asset balance at December 31, 2022, $23 million was transferred to accounts receivable during the year ended December 31, 2023. As of December 31, 2023 and 2022, our contract liability balances were $415 million and $204 million, respectively. Of the contract liability balance at December 31, 2022, $71 million was recognized as revenue during the year ended December 31, 2023. During the year ended December 31, 2023, we entered into an agreement with a customer to prepay certain fixed reservation charges under long-term transportation and terminaling contracts. We received $843 million in the fourth quarter of 2023 as part of this agreement. The prepayment, which relates to contracts expiring from 2035 to 2040, was discounted to present value at a rate that is attractive relative to our cost of issuing long-term debt. As of December 31, 2023, we had a lease contract liability balance of $643 million and a contract liability balance of $195 million associated with this prepayment. Revenue Allocated to Remaining Performance Obligations The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of December 31, 2023 that we will invoice or transfer from contract liabilities and recognize in future periods: Year Estimated Revenue (In millions) 2024 $ 4,687 2025 4,007 2026 3,472 2027 2,874 2028 2,475 Thereafter 14,336 Total $ 31,851 Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts, based on the practical expedient that we elected to apply, generally exclude remaining performance obligations for contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

Reportable Segments (Notes)

Reportable Segments (Notes)	12 Months Ended
Reportable Segments (Notes)	Dec. 31, 2023
Segment Reporting [Abstract]
Reportable Segments	16. Reportable Segments Our reportable business segments are: • Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG regasification, liquefaction and storage facilities; • Products Pipelines—the ownership and operation of refined petroleum products, crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, crude oil and condensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; • Terminals—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. that store and handle various commodities including gasoline, diesel fuel, chemicals, petroleum coke, metals and ethanol and other renewable fuels and feedstocks; and (ii) Jones Act-qualified tankers; • CO 2 —(i) the production, transportation and marketing of CO 2 to oil fields that use CO 2 as a flooding medium to increase recovery and production of crude oil from mature oil fields; (ii) ownership interests in and/or operation of oil fields and gasoline processing plants in West Texas; (iii) the ownership and operation of a crude oil pipeline system in West Texas; an d (iv) the ownership and operation of RNG and LNG facilities. We evaluate performance principally based on each segment’s earnings before DD&A expenses, including amortization of excess cost of equity investments, (EBDA), which excludes general and administrative expenses and corporate charges, interest expense, net, and income tax expense. Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision makers organize their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and services and marketing strategies. We consider each period’s earnings before all non-cash DD&A expenses to be an important measure of business segment performance for our reporting segments. We account for intersegment sales at market prices, while we account for asset transfers at book value. During 2023, 2022 and 2021, we did not have revenues from any single external customer that exceeded 10% of our consolidated revenues. Financial information by segment follows: Year Ended December 31, 2023 2022 2021 (In millions) Revenues Natural Gas Pipelines Revenues from external customers $ 9,152 $ 12,659 $ 11,644 Intersegment revenues 16 27 65 Products Pipelines 3,066 3,418 2,245 Terminals Revenues from external customers 1,911 1,789 1,712 Intersegment revenues 6 3 3 CO 2 Revenues from external customers 1,205 1,334 1,009 Intersegment revenues 4 — — Corporate and intersegment eliminations (26) (30) (68) Total consolidated revenues $ 15,334 $ 19,200 $ 16,610 Year Ended December 31, 2023 2022 2021 (In millions) Operating expenses(a) Natural Gas Pipelines $ 4,700 $ 8,562 $ 7,000 Products Pipelines 2,024 2,391 1,239 Terminals 896 853 793 CO 2 550 554 289 Corporate and intersegment eliminations (4) (9) (34) Total consolidated operating expenses $ 8,166 $ 12,351 $ 9,287 Year Ended December 31, 2023 2022 2021 (In millions) Other expense (income)(b) Natural Gas Pipelines $ (12) $ (13) $ 1,597 Products Pipelines 4 (12) — Terminals (2) (14) 32 CO 2 — (1) (8) Corporate (3) 1 (4) Total consolidated other expense (income) $ (13) $ (39) $ 1,617 Year Ended December 31, 2023 2022 2021 (In millions) DD&A Natural Gas Pipelines $ 1,041 $ 1,096 $ 1,099 Products Pipelines 367 336 335 Terminals 493 458 440 CO 2 325 272 236 Corporate 24 24 25 Total consolidated DD&A $ 2,250 $ 2,186 $ 2,135 Year Ended December 31, 2023 2022 2021 (In millions) Earnings from equity investments and amortization of excess cost of equity investments Natural Gas Pipelines $ 746 $ 650 $ 435 Products Pipelines (6) 33 34 Terminals 9 14 15 CO 2 23 31 29 Total consolidated equity earnings $ 772 $ 728 $ 513 Year Ended December 31, 2023 2022 2021 (In millions) Other, net-income (expense) Natural Gas Pipelines $ 26 $ (19) $ 216 Products Pipelines 1 — 1 Terminals 8 8 3 Corporate (72) 66 62 Total consolidated other, net-income (expense) $ (37) $ 55 $ 282 Year Ended December 31, 2023 2022 2021 (In millions) Segment EBDA(c) Natural Gas Pipelines $ 5,282 $ 4,801 $ 3,815 Products Pipelines 1,062 1,107 1,064 Terminals 1,040 975 908 CO 2 689 819 760 Total Segment EBDA 8,073 7,702 6,547 DD&A (2,250) (2,186) (2,135) Amortization of excess cost of equity investments (66) (75) (78) General and administrative and corporate charges (759) (593) (623) Interest, net (1,797) (1,513) (1,492) Income tax expense (715) (710) (369) Total consolidated net income $ 2,486 $ 2,625 $ 1,850 Year Ended December 31, 2023 2022 2021 (In millions) Capital expenditures Natural Gas Pipelines $ 1,299 $ 666 $ 570 Products Pipelines 221 — 122 Terminals 406 552 332 CO 2 355 371 230 Corporate 36 32 27 Total consolidated capital expenditures $ 2,317 $ 1,621 $ 1,281 December 31, 2023 2022 (In millions) Investments Natural Gas Pipelines $ 7,273 $ 6,993 Products Pipelines 390 445 Terminals 130 128 CO 2 81 87 Total consolidated investments $ 7,874 $ 7,653 December 31, 2023 2022 (In millions) Other intangibles, net Natural Gas Pipelines $ 742 $ 439 Products Pipelines 687 777 Terminals 26 38 CO 2 502 555 Total consolidated other intangibles, net $ 1,957 $ 1,809 December 31, 2023 2022 (In millions) Assets Natural Gas Pipelines $ 49,883 $ 47,978 Products Pipelines 8,781 8,985 Terminals 8,235 8,357 CO 2 3,497 3,449 Corporate assets(d) 624 1,309 Total consolidated assets $ 71,020 $ 70,078 (a) Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes. (b) Include s (gain) loss on divestitures and impairments, net and other (expense) income, net. (c) Includes revenues, earnings from equity investments, and other, net, less operating expenses, (gain) loss on divestitures and impairments, net and other (expense) income, net. (d) Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments. We do not attribute interest and debt expense to any of our reportable business segments. Following is geographic information regarding the revenues and long-lived assets of our business: Year Ended December 31, 2023 2022 2021 (In millions) Revenues from external customers U.S. $ 15,255 $ 19,036 $ 16,479 Mexico and other foreign 79 164 131 Total consolidated revenues from external customers $ 15,334 $ 19,200 $ 16,610 December 31, 2023 2022 2021 (In millions) Long-term assets, excluding goodwill and other intangibles U.S. $ 46,328 $ 44,425 $ 44,916 Mexico and other foreign 72 75 78 Canada — 1 1 Total consolidated long-lived assets $ 46,400 $ 44,501 $ 44,995

Leases (Notes)

Leases (Notes)	12 Months Ended
Leases (Notes)	Dec. 31, 2023
Leases [Abstract]
Leases: Lessee	17. Leases Following are components of our lease cost: Year Ended December 31, 2023 2022 2021 (In millions) Operating leases $ 71 $ 62 $ 60 Short-term and variable leases 127 101 109 Total lease cost $ 198 $ 163 $ 169 Other information related to our operating leases are as follows: Year Ended December 31, 2023 2022 2021 (In millions, Operating cash flows from operating leases $ (157) $ (132) $ (137) Investing cash flows from operating leases (41) (31) (32) ROU assets obtained in exchange for operating lease obligations, net of retirements 56 22 59 Amortization of ROU assets 58 50 47 Weighted average remaining lease term 8.72 years 9.8 years 10.39 years Weighted average discount rate 4.59 % 4.26 % 3.95 % Amounts recognized in the accompanying consolidated balance sheets are as follows: December 31, Lease Activity(a) Balance sheet location 2023 2022 (In millions) ROU assets Deferred charges and other assets $ 285 $ 287 Short-term lease liability Other current liabilities 55 47 Long-term lease liability Other long-term liabilities and deferred credits 230 240 (a) We have immaterial financing leases recorded as of December 31, 2023 and 2022. Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2023 are as follows: Year Commitment (In millions) 2024 $ 67 2025 56 2026 40 2027 33 2028 25 Thereafter 145 Total lease payments 366 Less: Interest (81) Present value of lease liabilities $ 285 Short-term lease costs are not material to us and are anticipated to be similar to the current year short-term lease expense outlined in this disclosure.

Litigation and Environmental (N

Litigation and Environmental (Notes)	12 Months Ended
Litigation and Environmental (Notes)	Dec. 31, 2023
Loss Contingency, Information about Litigation Matters [Abstract]
Litigation and Environmental	18. Litigation and Environmental We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact to our business. We believe we have numerous and substantial defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose the following contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed. Gulf LNG Facility Disputes Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) filed a lawsuit in 2018 against Eni S.p.A. in the Supreme Court of the State of New York to enforce a Guarantee Agreement (Guarantee) entered into by Eni S.p.A. in 2007 in connection with a contemporaneous terminal use agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA). GLNG filed suit to enforce the Guarantee against Eni S.p.A. after an arbitration tribunal delivered an award which called for the termination of the terminal use agreement and payment of compensation by Eni USA to GLNG. In response to GLNG’s lawsuit, Eni S.p.A. filed counterclaims and other claims based on the terminal use agreement and a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing counterclaims and other claims asserted by Eni S.p.A sought unspecified damages based on the same substantive allegations which were dismissed with prejudice in previous separate arbitrations with Eni USA described above and with GLNG’s remaining customer Angola LNG Supply Services LLC, a consortium of international oil companies including Eni S.p.A. In early 2022, the trial court granted Eni S.p.A’s motion for summary judgment on GLNG’s claims to enforce the Guarantee. The Appellate Division denied GLNG’s appeal and its motion for rehearing in 2023. GLNG elected not to pursue further recourse to the state Court of Appeals, which is the state’s highest appellate court, thereby concluding GLNG’s efforts to enforce the Guarantee. With respect to the counterclaims and other claims asserted by Eni S.p.A., the trial court granted GLNG’s motion for summary judgment and entered judgment dismissing all of Eni S.p.A.’s claims with prejudice on September 15, 2023. Eni S.p.A. filed a notice of appeal to the state Appellate Division. We intend to vigorously oppose Eni S.p.A’s appeal, which remains pending. Freeport LNG Winter Storm Litigation On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed a lawsuit against KMTP and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. On October 24, 2022, the trial court granted our motion for summary judgment on all of Freeport’s claims. On November 21, 2022, Freeport filed a notice of appeal to the 14th Court of Appeals, where the matter remains pending. We believe our declaration of force majeure was proper and intend to continue to vigorously defend this case. Pension Plan Litigation On February 22, 2021, Kinder Morgan Retirement Plan A participants Curtis Pedersen and Beverly Leutloff filed a purported class action lawsuit under the Employee Retirement Income Security Act of 1974 (ERISA). The named plaintiffs were hired initially by the ANR Pipeline Company (ANR) in the late 1970s. Following a series of corporate acquisitions, plaintiffs became participants in pension plans sponsored by the Coastal Corporation (Coastal), El Paso Corporation (El Paso) and our company by virtue of our acquisition of El Paso in 2012 and our assumption of certain of El Paso’s pension plan obligations. The complaint, which was filed initially in federal court in Michigan, then transferred to the U.S. District Court for the Southern District of Texas (Civil Action No. 4:21-3590), and later amended to include the Kinder Morgan Retirement Plan B, alleges that the series of foregoing transactions resulted in changes to plaintiffs’ retirement benefits which are now contested on a purported class-wide basis in the lawsuit. The complaint asserts six claims that fall within three primary theories of liability. Claims I, II, and III all seek the same plan modification as to how the plans calculate benefits for former participants in the Coastal plan. These claims challenge plan provisions which are alleged to constitute impermissible “backloading” or “cutback” of benefits. Claims IV and V allege that former participants in the ANR plans should be eligible for unreduced benefits at younger ages than the plans currently provide. Claim VI asserts that actuarial assumptions used to calculate reduced early retirement benefits for current or former ANR employees are outdated and therefore unreasonable. On February 8, 2024, the Court certified a class defined as any and all persons who participated in the Kinder Morgan Retirement Plan A or B who are current or former employees of ANR or Coastal, and participated in the El Paso pension plan after El Paso acquired Coastal in 2001, and are members of at least one of three subclasses of individuals who are allegedly due benefits under one or more of the six claims asserted in the complaint. Plaintiffs seek to recover early retirement benefits as well as declaratory and injunctive relief, but have not pleaded, disclosed or otherwise specified a calculation of alleged damages. Accordingly, the extent of potential plan liabilities for past or future benefits, if any, remains to be determined in a bench trial scheduled to begin on August 5, 2024. We believe we have numerous and substantial defenses and intend to vigorously defend this case. Pipeline Integrity and Releases From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties. Arizona Line 2000 Rupture On August 15, 2021, the 30” EPNG Line 2000 natural gas transmission pipeline ruptured in a rural area in Coolidge, Arizona. The failure resulted in a fire which destroyed a home, resulting in two fatalities and one injury. The National Transportation Safety Board investigated the incident and issued its report on April 27, 2023. EPNG completed the physical work on Line 2000 in accordance with PHMSA’s requirements and returned the pipeline to commercial service in February 2023. We notified our insurers and resolved the claims presented by or on behalf of the owner and residents of the home without litigation or a material adverse impact to our business. General As of December 31, 2023 and 2022, our total reserve for legal matters was $23 million and $70 million, respectively. Environmental Matters We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to local, state and federal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal, CO 2 field and oil field, and our other operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations. We are currently involved in several governmental proceedings involving alleged violations of local, state and federal environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but except as disclosed herein we do not believe any such fines and penalties will be material to our business, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under state or federal administrative orders or related remediation programs. We have established a reserve to address the costs associated with the remediation efforts. In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state Superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, crude oil, NGL, natural gas or CO 2 , including natural resource damage (NRD) claims. Portland Harbor Superfund Site, Willamette River, Portland, Oregon On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated to be more than $2.8 billion and active cleanup is expected to take more than 10 years to complete. KMLT, KMBT, and some 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. At this time we anticipate the non-judicial allocation process will be complete in or around June 2025. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business. In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, NRD claims in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the PHSS. Lower Passaic River Study Area of the Diamond Alkali Superfund Site, New Jersey EPEC Polymers, Inc. and EPEC Oil Company Liquidating Trust (collectively EPEC) are identified as PRPs in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River in New Jersey. On March 4, 2016, the EPA issued a ROD for the lower eight miles of the Site. At that time the cleanup plan in the ROD was estimated to cost $1.7 billion. The cleanup is expected to take at least six years to complete once it begins. In addition, the EPA and numerous PRPs, including EPEC, engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. That process was completed December 28, 2020 and certain PRPs, including EPEC, engaged in discussions with the EPA as a result thereof. On October 4, 2021, the EPA issued a ROD for the upper nine miles of the Site. At that time, the cleanup plan in the ROD was estimated to cost $440 million. No timeline for the cleanup has been established. On December 16, 2022, the United States Department of Justice (DOJ) and the EPA announced a settlement and proposed consent decree with 85 PRPs, including EPEC, to resolve their collective liability at the Site. The total amount of the settlement is $150 million. Also on December 16, 2022, the DOJ on behalf of the EPA filed a Complaint against the 85 PRPs, including EPEC, a Notice of Lodging of Consent Decree, and a Consent Decree in the U.S. District Court for the District of New Jersey. On January 17, 2024, the DOJ on behalf of the EPA voluntarily dismissed its Complaint against 3 PRPs, filed an Amended Complaint against 82 PRPs, including EPEC, and a modified Consent Decree in the U.S. District Court. On January 31, 2024, the DOJ on behalf of the EPA filed a motion to Enter Consent Decree in the U.S. District Court. We believe our share of the costs to resolve this matter, including our share of the settlement with the EPA and the costs to remediate the Site, if any, will not have a material adverse impact to our business. Louisiana Governmental Coastal Zone Erosion Litigation Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA) and that those operations caused substantial damage to the coastal waters of Louisiana and nearby lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected areas. There are more than 40 of these cases pending in Louisiana against oil and gas companies, one of which is against TGP and one of which is against SNG, both described further below. On November 8, 2013, the Parish of Plaquemines, Louisiana and others filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. The case has been effectively stayed pending the resolution of jurisdictional issues in separate, consolidated cases to which TGP is not a party; The Parish of Plaquemines, et al. vs. Chevron USA, Inc. et al. consolidated with The Parish of Cameron, et al. v. BP America Production Company, et al. Those cases were removed to federal court and subsequently remanded to the state district courts for Plaquemines and Cameron Parishes, respectively. On September 27, 2023, the U.S. District Court ordered the case be stayed and administratively closed pending the resolution of jurisdictional issues. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to vigorously defend this case. On March 29, 2019, the City of New Orleans (Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In January 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to which SNG is not a party. On May 3, 2023, the U.S. District Court re-opened the case. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to vigorously defend this case. Hurricane Harvey Emission Event In August 2017, KMLT discovered that three tanks at its Pasadena, Texas Terminal failed during Hurricane Harvey. The tank failures resulted in emissions of products being stored in the tanks. The emissions were properly reported to the Texas Commission on Environmental Quality. On November 15, 2019, the State of Texas filed a petition against KMLT in a state district court in Harris County, Texas alleging that violations of maintenance standards contributed to cause both the tank failures in August 2017, and a subsequent tank failure in 2018. The State seeks monetary penalties and corrective actions by KMLT. The State amended its petition in May 2023; the amended petition also seeks penalties and corrective actions. We intend to vigorously defend this case, and we do not anticipate the cost to resolve this matter including the costs to comply with corrective actions, if any, will have a material impact to our business. General Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of December 31, 2023 and 2022, we have accrued a total reserve for environmental liabilities in the amount of $199 million and $221 million, respectively. In addition, as of December 31, 2023 and 2022, we had receivables of $11 million and $12 million, respectively, recorded for expected cost recoveries that have been deemed probable. Challenge to Federal “Good Neighbor Plan” On July 14, 2023, we filed a Petition for Review against the EPA and others in the U.S. Court of Appeals for the District of Columbia Circuit seeking review of the EPA’s final action promulgating the EPA’s final rule known as the “Good Neighbor Plan” (the Plan). The Plan was published in the Federal Register as a final rule on June 5, 2023. The Plan is a federal implementation plan to address certain interstate transport requirements of the Clean Air Act for the 2015 8-hour Ozone NAAQS. We believe that the Plan is deeply flawed and that numerous and substantial bases for challenging the Plan exist. If the Plan were fully implemented, its emission standards would require installation of more stringent air pollution controls on hundreds of existing internal combustion engines used by our Natural Gas Pipelines business segment. On July 27, 2023, we filed a Motion to Stay the Plan Pending Review, and on September 25, 2023, the U.S. Court of Appeals denied the Motion. On October 13, 2023, we filed an Emergency Application for Stay of Final Agency Action in the United States Supreme Court. On December 20, 2023, the Supreme Court issued an order deferring consideration of the Emergency Application for Stay pending oral argument which is scheduled to take place February 21, 2024. On July 31, 2023 and September 29, 2023, the EPA published interim final rules entitled, respectively, “Federal ‘Good Neighbor Plan’ for the 2015 Ozone NAAQS; Response to Judicial Stays of SIP Disapproval Action for Certain States” and “Federal ‘Good Neighbor Plan’ for the 2015 Ozone NAAQS; Response to Additional Judicial Stays of SIP Disapproval Action for Certain States.” We filed petitions for review against the EPA and others in the U.S. Court of Appeals for the District of Columbia seeking review of the interim final rule and the second interim final rule on September 29, 2023 and November 17, 2023, respectively. If the Plan were to remain in effect in its current form (including full compliance by its compliance deadline, and assuming failure of all pending challenges to state implementation plan disapprovals and no successful challenge to the Plan), we anticipate that it would have a material impact on us. However, impacts of the Plan are difficult to predict, given the extensive pending litigation. We would seek to mitigate the impacts, and to recover expenditures through adjustments to our rates on our regulated assets where available.

Recent Accounting Pronoucements

Recent Accounting Pronoucements (Notes)	12 Months Ended
Recent Accounting Pronoucements (Notes)	Dec. 31, 2023
Accounting Standards Update and Change in Accounting Principle [Abstract]
Recent Accounting Pronouncements	19. Recent Accounting Pronouncements Accounting Standards Updates Reference Rate Reform (Topic 848) On March 12, 2020, the FASB issued ASU No. 2020-04, “ Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. ” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the SOFR. Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met. On January 7, 2021, the FASB issued ASU No. 2021-01, “ Reference Rate Reform (Topic 848): Scope. ” This ASU clarifies that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price alignment (the “Discounting Transition”) are in the scope of Topic 848 and therefore qualify for the available temporary optional expedients and exceptions. As such, entities that employ derivatives that are the designated hedged item in a hedge relationship where perfect effectiveness is assumed can continue to apply hedge accounting without de-designating the hedging relationship to the extent such derivatives are impacted by the Discounting Transition. On December 21, 2022, the FASB issued ASU No. 2022-06, “ Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848. ” This ASU defers the sunset date of Topic 848 from December 31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the optional expedients and exceptions in Topic 848. The guidance was effective upon issuance. We amended certain of our existing fixed-to-variable interest rate swap agreements, which were designated as fair value hedges, to transition the variable leg of such agreements from LIBOR to SOFR. Concurrent with these amendments, we elected certain of the optional expedients provided in Topic 848 which allow us to maintain our prior designation of fair value hedge accounting to these agreements. As of December 31, 2023, we no longer have any such agreements outstanding that include a LIBOR reference rate. See Note 14 “ Risk Management— Interest Rate Risk Management ” for more information on our interest rate risk management activities. ASU No. 2023-07 On November 27, 2023, the FASB issued ASU No. 2023-07, “ Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures .” This ASU amends reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption of the ASU is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s annual and interim disclosures. ASU No. 2023-09 On December 14, 2023, the FASB issued ASU No. 2023-09, “ Income Taxes (Topic 740): Improvements to Income Tax Disclosures .” This ASU improves the transparency of income tax disclosures by requiring (i) consistent categories and greater disaggregation of information in the rate reconciliation and (ii) income taxes paid disaggregated by jurisdiction. This ASU will be effective for annual periods beginning after December 15, 2024, and early adoption is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s annual disclosures.

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 Parent	$ 2,391	$ 2,548	$ 1,784

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

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2023
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.
Use of Estimates	Use of Estimates Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including those related to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.
Cash Equivalents and Restricted Deposits	Cash Equivalents and Restricted Deposits We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less. Amounts included in the restricted deposits in the accompanying consolidated financial statements represent a combination of restricted cash amounts required to be set aside by regulatory agencies to cover obligations for our captive insurance subsidiary, cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions and escrow deposits.
Allowance for Credit Losses	Allowance for Credit Losses We evaluate our financial assets measured at amortized cost and off-balance sheet credit exposures for expected credit losses over the contractual term of the asset or exposure. We consider available information relevant to assessing the collectability of cash flows including the expected risk of credit loss even if that risk is remote. We measure expected credit losses on a collective (pool) basis when similar risk characteristics exist, and we reflect the expected credit losses on the amortized cost basis of the financial asset as of the reporting date. Our financial instruments primarily consist of our accounts receivable from customers, notes receivable from affiliates and contingent liabilities such as proportional guarantees of debt obligations of an equity investee. We utilized historical analysis of credit losses experienced over the previous five years along with current conditions and reasonable and supportable forecasts of future conditions in our evaluation of collectability of our financial assets.
Inventories	Inventories Our inventories consist of materials and supplies and products such as natural gas, NGL, crude oil, condensate, refined petroleum products and transmix. We report products inventory at the lower of weighted-average cost or net realizable value. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.
Property, Plant and Equipment, net	Property, Plant and Equipment, net Capitalization, Depreciation and Depletion and Disposals We report property, plant and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in the period incurred. The following table summarizes our significant policies related to our property, plant and equipment. The application of these policies can involve significant estimates. Asset Accounting Area Policy Straight-line assets Depreciation rates • Depreciable lives are based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets. Gains and losses • A gain or loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sale proceeds received or when held for sale, the market value of the asset. • A gain on an asset disposal is recognized in income in the period that the sale is closed. • A loss is recognized when the asset is sold or when classified as held for sale. • Gains and losses are recorded in operating costs, expenses and other. Composite assets Depreciation rates • A single depreciation rate is applied to the total cost of a functional group of assets that have similar economic characteristics until the net book value of the composite group equals the salvage value. • Interstate natural gas FERC-regulated entities use the depreciation rates approved by the FERC. • A depreciation rate for other composite assets is based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets. Gains and losses • Gains and losses are credited or charged to accumulated depreciation, net of salvage and cost of removal. • Gains and losses on FERC-approved operating unit sales and land sales are recorded in operating costs, expenses and other. Oil and gas producing activities(a) Successful efforts method of accounting • Costs that are incurred to acquire leasehold and subsequent development costs are capitalized. • Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. • Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. • The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. • Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset. Enhanced recovery techniques • In some cases, the cost of the CO 2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. • The cost of CO 2 associated with pressure maintenance operations for reservoir management is expensed when it is injected. • When CO 2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. • Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. (a) Gains and losses associated with assets in our oil and gas producing activities have a similar treatment as with that associated with our straight-line assets. Circumstances may develop which cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.
Asset Retirement Obligations	Asset Retirement Obligations We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. The majority of our asset retirement obligations are associated with our CO 2 business where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors, but we also have obligations for certain gathering and long-haul pipelines and certain processing plants. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. The fair value estimates are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include estimates and assumptions related to timing of settlement and retirement costs, which we base on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted to reflect the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service. Our estimates of retirement costs could change as a result of changes in cost estimates and/or timing of the obligation. The following table summarizes changes in the asset retirement obligations included in our accompanying consolidated balance sheets: December 31, 2023 2022 (In millions) Balance at beginning of period $ 204 $ 196 Accretion expense 12 12 New obligations 22 2 Settlements (7) (6) Balance at end of period(a) $ 231 $ 204 (a) Balances at both December 31, 2023 and 2022 include For certain assets, we currently cannot reasonably estimate the fair value of the asset retirement obligations because the associated assets have indeterminate lives. These assets include certain pipelines, processing plants and distribution facilities, and liquids and bulk terminal facilities. Based on the widespread use of hydrocarbons domestically and for international export, management expects supply and demand to exist for the foreseeable future. Therefore, the remaining useful lives of these assets are indeterminate due to prolonged expected demand. Additionally, these assets could also benefit from potential future conversion opportunities. For example, certain assets could be converted to transport, handle or store products other than traditional hydrocarbons. Under our integrity program, individual asset parts are replaced regularly. Although some of the individual asset parts may be replaced, the assets themselves may remain intact indefinitely. For these assets, an asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.
Long-lived Asset Impairments	Long-lived Asset Impairments We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable. In addition to our annual goodwill impairment test discussed further below, to the extent triggering events exist, we complete a review of the carrying value of our long-lived assets, including property, plant and equipment as well as other intangibles, and record, as applicable, the appropriate impairments using a two-step approach. To determine if a long-lived asset is recoverable, we compare the asset’s estimated undiscounted cash flows to its carrying value (step 1). Because the impairment test for long-lived assets held in use is based on estimated undiscounted cash flows, there may be instances where an asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset or asset group. If the carrying value of a long-lived asset or asset group is in excess of estimated undiscounted cash flows, we typically use discounted cash flow analyses to calculate the fair value of the long-lived asset to determine if an impairment is required and the amount of the impairment losses to be recognized (step 2). We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on estimated future oil and gas production volumes. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on estimated future oil and gas production volumes. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment. Refer to Note 4 for further information.
Equity Method of Accounting and Basis Difference	Equity Method of Accounting and Basis Differences We use the equity method of accounting for investments which we do not control, but for which we have the ability to exercise significant influence. The carrying values of these investments are impacted by our share of investee income or loss, distributions, amortization or accretion of basis differences and other-than-temporary impairments. The difference between the carrying value of an investment and our share of the investment’s underlying equity in net assets is referred to as a basis difference. If the basis difference is assigned to depreciable or amortizable assets and liabilities, the basis difference is amortized or accreted as part of our share of investee earnings. To the extent that the basis difference relates to goodwill, referred to as equity method goodwill, the amount is not amortized. We evaluate our equity method investments for other-than-temporary impairment. When an other-than-temporary impairment is recognized, the loss is recorded as a reduction in equity earnings.
Goodwill	Goodwill Goodwill is the cost of an acquisition of a business in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually and in interim periods if indicators of impairment exist. This test requires us to assign goodwill to an appropriate reporting unit and compare the fair value of a reporting unit to its carrying value. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value an impairment is measured and recorded at the amount by which the reporting unit’s carrying value exceeds its fair value. We evaluate goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. For purposes of our May 31, 2023 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO 2 ; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (vi) Terminals; and (vii) Energy Transition Ventures. Generally, the evaluation of goodwill for impairment involves a quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test. A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit. Refer to Note 8 for further information.
Other Intangibles	Other Intangibles Excluding goodwill, our other intangible assets include customer contracts and other relationships and agreements. Our intangible assets primarily relate to customer contracts or other relationships for the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline, and other refined petroleum products, petroleum coke, metals and ores, the gathering of natural gas and the production and supply of RNG. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate. We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. Among the factors we weigh, depending on the nature of the asset, are the effects of obsolescence, new technology, and competition.
Revenue Recognition	Revenue Recognition The majority of our revenues are accounted for under Topic 606, Revenue from Contracts with Customers ; however, to a limited extent, some revenues are accounted for under other guidance such as Topic 842, Leases or Topic 815, Derivatives and Hedging Activities . Revenue from Contracts with Customers We review our contracts with customers using the following steps to recognize revenue based on the transfer of goods or services to customers and in amounts that reflect the consideration the company expects to receive for those goods or services. The steps include: (i) identify the contract; (ii) identify the performance obligations of the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and then (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions. Our customer sales contracts primarily include sales of natural gas, NGL, crude oil, CO 2 and transmix, as described below. Generally, for the majority of these contracts (i) each unit (Bcf, gallon, barrel, etc.) of commodity is a separate performance obligation, as our promise is to sell multiple distinct units of commodity at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied. Our customer services contracts are primarily for transportation service, storage service, gathering and processing service, and terminaling, as described below. Generally, for the majority of these contracts (i) our promise is to transfer (or stand ready to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights). Firm Services Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows: • Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is satisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the beginning of each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., we expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation) continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time. • Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future period and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to deliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e., breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods. Non-Firm Services Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period). Contract Balances Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. We recognize contract assets in those instances where billing occurs subsequent to revenue recognition, and our right to invoice the customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of the contract for which we record revenue ratably per unit over the life of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognize as revenue on a straight-line basis over the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future period, which we subsequently recognize as revenue when the customer makes up the volumes or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed rates per volume that decrease over the life of the contract where we apply revenue levelization for amounts received for our future performance obligations. We reassess amounts recorded as contract assets or liabilities upon contract modification. Refer to Note 15 for further information.
Costs of Sales	Costs of Sales Costs of sales primarily includes the cost to purchase energy commodities sold, including natural gas, crude oil, NGL and other refined petroleum products, adjusted for the effects of our energy commodity hedging activities, as applicable. Costs of our crude oil, gas and CO 2 producing activities, such as those in our CO 2 business segment, are not accounted for as costs of sales.
Operations and Maintenance	Operations and Maintenance Operations and maintenance includes costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our crude oil, gas and CO 2 producing activities included within operations and maintenance totaled $393 million, $367 million and $180 million for the years ended December 31, 2023, 2022 and 2021, respectively.
Environmental Matters	Environmental Matters We capitalize certain environmental expenditures required to obtain rights-of-way, regulatory approvals or permitting as part of the construction of facilities we use in our business operations. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs, such as after the completion of a feasibility study or commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities assumed in a business combination. We routinely conduct reviews of potential environmental issues and claims that assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims we may have against others. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs.
Leases: Lessee	Leases We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one Our operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, are reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842 , such as land easements, are reassessed when the agreements are modified. Refer to Note 17 for further information.
Share-based Compensation	Share-based Compensation We recognize compensation expense ratably over the vesting period of the restricted stock award based on the grant-date fair value, which is determined based on the market price of our Class P common stock on the grant date, less estimated forfeitures. Forfeiture rates are estimated based on historical forfeitures under our restricted stock award plans. Upon vesting, the restricted stock award will be paid in shares of our Class P common stock.
Pensions and Other Postretirement Benefits	Pensions and Other Postretirement Benefits We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheets. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—net of income taxes in “Accumulated other comprehensive loss,” with the proportionate share associated with less than wholly owned consolidated subsidiaries allocated and included within “Noncontrolling interests,” or as a regulatory asset or liability for certain of our regulated operations, until they are amortized as a component of benefit expense.
Deferred Financing Costs	Deferred Financing Costs We capitalize financing costs incurred with new borrowings and amortize the costs over the contractual term of the related obligations.
Redeemable Noncontrolling Interest and Noncontrolling Interests	Redeemable Noncontrolling Interest Through December 14, 2021, we had a redeemable noncontrolling interest which represented the interest in one of our consolidated subsidiaries, not owned by us, and which in certain limited circumstances, the partner had the right to relinquish its interest in the subsidiary. Distributions paid to the partner prior to that date were recorded as a reduction to the redeemable noncontrolling interest balance and included in “Distributions to investment partner” in our accompanying consolidated statement of cash flows. On December 14, 2021, the ownership agreement was modified such that the noncontrolling interest was no longer contingently redeemable, and the balance was reclassified to “Noncontrolling Interests.” Net income attributable to redeemable noncontrolling interest was $58 million for the year ended December 31, 2021 and is included in “Net Income Attributable to Noncontrolling Interests” in our accompanying consolidated statement of income. Noncontrolling Interests Noncontrolling interests represents the interests in our consolidated subsidiaries that are not owned by us. In our accompanying consolidated statements of income, the noncontrolling interest in the net income of our less than wholly owned consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net Income Attributable to Noncontrolling Interests.” In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”
Income Taxes	Income Taxes Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective tax rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. Income tax effects are released from accumulated other comprehensive loss to retained earnings, when applicable, on an individual item basis as those items are reclassified into income. In determining the deferred income tax asset and liability balances attributable to our investments, we apply an accounting policy that looks through our investments. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments, including KMI’s investment in its wholly-owned subsidiary, KMP.
Risk Management Activities	Risk Management Activities We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of commodities including crude oil, natural gas, and NGL. In addition, we enter into interest rate swap agreements for the purpose of managing our interest rate exposure associated with our debt obligations. We also enter into cross-currency swap agreements to manage our foreign currency risk associated with certain debt obligations. We measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability. For certain physical forward commodity derivatives contracts, we apply the normal purchase/normal sale exception, whereby the revenues and expenses associated with such transactions are recognized during the period when the commodities are physically delivered or received. For qualifying accounting hedges, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. When we designate a derivative contract as a cash flow accounting hedge, the entire change in fair value of the derivative that is included in the assessment of hedge effectiveness is deferred in “Accumulated other comprehensive loss” and reclassified into earnings in the period in which the hedged item affects earnings. When we designate a derivative contract as a fair value accounting hedge, the change in fair value of the hedged item is recorded as an adjustment to the carrying value of the hedged item and recognized currently in earnings in the same line item that the change in fair value of the derivative is recognized currently in earnings. Therefore, any difference between the changes in fair values of the item being hedged and the derivative contract results in a gain or loss from the hedging relationship recognized currently in earnings. For derivative instruments that are not designated as accounting hedges, or for which we have not elected the normal purchase/normal sales exception, changes in fair value are recognized currently in earnings. Unrealized gains and losses associated with our derivative activities that affect income are reflected as “Change in fair market value of derivative contracts” within our accompanying consolidated statement of cash flows as a noncash add back to net income to arrive at cash flows from our derivative activities for the period. Net changes in our interest receivable and payable balances that represent accruals and periodic settlements of interest on our interest rate swaps are included within “Accrued interest, net of interest rate swaps” on our accompanying consolidated statement of cash flows.
Fair Value	Fair Value The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. We assign each fair value measurement to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. Recognized valuation techniques utilize inputs such as contractual prices, quoted market prices or rates, and discount factors. These inputs may be either readily observable or corroborated by market data.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or returned to customers through the ratemaking process. In instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount. We include the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets.
Earnings per Share	Earnings per Share We calculate earnings per share using the two-class method. Earnings were allocated to Class P common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.

Acquisitions and Divestitures_2

Acquisitions and Divestitures (Policies)	12 Months Ended
Acquisitions and Divestitures (Policies)	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Business Combinations	For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of these items requires management’s judgment and the utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions.

Income Taxes (Policies)

Income Taxes (Policies)	12 Months Ended
Income Taxes (Policies)	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits	Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
Summary of Significant Accounting Policies (Tables)	Dec. 31, 2023
Accounting Policies [Abstract]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	The following table summarizes changes in the asset retirement obligations included in our accompanying consolidated balance sheets: December 31, 2023 2022 (In millions) Balance at beginning of period $ 204 $ 196 Accretion expense 12 12 New obligations 22 2 Settlements (7) (6) Balance at end of period(a) $ 231 $ 204 (a) Balances at both December 31, 2023 and 2022 include
Schedule of Other Intangibles	The following tables summarize our other intangible assets as of December 31, 2023 and 2022 and our amortization expense for the years ended December 31, 2023, 2022 and 2021: Weighted Average Amortization Period December 31, 2023 2022 (Years) (In millions) Gross 11.3 $ 3,543 $ 3,382 Accumulated amortization (1,586) (1,573) Net carrying amount $ 1,957 $ 1,809 December 31, 2023 2022 2021 (In millions) Amortization expense $ 202 $ 253 $ 237
Schedule of Estimated Amortization Expense for Other Intangibles	Our estimated amortization expense for our intangible assets for each of the next five fiscal years is: 2024 2025 2026 2027 2028 (In millions) Estimated amortization expenses $ 198 $ 193 $ 191 $ 191 $ 190
Schedule of Regulatory Assets and Liabilities Table [Table Text Block]	The following table summarizes our regulatory asset and liability balances as of December 31, 2023 and 2022: December 31, 2023 2022 (In millions) Current regulatory assets $ 26 $ 73 Non-current regulatory assets 214 183 Total regulatory assets(a) $ 240 $ 256 Current regulatory liabilities $ 45 $ 50 Non-current regulatory liabilities 188 175 Total regulatory liabilities(b) $ 233 $ 225 (a) Regulatory assets as of December 31, 2023 include (i) $100 million of unamortized losses on disposal of assets; (ii) $43 million income tax gross up on equity AFUDC; and (iii) $97 million of other assets, including amounts related to fuel tracker arrangements. Approximately $138 million of the regulatory assets, with a weighted average remaining recovery period of 10 years, are recoverable without earning a return, including the income tax gross up on equity AFUDC for which there is an offsetting deferred income tax balance for FERC rate base purposes; therefore, it does not earn a return. (b) Regulatory liabilities as of December 31, 2023 are comprised of customer prepayments to be credited to shippers or other over-collections that are expected to be returned to shippers or netted against under-collections over time. Approximately $104 million of the $188 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 13 years, while the remaining $84 million is not subject to a defined period.
Schedule of Earnings Per Share, Basic and Diluted	The following table sets forth the allocation of net income available to shareholders of Class P common stock and participating securities: Year Ended December 31, 2023 2022 2021 (In millions, except per share amounts) Net Income Available to Stockholders $ 2,391 $ 2,548 $ 1,784 Participating securities: Less: Net Income Allocated to Restricted stock awards(a) (14) (13) (14) Net Income Allocated to Common Stockholders $ 2,377 $ 2,535 $ 1,770 Basic Weighted Average Shares Outstanding 2,234 2,258 2,266 Basic Earnings Per Share $ 1.06 $ 1.12 $ 0.78 (a) As of December 31, 2023, there were approximately 13 million restricted stock awards outstanding.
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share. As we have no other common stock equivalents, our diluted earnings per share are the same as our basic earnings per share for all periods presented. Year Ended December 31, 2023 2022 2021 (In millions on a weighted average basis) Unvested restricted stock awards 13 13 13 Convertible trust preferred securities 3 3 3

Acquisitions and Divestitures_3

Acquisitions and Divestitures (Tables)	12 Months Ended
Acquisitions and Divestitures (Tables)	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	Our allocation of the purchase price for acquisitions completed during the years ended December 31, 2023, 2022 and 2021 are detailed below: Assignment of Purchase Price Ref Acquisition Purchase price Current assets Property, plant & equipment Other long-term assets Current liabilities Long-term liabilities Non-controlling interest Resulting goodwill (In millions) (1) STX Midstream(a) $ 1,831 $ 41 $ 1,199 $ 552 $ (11) $ (2) $ (104) $ 156 (2) Diamond M 13 — 25 — — (12) — — (3) North American Natural Resources 132 2 5 64 — — — 61 (4) Mas Ranger, LLC 358 9 31 320 (2) — — — (5) Kinetrex Energy 318 18 49 272 (6) (68) — 53 (6) Stagecoach 1,258 53 1,187 24 (6) — — — (a) The purchase price allocation for the STX Midstream Acquisition is preliminary.
Schedule of Variable Interest Entities	The following table shows the carrying amount and classification of ELC’s assets and liabilities in our consolidated balance sheets: December 31, 2023 2022 (In millions) Assets Current assets $ 46 $ 34 Property, plant and equipment, net 1,162 1,197 Deferred charges and other assets 5 6 Liabilities Current liabilities $ 15 $ 15 Other long-term liabilities and deferred credits 25 5

Gains and Losses on Divestitu_2

Gains and Losses on Divestitures, Impairments and Other Write-downs (Tables)	12 Months Ended
	Dec. 31, 2023
Impairments [Abstract]
Impairment of Goodwill, Long-lived assets and equity investments [Table Text Block]	We recognized the following non-cash pre-tax losses (gains) on divestitures, impairments or other write-downs on assets and equity investments during the years ended December 31, 2023, 2022, and 2021: Year Ended December 31, 2023 2022 2021 (In millions) Natural Gas Pipelines Impairments of long-lived assets(a) $ — $ — $ 1,600 Gain on sale of interest in NGPL Holdings(b) — — (206) Loss on write-down of related party note receivable(c) — — 117 Gains on divestitures of long-lived assets (10) (10) (1) Products Pipelines Impairment of equity investment(d) 67 — — Gain on divestiture of long-lived asset — (12) — Terminals Impairments of long-lived assets — — 34 (Gains) losses on divestitures of long-lived assets (1) (9) 2 CO 2 Gains on divestitures of long-lived assets (1) (1) (8) Other gains on divestitures of long-lived assets (3) — (3) Pre-tax losses (gains) on divestitures, impairments and other write-downs, net $ 52 $ (32) $ 1,535 (a) 2021 amount represents non-cash impairments associated with our South Texas gathering and processing assets. (b) See Note 3. (c) See “— Investment in Ruby ” below for a further discussion. (d) See “— Investments ” below for a further discussion.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of Income Before Income Taxes	The components of “Income Before Income Taxes” are as follows: Year Ended December 31, 2023 2022 2021 (In millions) U.S. $ 3,192 $ 3,318 $ 2,217 Foreign 9 17 2 Total Income Before Income Taxes $ 3,201 $ 3,335 $ 2,219
Schedule of Components of Income Tax Provision	Components of the income tax provision applicable for federal, foreign and state taxes are as follows: Year Ended December 31, 2023 2022 2021 (In millions) Current tax expense State $ 5 $ 14 $ 11 Foreign — 4 3 Total 5 18 14 Deferred tax expense Federal 619 642 334 State 91 50 21 Total 710 692 355 Total tax provision $ 715 $ 710 $ 369
Schedule of Effective Income Tax Rate Reconciliation	The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows: Year Ended December 31, 2023 2022 2021 (In millions, except percentages) Federal income tax $ 672 21.0 % $ 700 21.0 % $ 466 21.0 % Increase (decrease) as a result of: State income tax, net of federal benefit 64 2.0 % 69 2.0 % 50 2.2 % Dividend received deduction (34) (1.1) % (36) (1.1) % (46) (2.1) % Release of valuation allowance — — % — — % (38) (1.7) % General business credit (1) — % — — % (36) (1.6) % Other 14 0.4 % (23) (0.7) % (27) (1.2) % Total $ 715 22.3 % $ 710 21.2 % $ 369 16.6 %
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities result from the following: December 31, 2023 2022 (In millions) Deferred tax assets Employee benefits $ 114 $ 116 Net operating loss carryforwards 2,024 2,007 Tax credit carryforwards 300 303 Interest expense limitation 266 82 Other 181 192 Valuation allowances (77) (79) Total deferred tax assets 2,808 2,621 Deferred tax liabilities Property, plant and equipment 215 163 Investments(a) 3,951 3,056 Other 30 25 Total deferred tax liabilities 4,196 3,244 Net deferred tax liability $ (1,388) $ (623) (a) Amounts as of December 31, 2023 and 2022 are primarily associated with KMI’s investment in KMP.
Summary of Valuation Allowance	A reconciliation of our valuation allowances for the year ended December 31, 2023 is as follows: Year Ended December 31, 2023 (In millions) Balance at beginning of period $ 79 Statute expirations for state NOL and foreign tax credits (5) Currency fluctuation 3 Balance at end of period $ 77
Summary of Operating Loss Carryforwards	The following table provides details related to our deferred tax assets and valuation allowances as of December 31, 2023: Unused Amount Deferred Tax Asset Valuation Allowance Expiration Period (In millions) Net Operating Loss U.S. federal net operating loss $ 6,565 $ 1,379 $ — Indefinite U.S. federal net operating loss 1,716 360 — 2035 - 2037 State losses 5,293 254 (46) 2024 - 2043 Foreign losses 90 31 (31) Indefinite Tax Credits General business credits 300 300 — 2036 - 2042
Schedule of Unrecognized Tax Benefits Roll Forward	A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows: Year Ended December 31, 2023 2022 2021 (In millions) Balance at beginning of period $ 23 $ 21 $ 18 Reductions based on statute expirations (5) (5) — Audit settlement (1) — — Additions to state reserves for prior years 1 7 3 Balance at end of period $ 18 $ 23 $ 21 Amounts which, if recognized, would affect the effective tax rate $ 18
Summary of Income Tax Examinations	The following table summarizes information of our open tax years: Jurisdiction Open Tax Year U.S. 2019 - 2023 Various states 2012 - 2023 Foreign 2008 - 2023

Property, Plant and Equipment_2

Property, Plant and Equipment, net (Tables)	12 Months Ended
Property, Plant and Equipment, net (Tables)	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	As of December 31, 2023 and 2022, our property, plant and equipment, net consisted of the following: Straight-Line Estimated Useful Life Composite December 31, 2023 2022 (Years) (%) (In millions) Interstate Natural Gas FERC-Regulated Pipelines (Natural gas) 0.80-6.67 $ 12,019 $ 11,793 Equipment (Natural gas) 0.80-6.67 9,190 8,839 Other(a) 0.00-25 823 833 Accumulated depreciation, depletion and amortization (10,301) (9,883) Depreciable assets 11,731 11,582 Land and land rights-of-way(b) 399 388 Construction work in process 394 258 Total interstate natural gas FERC-regulated 12,524 12,228 Other Pipelines (Natural gas, liquids, crude oil and CO 2 ) 5-40 0.09-33.33 9,631 8,329 Equipment (Natural gas, liquids, crude oil, CO 2 and terminals) 5-40 0.09-33.33 19,974 18,645 Other(a) 3-10 0.00-33.33 4,773 4,791 Accumulated depreciation, depletion and amortization (11,774) (10,529) Depreciable assets 22,604 21,236 Land and land rights-of-way(c) 1,518 1,350 Construction work in process 651 785 Total other 24,773 23,371 Property, plant and equipment, net $ 37,297 $ 35,599 (a) Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and miscellaneous property, plant and equipment. (b) Balances as of both December 31, 2023 and 2022 include land rights-of-way of $346 million which are depreciable. (c)

Investments (Tables)

Investments (Tables)	12 Months Ended
Investments (Tables)	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Method Investments [Table Text Block]	Our investments primarily consist of equity investments where we hold significant influence over investee actions and for which we apply the equity method of accounting. The following table provides details on our investments as of December 31, 2023 and 2022 and our earnings (loss) from these respective investments for the years ended December 31, 2023, 2022 and 2021: Ownership Interest Equity Investments Earnings (Loss) from December 31, December 31, Year Ended December 31, 2023 2023 2022 2023 2022 2021 (In millions) Citrus Corporation 50% $ 1,789 $ 1,781 $ 143 $ 145 $ 151 SNG 50% 1,668 1,669 140 145 128 PHP 27.74% 763 666 70 70 63 NGPL Holdings(a) 37.5% 623 610 121 111 94 Gulf Coast Express Pipeline LLC 34% 566 597 93 91 86 Products (SE) Pipe Line Corporation 51.17% 369 348 65 51 48 MEP 50% 342 371 87 10 (17) Utopia Holding LLC 50% 322 325 22 20 20 Gulf LNG Holdings Group, LLC 50% 275 311 25 24 22 EagleHawk 25% 273 273 18 13 8 Dos Caminos, LLC 50% 192 — — — — Red Cedar Gathering Company 49% 155 155 15 17 10 Watco Companies, LLC (b) 84 79 10 9 9 Cortez Pipeline Company 52.98% 30 31 25 30 29 Double Eagle(c) 50% 14 90 (42) 18 9 Ruby(d) — — — — (116) All others 409 347 46 49 47 Total investments $ 7,874 $ 7,653 $ 838 $ 803 $ 591 Amortization of excess cost $ (66) $ (75) $ (78) (a) Our investment in NPGL Holdings includes a related party promissory note receivable from NGPL Holdings with quarterly interest payments at 6.75%. As of December 31, 2023, we and Arclight each hold a 37.5% interest and Brookfield holds a 25% interest in NGPL Holdings. The outstanding principal amount of our related party promissory note receivable at both December 31, 2023 and 2022 was $375 million. For the years ended December 31, 2023, 2022 and 2021, we recognized $25 million, $25 million and $27 million, respectively, of interest within “Earnings from equity investments” on our accompanying consolidated statements of income. (b) We hold a preferred equity investment in Watco Companies, LLC (Watco). We own 50,000 Class B preferred shares and pursuant to the terms of the investment, receive priority, cumulative cash and stock distributions from the preferred shares at a rate of 3.00% per quarter. We do not hold any voting powers, but the class does provide us certain approval rights, including the right to appoint one of the members to Watco’s board of managers. (c) Loss for the year ended December 31, 2023 includes $67 million of our share of a non-cash impairment charge (pre-tax). For further information, see Note 4 “Losses and Gains on Divestitures, Impairments and Other Write-downs —Investments. ” (d) As of January 13, 2023, we no longer own an interest in Ruby. The loss from our investment in Ruby for the year ended December 31, 2021 includes a non-cash impairment charge of $117 million related to a write-down of our subordinated note receivable from Ruby driven by the impairment by Ruby of its assets. For further information regarding our investment in Ruby, see Note 4 “Losses and Gains on Divestitures, Impairments and Other Write-downs —Investment in Ruby. ” Summarized combined financial information for our significant equity investments (listed or described above) is reported below (amounts represent 100% of investee financial information): Year Ended December 31, Income Statement 2023 2022 2021(a) (In millions) Revenues $ 5,981 $ 5,953 $ 5,521 Costs and expenses 4,149 4,193 6,137 Net income (loss) $ 1,832 $ 1,760 $ (616) December 31, Balance Sheet 2023 2022 (In millions) Current assets $ 1,844 $ 1,461 Non-current assets 23,193 23,360 Current liabilities 1,534 1,617 Non-current liabilities 10,102 10,206 Partners’/owners’ equity 13,401 12,998 (a)

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
Goodwill (Tables)	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	Changes in the amounts of our goodwill for each of the years ended December 31, 2023 and 2022 are summarized by reporting unit as follows: Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated CO 2 Products Pipelines Products Pipelines Terminals Terminals Energy Transition Ventures Total (In millions) Gross goodwill $ 15,892 $ 4,940 $ 1,528 $ 2,575 $ 221 $ 1,481 $ 63 $ 26,700 Accumulated impairment losses (1,643) (2,597) (600) (1,197) (70) (679) — (6,786) December 31, 2021 14,249 2,343 928 1,378 151 802 63 19,914 Acquisitions(a) — — — — — — 51 51 December 31, 2022 14,249 2,343 928 1,378 151 802 114 19,965 Acquisition of STX Midstream — 156 — — — — — 156 December 31, 2023 14,249 2,499 928 1,378 151 802 114 20,121 Gross goodwill 15,892 5,096 1,528 2,575 221 1,481 114 26,907 Accumulated impairment losses (1,643) (2,597) (600) (1,197) (70) (679) — (6,786) December 31, 2023 $ 14,249 $ 2,499 $ 928 $ 1,378 $ 151 $ 802 $ 114 $ 20,121 (a) Includes goodwill arising from our acquisition of NANR and a $10 million purchase price adjustment related to our acquisition of Kinetrex in 2021 that was attributed to long-term deferred tax liabilities.

Debt (Tables)

Debt (Tables)	12 Months Ended
Debt (Tables)	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of Debt	The following table provides detail on the principal amount of our outstanding debt balances: December 31, 2023 2022 (In millions) Credit facility and commercial paper borrowings(a) $ 1,989 $ — Corporate senior notes(b) 3.15%, due January 2023 — 1,000 Floating rate, due January 2023(c) — 250 3.45%, due February 2023 — 625 3.50%, due September 2023 — 600 5.625%, due November 2023 — 750 4.15%, due February 2024 650 650 4.30%, due May 2024 600 600 4.25%, due September 2024 650 650 4.30%, due June 2025 1,500 1,500 1.75%, due November 2026 500 500 6.70%, due February 2027 7 7 2.25%, due March 2027(d) 552 535 6.67%, due November 2027 7 7 4.30%, due March 2028 1,250 1,250 7.25%, due March 2028 32 32 6.95%, due June 2028 31 31 8.05%, due October 2030 234 234 2.00%, due February 2031 750 750 7.40%, due March 2031 300 300 7.80%, due August 2031 537 537 7.75%, due January 2032 1,005 1,005 7.75%, due March 2032 300 300 4.80%, due February 2033 750 750 5.20%, due June 2033 1,500 — 7.30%, due August 2033 500 500 5.30%, due December 2034 750 750 5.80%, due March 2035 500 500 7.75%, due October 2035 1 1 6.40%, due January 2036 36 36 6.50%, due February 2037 400 400 7.42%, due February 2037 47 47 6.95%, due January 2038 1,175 1,175 6.50%, due September 2039 600 600 6.55%, due September 2040 400 400 7.50%, due November 2040 375 375 6.375%, due March 2041 600 600 5.625%, due September 2041 375 375 5.00%, due August 2042 625 625 4.70%, due November 2042 475 475 5.00%, due March 2043 700 700 5.50%, due March 2044 750 750 5.40%, due September 2044 550 550 5.55%, due June 2045 1,750 1,750 5.05%, due February 2046 800 800 5.20%, due March 2048 750 750 3.25%, due August 2050 500 500 3.60%, due February 2051 1,050 1,050 5.45%, due January 2052 750 750 7.45%, due March 2098 26 26 TGP senior notes(b) 7.00%, due March 2027 300 300 7.00%, due October 2028 400 400 2.90%, due March 2030 1,000 1,000 December 31, 2023 2022 8.375%, due June 2032 240 240 7.625%, due April 2037 300 300 EPNG senior notes(b) 7.50%, due November 2026 200 200 3.50%, due February 2032 300 300 8.375%, due June 2032 300 300 CIG senior notes(b) 4.15%, due August 2026 375 375 6.85%, due June 2037 100 100 EPC Building, LLC, promissory note, 3.967%, due January 2022 through December 2035 330 348 Trust I Preferred Securities, 4.75%, due March 2028(e) 221 220 Other miscellaneous debt(f) 234 242 Total debt – KMI and Subsidiaries 31,929 31,673 Less: Current portion of debt 4,049 3,385 Total long-term debt – KMI and Subsidiaries(g) $ 27,880 $ 28,288 (a) Weighted average interest rate on borrowings at December 31, 2023 was 5.68%. (b) Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. (c) As of December 31, 2022, we had outstanding an associated floating-to-fixed interest rate swap agreement which was designated as a cash flow hedge. (d) Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2023 exchange rate of 1.1039 U.S. dollars per Euro and at the December 31, 2022 exchange rate of 1.0705 U.S. dollars per Euro. As of December 31, 2023 and 2022, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase of $9 million and a decrease of $8 million, respectively. As of December 31, 2023, we had outstanding associated cross-currency swap agreements which are designated as cash flow hedges. (e) Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2023, had 4.4 million of 4.75% trust convertible preferred securities outstanding (referred to as the Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We provide a full and unconditional guarantee of the Trust I Preferred Securities. There are no significant restrictions from these securities on our ability to obtain funds from our subsidiaries by distribution, dividend or loan. The Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75% and carry a liquidation value of $50 per security plus accrued and unpaid distributions. The Trust I Preferred Securities outstanding as of December 31, 2023 are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; and (ii) $25.18 in cash without interest. We have the right to redeem these Trust I Preferred Securities at any time. (f) Includes finance lease obligations with monthly installments. The lease terms expire between 2026 and 2070. (g) Excludes our “Debt fair value adjustments” which, as of December 31, 2023 and 2022, increased our combined debt balances by $187 million and $115 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see “— Debt Fair Value Adjustments ” below.
Schedule of Short-term Debt	The following table details the components of our “Current portion of debt” reported on our consolidated balance sheets: December 31, 2023 2022 (In millions) $3.5 billion credit facility due August 20, 2027 — — $500 million credit facility due November 16, 2023 — — Commercial paper notes 1,989 — Current portion of senior notes 3.15%, due January 2023(a) — 1,000 Floating rate, due January 2023(b) — 250 3.45%, due February 2023 — 625 3.50%, due September 2023 — 600 5.625%, due November 2023 — 750 4.15%, due February 2024(c) 650 — 4.30%, due May 2024 600 — 4.25%, due September 2024 650 — Trust I Preferred Securities, 4.75% due March 2028(d) 111 111 Current portion of other debt 49 49 Total current portion of debt $ 4,049 $ 3,385 (a) On January 17, 2023, we repaid these senior notes using cash on hand and short-term borrowings. (b) These senior notes had an associated floating-to-fixed interest rate swap agreement which was designated as a cash flow hedge. (c) On February 1, 2024, we repaid these senior notes using cash on hand and short-term borrowings. (d) Reflects the portion of cash consideration payable if all the outstanding securities as of the end of the reporting period were converted by the holders.
Schedule of Maturities of Long-term Debt	The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2023, are summarized as follows: Year Total (In millions) 2024 $ 4,049 2025 1,566 2026 1,102 2027 906 2028 1,867 Thereafter 22,439 Total $ 31,929
Schedule of Debt Fair Value Adjustments	The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets: December 31, 2023 2022 (In millions) Purchase accounting debt fair value adjustments $ 430 $ 472 Carrying value adjustment to hedged debt (236) (367) Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a) 185 204 Unamortized debt discounts, net (67) (68) Unamortized debt issuance costs (125) (126) Total debt fair value adjustments $ 187 $ 115 (a) As of December 31, 2023, the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 11 years.
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments	The carrying value and estimated fair value of our outstanding debt balances is disclosed below: December 31, 2023 December 31, 2022 Carrying Estimated Carrying Estimated (In millions) Total debt $ 32,116 $ 31,370 $ 31,788 $ 30,070 (a) Included in the estimated fair value are amounts for our Trust I Preferred Securities of $207 million and $195 million as of December 31, 2023 and 2022, respectively.

Share-based Compensation and _2

Share-based Compensation and Employee Benefits (Tables)	12 Months Ended
Share-based Compensation and Employee Benefits (Tables)	Dec. 31, 2023
Employee Benefit and Share-Based Payment Arrangement, Noncash Expense [Abstract]
Summary of Stock Compensation Plans	Following is a summary of our stock compensation plans: Directors’ Plan Long Term Incentive Plan Participating individuals Eligible non-employee directors Eligible employees Total number of shares of Class P common stock authorized 1,190,000 63,000,000 Vesting period 6 months 1 year to 10 years
Summary of Activity and Related Balances of Restricted Stock Awards	We also have a Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan (Long Term Incentive Plan). The following table sets forth a summary of activity and related balances under our Long Term Incentive Plan: Shares Weighted Average Grant Date Fair Value per Share (In thousands, except per share amounts) Outstanding at December 31, 2022 13,288 $ 16.87 Granted 5,253 17.41 Vested (5,226) 16.09 Forfeited (454) 17.03 Outstanding at December 31, 2023 12,861 $ 17.41
Schedule of Grant Date Fair Value, Awards Vested and Compensation Costs	The following tables set forth additional information related to our Long Term Incentive Plan: Year Ended December 31, 2023 2022 2021 (In millions, except per share amounts) Weighted average grant date fair value per share $ 17.41 $ 17.31 $ 17.44 Intrinsic value of awards vested during the year 93 47 77 Restricted stock awards expense(a) 63 60 59 Restricted stock awards capitalized(a) 10 9 9 (a) We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements. December 31, 2023 Unrecognized restricted stock awards compensation costs, less estimated forfeitures (in millions) $ 117 Weighted average remaining amortization period 2.06 years
Schedule of Defined Benefit Plans Disclosures	Benefit Obligation, Plan Assets and Funded Status . The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 2023 and 2022: Pension Benefits OPEB 2023 2022 2023 2022 (In millions) Change in benefit obligation: Benefit obligation at beginning of period $ 2,077 $ 2,658 $ 195 $ 257 Service cost 55 55 1 1 Interest cost 107 57 10 5 Actuarial loss (gain) 14 (503) (6) (44) Benefits paid (132) (190) (25) (26) Participant contributions — — 1 1 Settlements (219) — — — Other — — 1 1 Benefit obligation at end of period 1,902 2,077 177 195 Change in plan assets: Fair value of plan assets at beginning of period 1,741 2,231 302 382 Actual return on plan assets 122 (350) 44 (63) Employer contributions 50 50 — 7 Participant contributions — — 1 1 Benefits paid (132) (190) (25) (26) Settlements (219) — — — Other — — 1 1 Fair value of plan assets at end of period 1,562 1,741 323 302 Funded status - net (liability) asset at December 31, $ (340) $ (336) $ 146 $ 107 Amounts recognized in the consolidated balance sheets: Non-current benefit asset(a) $ — $ — $ 263 $ 239 Current benefit liability — — (14) (15) Non-current benefit liability (340) (336) (103) (117) Funded status - net (liability) asset at December 31, $ (340) $ (336) $ 146 $ 107 Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets: Unrecognized net actuarial (loss) gain $ (384) $ (455) $ 149 $ 135 Unrecognized prior service (cost) credit — (1) 3 4 Accumulated other comprehensive (loss) income $ (384) $ (456) $ 152 $ 139 Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets: Accumulated benefit obligation $ 1,870 $ 2,047 $ 119 $ 167 Fair value of plan assets 1,562 1,741 2 34 (a) 2023 and 2022 OPEB amounts include $53 million and $45 million, respectively, of non-current benefit assets related to a plan we sponsor which is associated with employee services provided to an unconsolidated joint venture, and for which we have recorded an offsetting related party deferred credit.
Fair Value of Pension and OPEB Assets by Level of Assets	The allowable range for asset allocations in effect for our plans as of December 31, 2023, by asset category, are as follows: Pension Benefits OPEB Cash 0% to 23% Equities 42% to 52% 43% to 71% Fixed income securities 37% to 47% 26% to 50% Real estate 2% to 12% Company securities (KMI Class P common stock and/or debt securities) 0% to 10% Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value by class and categorized by fair value measurement used at December 31, 2023 and 2022: Pension Assets 2023 2022 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Short-term investment funds $ — $ 32 $ 32 $ — $ 27 $ 27 Equities(a) 143 — 143 152 — 152 Fixed income securities — 410 410 — 421 421 Subtotal $ 143 $ 442 585 $ 152 $ 448 600 Measured at NAV Common/collective trusts(b) 976 1,138 Private limited partnerships(c) 1 3 Subtotal 977 1,141 Total plan assets fair value $ 1,562 $ 1,741 (a) Plan assets include $107 and $110 of KMI Class P common stock for 2023 and 2022, respectively. (b) Common/collective trust funds were invested in approximately 64% equities, 23% fixed income securities and 13% real estate in 2023 and 66% equities, 22% fixed income securities and 12% real estate in 2022. (c) Includes assets invested in real estate, venture and buyout funds. OPEB Assets 2023 2022 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Short-term investment funds $ — $ 5 $ 5 $ — $ 3 $ 3 Measured at NAV Common/collective trusts(a) 318 299 Total plan assets fair value $ 323 $ 302 (a)
Schedule of Expected Payment of Future Benefits and Employer Contributions	Employer Contributions and Expected Payment of Future Benefits . As of December 31, 2023, we expect the following cash flows under our plans: Pension Benefits OPEB (In millions) Contributions expected in 2024 $ 50 $ — Benefit payments expected in: 2024 $ 190 $ 24 2025 187 22 2026 185 21 2027 179 19 2028 175 18 2029 - 2033 777 67
Schedule of Weighted-Average Actuarial Assumptions	Actuarial Assumptions and Sensitivity Analysis . Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit obligation as of December 31, 2023 and 2022 and net benefit costs of our pension and OPEB plans for 2023, 2022 and 2021: Pension Benefits OPEB 2023 2022 2023 2022 Assumptions related to benefit obligations: Discount rate 5.13 % 5.41 % 5.08 % 5.38 % Rate of compensation increase 3.50 % 3.50 % n/a n/a Interest crediting rate 3.85 % 3.50 % n/a n/a Pension Benefits OPEB 2023 2022 2021 2023 2022 2021 Assumptions related to benefit costs: Discount rate 5.41 % 2.74 % 2.27 % 5.38 % 2.56 % 2.08 % Expected return on plan assets 7.00 % 6.50 % 6.25 % 6.00 % 5.75 % 5.75 % Rate of compensation increase 3.50 % 3.50 % 3.50 % n/a n/a n/a Interest crediting rate 3.50 % 3.01 % 2.57 % n/a n/a n/a
Schedule of Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income	Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows: Pension Benefits OPEB 2023 2022 2021 2023 2022 2021 (In millions) Components of net benefit cost (credit): Service cost $ 55 $ 55 $ 53 $ 1 $ 1 $ 1 Interest cost 107 57 45 10 5 4 Expected return on assets (117) (142) (133) (13) (17) (16) Amortization of prior service cost (credit) 1 1 — (3) (3) (5) Amortization of net actuarial loss (gain) 35 29 52 (16) (18) (17) Settlement loss 46 — — — — — Net benefit cost (credit) 127 — 17 (21) (32) (33) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 10 (11) (127) (30) 24 (40) Amortization or settlement recognition of net actuarial (loss) gain (81) (29) (52) 16 17 17 Amortization of prior service (cost) credit (1) (1) — 1 2 3 Total recognized in total other comprehensive (income) loss(a) (72) (41) (179) (13) 43 (20) Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ 55 $ (41) $ (162) $ (34) $ 11 $ (53) (a) Excludes $4 million and $3 million for the years ended December 31, 2022 and 2021, respectively, associated with other plans.

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
Stockholders' Equity (Tables)	Dec. 31, 2023
Stockholders' Equity Note [Abstract]
Schedule of Share Repurchases	On July 19, 2017, our Board approved a $2 billion share buy-back program that began in December 2017. On January 18, 2023, our Board approved an increase in our share repurchase authorization to $3 billion. All shares we have repurchased are canceled and are no longer outstanding. Activity under the buy-back program is as follows: Year Ended December 31, 2023 2022 2021 (In millions, except per share amounts) Total value of shares repurchased $ 522 $ 368 $ — Total number of shares repurchased 32 21 — Average repurchase price per share $ 16.56 $ 16.94 $ —
Schedule of Dividends Paid and Payable	The following table provides information about our per share dividends: Year Ended December 31, 2023 2022 2021 Per share cash dividend declared for the period $ 1.13 $ 1.11 $ 1.08 Per share cash dividend paid in the period 1.1250 1.1025 1.0725
Schedule of Changes in Accumulated Other Comprehensive Income (Loss)	Changes in the components of our “Accumulated other comprehensive loss” not including noncontrolling interests are summarized as follows: Net unrealized Pension and Total (In millions) Balance at December 31, 2020 $ (13) $ (394) $ (407) Other comprehensive (loss) gain before reclassifications (432) 155 (277) Losses reclassified from accumulated other comprehensive loss 273 — 273 Net current-period change in accumulated other comprehensive loss (159) 155 (4) Balance at December 31, 2021 (172) (239) (411) Other comprehensive (loss) gain before reclassifications (312) 1 (311) Losses reclassified from accumulated other comprehensive loss 320 — 320 Net current-period change in accumulated other comprehensive loss 8 1 9 Balance at December 31, 2022 (164) (238) (402) Other comprehensive gain before reclassifications 155 65 220 Gains reclassified from accumulated other comprehensive loss (35) — (35) Net current-period change in accumulated other comprehensive loss 120 65 185 Balance at December 31, 2023 $ (44) $ (173) $ (217)

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
Related Party Transactions (Tables)	Dec. 31, 2023
Related Party Transactions [Abstract]
Schedule of Related Party Transactions [Table Text Block]	The following tables summarize our affiliate balance sheet balances and income statement activity, other than amounts reported within our “Investments” balances and “Earnings from equity investments” activity: December 31, 2023 2022 (In millions) Balance sheet location Accounts receivable $ 45 $ 39 Other current assets 2 3 $ 47 $ 42 Current portion of debt $ 5 $ 6 Accounts payable 16 19 Other current liabilities 3 8 Long-term debt 137 142 Other long-term liabilities and deferred credits 54 47 $ 215 $ 222 Year Ended December 31, 2023 2022 2021 (In millions) Income statement location Revenues $ 172 $ 172 $ 164 Operating Costs, Expenses and Other Costs of sales $ 132 $ 134 $ 145 Other operating expenses 57 50 52

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
Risk Management (Tables)	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Energy Commodity Price Risk Management	As of December 31, 2023, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales: Net open position long/(short) Derivatives designated as hedging contracts Crude oil fixed price (16.9) MMBbl Natural gas fixed price (61.0) Bcf Natural gas basis (35.4) Bcf NGL fixed price (0.6) MMBbl Derivatives not designated as hedging contracts Crude oil fixed price (1.2) MMBbl Crude oil basis (4.1) MMBbl Natural gas fixed price (7.5) Bcf Natural gas basis (101.6) Bcf NGL fixed price (0.7) MMBbl
Schedule of Interest Rate Risk Management	The following table summarizes our outstanding interest rate contracts as of December 31, 2023: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments Fixed-to-variable interest rate contracts(a)(b) $ 6,200 Fair value hedge March 2035 Treasury locks(c) 1,000 Cash flow hedge March 2024 (a) The principal amount of hedged senior notes consisted of $1,450 million included in “Current portion of debt” and $4,750 million included in “Long-term debt” on our accompanying consolidated balance sheet. (b) During the year ended December 31, 2023, certain optional expedients as set forth in Topic 848 – Reference Rate Reform were elected on certain of these contracts to preserve fair value hedge accounting treatment. See Note 19 “Recent Accounting Pronouncements” for further information on Topic 848. (c)
Schedule of Foreign Currency Risk Management	The following table summarizes our outstanding foreign currency contracts as of December 31, 2023: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments EUR-to-USD cross currency swap contracts(a) $ 543 Cash flow hedge March 2027 (a) These s waps eliminate the foreign currency risk associated with our Euro-denominated debt.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets: Fair Value of Derivative Contracts Location Derivatives Asset Derivatives Liability December 31, December 31, 2023 2022 2023 2022 (In millions) Derivatives designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Fair value of derivative contracts) $ 77 $ 150 $ (75) $ (156) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 12 6 (29) (91) Subtotal 89 156 (104) (247) Interest rate contracts Fair value of derivative contracts/(Fair value of derivative contracts) — — (120) (144) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 37 39 (158) (261) Subtotal 37 39 (278) (405) Foreign currency contracts Fair value of derivative contracts/(Fair value of derivative contracts) — — (2) (3) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (2) (32) Subtotal — — (4) (35) Total 126 195 (386) (687) Derivatives not designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Fair value of derivative contracts) 49 80 (8) (162) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 3 23 (1) (19) Subtotal 52 103 (9) (181) Interest rate contracts Fair value of derivative contracts/(Fair value of derivative contracts) — 1 — — Total 52 104 (9) (181) Total derivatives $ 178 $ 299 $ (395) $ (868)
Schedule of Derivative Assets and Liabilities at Fair Value	The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements. Balance sheet asset fair value measurements by level Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral held(a) Net amount (In millions) As of December 31, 2023 Energy commodity derivative contracts(b) $ 65 $ 75 $ — $ 140 $ (16) $ — $ 124 Interest rate contracts — 38 — 38 — — 38 As of December 31, 2022 Energy commodity derivative contracts(b) $ 115 $ 144 $ — $ 259 $ (186) $ — $ 73 Interest rate contracts — 40 — 40 — — 40 Balance sheet liability Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral posted(a) Net amount (In millions) As of December 31, 2023 Energy commodity derivative contracts(b) $ (17) $ (96) $ — $ (113) $ 16 $ (85) $ (182) Interest rate contracts — (278) — (278) — — (278) Foreign currency contracts — (4) — (4) — — (4) As of December 31, 2022 Energy commodity derivative contracts(b) (23) (405) — (428) 186 (30) (272) Interest rate contracts — (405) — (405) — — (405) Foreign currency contracts — (35) — (35) — — (35) (a) Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table. (b) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.
Schedule of Derivative Instruments, Gain (Loss) in Statements of Income	The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of income and comprehensive income: Derivatives in fair value hedging relationships Location Gain/(loss) recognized in income on derivatives and related hedged item Year Ended December 31, 2023 2022 2021 (In millions) Interest rate contracts Interest, net $ 138 $ (738) $ (322) Hedged fixed rate debt(a) Interest, net $ (132) $ 743 $ 326 (a) As of December 31, 2023, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $236 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet. Derivatives in cash flow hedging relationships Gain/(loss) recognized in OCI on derivatives(a) Location Gain/(loss) reclassified from Accumulated OCI into income(b) Year Ended Year Ended December 31, December 31, 2023 2022 2021 2023 2022 2021 (In millions) (In millions) Energy commodity derivative contracts $ 182 $ (338) $ (475) Revenues—Commodity sales $ 103 $ (491) $ (271) Costs of sales (73) 144 20 Interest rate contracts (10) 7 5 Interest, net — — — Foreign currency contracts 30 (73) (93) Other, net 17 (68) (105) Total $ 202 $ (404) $ (563) Total $ 47 $ (415) $ (356) (a) We expect to reclassify an approximately $10 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2023 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices. (b) During the years ended December 31, 2023, 2022 and 2021, we recognized gains of none, $121 million and $41 million, respectively, associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred). Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives Year Ended December 31, 2023 2022 2021 (In millions) Energy commodity derivative contracts Revenues—Commodity sales $ 75 $ 137 $ (652) Costs of sales 100 (190) 152 Earnings from equity investments 2 (11) (5) Interest rate contracts Interest, net 1 (10) 12 Total(a) $ 178 $ (74) $ (493) (a) The years ended December 31, 2023, 2022 and 2021 include approximate gains (losses) of $58 million, $(11) million and $(479) million, respectively, associated with natural gas, crude and NGL derivative contract settlements.

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
Revenue Recognition (Tables)	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Schedule of Disaggregation of Revenue	The following tables present our revenues disaggregated by segment, revenue source and type of revenue for each revenue source: Year Ended December 31, 2023 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,543 $ 171 $ 819 $ 1 $ 3 $ 4,537 Fee-based services 1,008 1,036 427 40 (9) 2,502 Total services 4,551 1,207 1,246 41 (6) 7,039 Commodity sales Natural gas sales 2,651 — — 85 (12) 2,724 Product sales 1,110 1,635 33 1,114 (8) 3,884 Total commodity sales 3,761 1,635 33 1,199 (20) 6,608 Total revenues from contracts with customers 8,312 2,842 1,279 1,240 (26) 13,647 Other revenues(c) Leasing services(d) 475 200 638 55 — 1,368 Derivatives adjustments on commodity sales 285 — — (107) — 178 Other 96 24 — 21 — 141 Total other revenues 856 224 638 (31) — 1,687 Total revenues $ 9,168 $ 3,066 $ 1,917 $ 1,209 $ (26) $ 15,334 Year Ended December 31, 2022 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,547 $ 207 $ 763 $ 1 $ (3) $ 4,515 Fee-based services 926 962 426 46 — 2,360 Total services 4,473 1,169 1,189 47 (3) 6,875 Commodity sales Natural gas sales 6,266 — — 94 (20) 6,340 Product sales 1,433 2,032 29 1,426 (7) 4,913 Total commodity sales 7,699 2,032 29 1,520 (27) 11,253 Total revenues from contracts with customers 12,172 3,201 1,218 1,567 (30) 18,128 Other revenues(c) Leasing services(d) 474 194 574 60 — 1,302 Derivatives adjustments on commodity sales (26) (3) — (325) — (354) Other 66 26 — 32 — 124 Total other revenues 514 217 574 (233) — 1,072 Total revenues $ 12,686 $ 3,418 $ 1,792 $ 1,334 $ (30) $ 19,200 Year Ended December 31, 2021 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,402 $ 259 $ 751 $ 1 $ (2) $ 4,411 Fee-based services 746 949 375 45 (1) 2,114 Total services 4,148 1,208 1,126 46 (3) 6,525 Commodity sales Natural gas sales 6,463 — — 32 (15) 6,480 Product sales 1,260 845 24 1,070 (50) 3,149 Total commodity sales 7,723 845 24 1,102 (65) 9,629 Total revenues from contracts with customers 11,871 2,053 1,150 1,148 (68) 16,154 Other revenues(c) Leasing services(d) 473 172 565 56 — 1,266 Derivatives adjustments on commodity sales (700) (1) — (222) — (923) Other 65 21 — 27 — 113 Total other revenues (162) 192 565 (139) — 456 Total revenues $ 11,709 $ 2,245 $ 1,715 $ 1,009 $ (68) $ 16,610 (a) Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c)). (b) Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as “Fee-based services.” (c) Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 14 for additional information related to our derivative contracts. (d) Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.
Revenue Allocated to Remaining Performance Obligations	The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of December 31, 2023 that we will invoice or transfer from contract liabilities and recognize in future periods: Year Estimated Revenue (In millions) 2024 $ 4,687 2025 4,007 2026 3,472 2027 2,874 2028 2,475 Thereafter 14,336 Total $ 31,851

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
Reportable Segments (Tables)	Dec. 31, 2023
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Financial information by segment follows: Year Ended December 31, 2023 2022 2021 (In millions) Revenues Natural Gas Pipelines Revenues from external customers $ 9,152 $ 12,659 $ 11,644 Intersegment revenues 16 27 65 Products Pipelines 3,066 3,418 2,245 Terminals Revenues from external customers 1,911 1,789 1,712 Intersegment revenues 6 3 3 CO 2 Revenues from external customers 1,205 1,334 1,009 Intersegment revenues 4 — — Corporate and intersegment eliminations (26) (30) (68) Total consolidated revenues $ 15,334 $ 19,200 $ 16,610 Year Ended December 31, 2023 2022 2021 (In millions) Operating expenses(a) Natural Gas Pipelines $ 4,700 $ 8,562 $ 7,000 Products Pipelines 2,024 2,391 1,239 Terminals 896 853 793 CO 2 550 554 289 Corporate and intersegment eliminations (4) (9) (34) Total consolidated operating expenses $ 8,166 $ 12,351 $ 9,287 Year Ended December 31, 2023 2022 2021 (In millions) Other expense (income)(b) Natural Gas Pipelines $ (12) $ (13) $ 1,597 Products Pipelines 4 (12) — Terminals (2) (14) 32 CO 2 — (1) (8) Corporate (3) 1 (4) Total consolidated other expense (income) $ (13) $ (39) $ 1,617 Year Ended December 31, 2023 2022 2021 (In millions) DD&A Natural Gas Pipelines $ 1,041 $ 1,096 $ 1,099 Products Pipelines 367 336 335 Terminals 493 458 440 CO 2 325 272 236 Corporate 24 24 25 Total consolidated DD&A $ 2,250 $ 2,186 $ 2,135 Year Ended December 31, 2023 2022 2021 (In millions) Earnings from equity investments and amortization of excess cost of equity investments Natural Gas Pipelines $ 746 $ 650 $ 435 Products Pipelines (6) 33 34 Terminals 9 14 15 CO 2 23 31 29 Total consolidated equity earnings $ 772 $ 728 $ 513 Year Ended December 31, 2023 2022 2021 (In millions) Other, net-income (expense) Natural Gas Pipelines $ 26 $ (19) $ 216 Products Pipelines 1 — 1 Terminals 8 8 3 Corporate (72) 66 62 Total consolidated other, net-income (expense) $ (37) $ 55 $ 282 Year Ended December 31, 2023 2022 2021 (In millions) Segment EBDA(c) Natural Gas Pipelines $ 5,282 $ 4,801 $ 3,815 Products Pipelines 1,062 1,107 1,064 Terminals 1,040 975 908 CO 2 689 819 760 Total Segment EBDA 8,073 7,702 6,547 DD&A (2,250) (2,186) (2,135) Amortization of excess cost of equity investments (66) (75) (78) General and administrative and corporate charges (759) (593) (623) Interest, net (1,797) (1,513) (1,492) Income tax expense (715) (710) (369) Total consolidated net income $ 2,486 $ 2,625 $ 1,850 Year Ended December 31, 2023 2022 2021 (In millions) Capital expenditures Natural Gas Pipelines $ 1,299 $ 666 $ 570 Products Pipelines 221 — 122 Terminals 406 552 332 CO 2 355 371 230 Corporate 36 32 27 Total consolidated capital expenditures $ 2,317 $ 1,621 $ 1,281 December 31, 2023 2022 (In millions) Investments Natural Gas Pipelines $ 7,273 $ 6,993 Products Pipelines 390 445 Terminals 130 128 CO 2 81 87 Total consolidated investments $ 7,874 $ 7,653 December 31, 2023 2022 (In millions) Other intangibles, net Natural Gas Pipelines $ 742 $ 439 Products Pipelines 687 777 Terminals 26 38 CO 2 502 555 Total consolidated other intangibles, net $ 1,957 $ 1,809 December 31, 2023 2022 (In millions) Assets Natural Gas Pipelines $ 49,883 $ 47,978 Products Pipelines 8,781 8,985 Terminals 8,235 8,357 CO 2 3,497 3,449 Corporate assets(d) 624 1,309 Total consolidated assets $ 71,020 $ 70,078 (a) Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes. (b) Include s (gain) loss on divestitures and impairments, net and other (expense) income, net. (c) Includes revenues, earnings from equity investments, and other, net, less operating expenses, (gain) loss on divestitures and impairments, net and other (expense) income, net. (d) Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.
Schedule of Revenue and Long-lived Assets from External Customers Attributed to Foreign Countries by Geographic Area [Table Text Block]	Following is geographic information regarding the revenues and long-lived assets of our business: Year Ended December 31, 2023 2022 2021 (In millions) Revenues from external customers U.S. $ 15,255 $ 19,036 $ 16,479 Mexico and other foreign 79 164 131 Total consolidated revenues from external customers $ 15,334 $ 19,200 $ 16,610 December 31, 2023 2022 2021 (In millions) Long-term assets, excluding goodwill and other intangibles U.S. $ 46,328 $ 44,425 $ 44,916 Mexico and other foreign 72 75 78 Canada — 1 1 Total consolidated long-lived assets $ 46,400 $ 44,501 $ 44,995

Leases (Tables)

Leases (Tables)	12 Months Ended
Leases (Tables)	Dec. 31, 2023
Leases [Abstract]
Lease, Cost [Table Text Block]	Following are components of our lease cost: Year Ended December 31, 2023 2022 2021 (In millions) Operating leases $ 71 $ 62 $ 60 Short-term and variable leases 127 101 109 Total lease cost $ 198 $ 163 $ 169 Other information related to our operating leases are as follows: Year Ended December 31, 2023 2022 2021 (In millions, Operating cash flows from operating leases $ (157) $ (132) $ (137) Investing cash flows from operating leases (41) (31) (32) ROU assets obtained in exchange for operating lease obligations, net of retirements 56 22 59 Amortization of ROU assets 58 50 47 Weighted average remaining lease term 8.72 years 9.8 years 10.39 years Weighted average discount rate 4.59 % 4.26 % 3.95 % Amounts recognized in the accompanying consolidated balance sheets are as follows: December 31, Lease Activity(a) Balance sheet location 2023 2022 (In millions) ROU assets Deferred charges and other assets $ 285 $ 287 Short-term lease liability Other current liabilities 55 47 Long-term lease liability Other long-term liabilities and deferred credits 230 240 (a) We have immaterial financing leases recorded as of December 31, 2023 and 2022.
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2023 are as follows: Year Commitment (In millions) 2024 $ 67 2025 56 2026 40 2027 33 2028 25 Thereafter 145 Total lease payments 366 Less: Interest (81) Present value of lease liabilities $ 285

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Accounts Receivable, Net (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Allowance for Credit Loss	$ 1	$ 1

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Balance at beginning of period	$ 204	$ 196
Accretion expense	12	12
New obligations	22	2
Settlements	(7)	(6)
Balance at end of period	231	204
Asset Retirement Obligation, Current	$ 3	$ 3

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Goodwill (Details)	May 31, 2023 segment
Accounting Policies [Abstract]
Number of Reporting Units	7

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Other Intangibles (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Other Intangibles
Weighted Average Amortization Period	11 years 3 months 18 days
Gross	$ 3,543	$ 3,382
Accumulated amortization	(1,586)	(1,573)
Net carrying amount	1,957	1,809
Amortization expense	202	$ 253	$ 237
Estimated amortization expense:
2024	198
2025	193
2026	191
2027	191
2028	$ 190

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Operations and Maintenance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Expense
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Results of Operations, Expense from Oil and Gas Producing Activities	$ 393	$ 367	$ 180

Summary of Significant Accoun_9

Summary of Significant Accounting Policies - Leases (Details)	Dec. 31, 2023
Minimum
Lessee, Operating Lease, Remaining Lease Term	1 year
Maximum
Lessee, Operating Lease, Remaining Lease Term	47 years

Summary of Significant Accou_10

Summary of Significant Accounting Policies - Redeemable NCI (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Elba Liquefaction Company L.L.C.
Variable Interest Entity [Line Items]
Net income (loss) attributable to redeemable noncontrolling interest	$ 58

Summary of Significant Accou_11

Summary of Significant Accounting Policies - Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Regulatory Assets and Liabilities [Line Items]
Current regulatory assets	$ 26	$ 73
Non-current regulatory assets	214	183
Total regulatory assets(a)	240	256
Current regulatory liabilities	45	50
Non-current regulatory liabilities	188	175
Total regulatory liabilities(b)	233	$ 225
Regulatory assets recoverable without earning a return	$ 138
Regulatory assets, weighted average remaining recovery period	10 years
Remaining Amounts of Regulatory Liabilities Subject to Crediting Period	$ 104
Remaining Recovery Period of Regulatory Liabilities Subject to Defined Crediting Period	13 years
Remaining Amounts of Regulatory Liabilities Not Subject to Defined Crediting Period	$ 84
Loss on Disposal of Assets
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	100
Income Tax Gross Up on AFUDC Equity
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	43
Other Regulatory Assets (Liabilities)
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	$ 97

Summary of Significant Accou_12

Summary of Significant Accounting Policies - Earnings per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Stockholders	$ 2,391	$ 2,548	$ 1,784
Less: Net Income Allocated to Restricted stock awards	$ (14)	$ (13)	$ (14)
Basic Weighted Average Shares Outstanding	2,234	2,258	2,266
Basic Earnings Per Share	$ 1.06	$ 1.12	$ 0.78
Unvested restricted stock awards
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities	13	13	13
Convertible trust preferred securities
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities	3	3	3
Class P
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Stockholders	$ 2,377	$ 2,535	$ 1,770
Class P \| Unvested restricted stock awards
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Awards outstanding	13

Acquisitions and Divestitures -

Acquisitions and Divestitures - Schedule of Recognized Identified Assets and Liabilities Assumed (Details) $ in Millions					5 Months Ended	12 Months Ended
	Dec. 28, 2023 USD ($)	Aug. 11, 2022 USD ($) assets	Jul. 19, 2022 USD ($) assets	Aug. 20, 2021 USD ($) facilities	Nov. 24, 2021 USD ($)	Dec. 31, 2023 USD ($)	Jun. 01, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Business Acquisition [Line Items]
Resulting goodwill						$ 20,121		$ 19,965	$ 19,914
Equity Method Investments						$ 7,874		7,653
Weighted average amortization period, customer relationship						11 years 3 months 18 days
Dos Caminos LLC
Business Acquisition [Line Items]
Equity Method Investments						$ 192		$ 0
Ownership Interest						50%
STX Midstream
Business Acquisition [Line Items]
Purchase price	$ 1,831
Current assets	41
Property, plant, & equipment	1,199
Other long-term assets	552
Current liabilities	(11)
Long-term liabilities	(2)
Non-controlling interest	(104)
Resulting goodwill	156
Business combination, customer contracts	$ 357
Weighted average amortization period, customer relationship	15 years
STX Midstream \| NET Mexico
Business Acquisition [Line Items]
Ownership percentage	90%
STX Midstream \| Dos Caminos LLC
Business Acquisition [Line Items]
Equity Method Investments	$ 192
Ownership Interest	50%
Diamond M
Business Acquisition [Line Items]
Purchase price							$ 13
Current assets							0
Property, plant, & equipment							25
Other long-term assets							0
Current liabilities							0
Long-term liabilities							(12)
Non-controlling interest							0
Resulting goodwill							$ 0
North American Natural Resources, Inc.
Business Acquisition [Line Items]
Purchase price		$ 132
Current assets		2
Property, plant, & equipment		5
Other long-term assets		64
Current liabilities		0
Long-term liabilities		0
Non-controlling interest		0
Resulting goodwill		$ 61
Weighted average amortization period, customer relationship		13 years
Number Of Landfill Assets \| assets		7
Mas Ranger, LLC
Business Acquisition [Line Items]
Purchase price			$ 358
Current assets			9
Property, plant, & equipment			31
Other long-term assets			320
Current liabilities			(2)
Long-term liabilities			0
Non-controlling interest			0
Resulting goodwill			$ 0
Weighted average amortization period, customer relationship			17 years
Number Of Landfill Assets \| assets			3
Kinetrex Energy
Business Acquisition [Line Items]
Purchase price				$ 318
Current assets				18
Property, plant, & equipment				49
Other long-term assets				272
Current liabilities				(6)
Long-term liabilities				(68)
Non-controlling interest				0
Resulting goodwill				53
Business combination, customer contracts				$ 199
Weighted average amortization period, customer relationship				10 years
Number Of Landfill-based RNG facilities \| facilities				3
Kinetrex Energy \| RNG Facility
Business Acquisition [Line Items]
Equity Method Investments				$ 63
Ownership Interest				50%
Stagecoach Gas Services LLC
Business Acquisition [Line Items]
Purchase price					$ 1,258
Current assets					53
Property, plant, & equipment					1,187
Other long-term assets					24
Current liabilities					(6)
Long-term liabilities					0
Non-controlling interest					0
Resulting goodwill					$ 0
Weighted average amortization period, customer relationship					2 years
Stagecoach Gas Services LLC \| Measurement Input, Discount Rate \| Valuation Technique, Discounted Cash Flow
Business Acquisition [Line Items]
Estimated weighted average cost of capital					12%

Acquisitions and Divestitures_4

Acquisitions and Divestitures - Sale of an Interest in ELC (Details) - USD ($) $ in Millions		12 Months Ended
	Sep. 26, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Variable Interest Entity [Line Items]
Proceeds from sale of noncontrolling interests (Note 3)		$ 0	$ 557	$ 0
Impact of change in ownership interest in subsidiary			501
ASSETS
Current assets		2,542	3,803
Property, plant and equipment, net		37,297	35,599
Deferred charges and other assets		1,229	1,249
Liabilities [Abstract]
Current liabilities		7,221	6,930
Other long-term liabilities and deferred credits		2,615	2,008
Elba Liquefaction Company L.L.C.
ASSETS
Current assets		46	34
Property, plant and equipment, net		1,162	1,197
Deferred charges and other assets		5	6
Liabilities [Abstract]
Current liabilities		15	15
Other long-term liabilities and deferred credits		$ 25	5
Additional paid-in capital
Variable Interest Entity [Line Items]
Impact of change in ownership interest in subsidiary			$ 190
Elba Liquefaction Company L.L.C.
Variable Interest Entity [Line Items]
Proceeds from sale of noncontrolling interests (Note 3)	$ 557
Ownership percentage		25.50%
Elba Liquefaction Company L.L.C. \| Third Party Investor
Variable Interest Entity [Line Items]
Ownership percentage by noncontrolling owners	25.50%

Acquisitions and Divestitures_5

Acquisitions and Divestitures - Sale of an interest in NGPL Holdings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Mar. 08, 2021
Schedule of Equity Method Investments [Line Items]
Pre-tax gain on sale of interest in equity investment	$ 0	$ 0	$ 206
NGPL Holdings, LLC \| Related Party
Schedule of Equity Method Investments [Line Items]
Note receivable	$ 375	375		$ 500
Interest rate, stated percentage	6.75%
ArcLight Capital Partners, LLC \| NGPL Holdings, LLC \| Related Party
Schedule of Equity Method Investments [Line Items]
Note receivable				$ 125
NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	37.50%
Proceeds from sales of assets and investments			412
NGPL Holdings, LLC \| Natural Gas Pipelines
Schedule of Equity Method Investments [Line Items]
Pre-tax gain on sale of interest in equity investment	$ 0	$ 0	$ 206
NGPL Holdings, LLC \| ArcLight Capital Partners, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	37.50%			25%
NGPL Holdings, LLC \| KMI
Schedule of Equity Method Investments [Line Items]
Ownership Interest	37.50%

Gains and Losses on Divestitu_3

Gains and Losses on Divestitures, Impairments and Other Write-downs (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Pre-tax losses (gains) on divestitures, impairments and other write-downs, net		$ 52	$ (32)	$ 1,535
Impairments of long-lived assets				$ 1,634
Impairment of long-lived assets (Extensible)				Gain (Loss) on Sale of Assets and Asset Impairment Charges
Gain on sale of interest in equity investment		0	0	$ (206)
Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of long-lived assets		0	0	1,600
(Gains) losses on divestitures of long-lived assets		(10)	(10)	(1)
Products Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gains) losses on divestitures of long-lived assets		0	(12)	0
Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of long-lived assets		0	0	34
(Gains) losses on divestitures of long-lived assets		(1)	(9)	2
CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gains) losses on divestitures of long-lived assets		(1)	(1)	(8)
Other
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gains) losses on divestitures of long-lived assets		(3)	0	(3)
NGPL Holdings \| Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Gain on sale of interest in equity investment		0	0	(206)
Ruby Pipeline Holding Company LLC \| Natural Gas Pipelines \| Notes Receivable
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of equity investments	$ 117	0	0	117
Double Eagle Pipeline LLC
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of equity investments		67
Double Eagle Pipeline LLC \| Products Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of equity investments		$ 67	$ 0	$ 0

Gains and Losses on Divestitu_4

Gains and Losses on Divestitures, Impairments and Other Write-downs - Long Lived Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Impairments of long-lived assets			$ 1,634
Double Eagle Pipeline LLC
Property, Plant and Equipment [Line Items]
Impairments of equity investments	$ 67
Products Pipelines \| Double Eagle Pipeline LLC
Property, Plant and Equipment [Line Items]
Impairments of equity investments	67	$ 0	0
Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Impairments of long-lived assets	$ 0	$ 0	$ 1,600
Natural Gas Pipelines \| Valuation Technique, Discounted Cash Flow
Property, Plant and Equipment [Line Items]
Estimated weighted average cost of capital			8.50%

Gains and Losses on Divestitu_5

Gains and Losses on Divestitures, Impairments and Other Write-downs - Investment in Ruby (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Impairment of Long-lived assets and equity investments [Line Items]
Current portion of debt		$ 4,049	$ 3,385
Equity Method Investments		7,874	7,653
Ruby Pipeline Holding Company LLC
Impairment of Long-lived assets and equity investments [Line Items]
Equity Method Investments			0
Ruby Pipeline Holding Company LLC \| Ruby Chapter 11 Bankruptcy Filing [Member] \| Other, net
Impairment of Long-lived assets and equity investments [Line Items]
Litigation Settlement, Expense			28.5
Ruby Pipeline Holding Company LLC \| Ruby Unsecured Notes Due April 1, 2022
Impairment of Long-lived assets and equity investments [Line Items]
Current portion of debt			475
Ruby Pipeline Holding Company LLC \| Natural Gas Pipelines \| Notes Receivable
Impairment of Long-lived assets and equity investments [Line Items]
Impairments of equity investments	$ 117	$ 0	$ 0	$ 117

Income Taxes - Income Before In

Income Taxes - Income Before Income Taxes and Income Tax Provision (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Components of Income Before Income Taxes
U.S.	$ 3,192	$ 3,318	$ 2,217
Foreign	9	17	2
Income Before Income Taxes	3,201	3,335	2,219
Current tax expense
State	5	14	11
Foreign	0	4	3
Total	5	18	14
Deferred tax expense
Federal	619	642	334
State	91	50	21
Total	710	692	355
Total	$ 715	$ 710	$ 369

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Amount:
Federal income tax	$ 672	$ 700	$ 466
State income tax, net of federal benefit	64	69	50
Dividend received deduction	(34)	(36)	(46)
Release of valuation allowance	0	0	(38)
General business credit	(1)	0	(36)
Other	14	(23)	(27)
Total	$ 715	$ 710	$ 369
Percent:
Federal income tax, percent	21%	21%	21%
State income tax, net of federal benefit, percent	2%	2%	2.20%
Dividend received deduction, percent	(1.10%)	(1.10%)	(2.10%)
Release of valuation allowance, percent	0%	0%	(1.70%)
General business credit, percent	0%	0%	(1.60%)
Other, percent	0.40%	(0.70%)	(1.20%)
Total, percent	22.30%	21.20%	16.60%

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred tax assets
Employee benefits	$ 114	$ 116
Net operating loss carryforwards	2,024	2,007
Tax credit carryforwards	300	303
Interest expense limitation	266	82
Other	181	192
Valuation allowances	(77)	(79)
Total deferred tax assets	2,808	2,621
Deferred tax liabilities
Property, plant and equipment	215	163
Investments(a)	3,951	3,056
Other	30	25
Total deferred tax liabilities	4,196	3,244
Net deferred tax liability	$ (1,388)	$ (623)

Income Taxes - Valuation Allowa

Income Taxes - Valuation Allowance (Details) $ in Millions	12 Months Ended
Income Taxes - Valuation Allowance (Details) $ in Millions	Dec. 31, 2023 USD ($)
Valuation Allowance [Line Items]
Balance at beginning of period	$ 79
Balance at end of period	77
Statute expirations for federal and state NOL and foreign tax credits
Valuation Allowance [Line Items]
Change in valuation allowances	(5)
Currency Fluctuation
Valuation Allowance [Line Items]
Change in valuation allowances	$ 3

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Valuation Allowances (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred tax assets and valuation allowances:
Net operating loss, deferred tax assets	$ 2,024	$ 2,007
Tax credits, deferred tax assets	300	$ 303
General Business Credits \| Expires from 2036 - 2042
Deferred tax assets and valuation allowances:
Tax credits, unused amount	300
Tax credits, deferred tax assets	300
Tax credits, valuation allowance	0
U.S. Federal \| Indefinite Tax Period
Deferred tax assets and valuation allowances:
Net operating loss, unused amount	6,565
Net operating loss, deferred tax assets	1,379
Net operating loss, valuation allowance	0
U.S. Federal \| Expires from 2035 - 2037
Deferred tax assets and valuation allowances:
Net operating loss, unused amount	1,716
Net operating loss, deferred tax assets	360
Net operating loss, valuation allowance	0
State \| Expires from 2024 - 2043
Deferred tax assets and valuation allowances:
Net operating loss, unused amount	5,293
Net operating loss, deferred tax assets	254
Net operating loss, valuation allowance	(46)
Foreign \| Indefinite Tax Period
Deferred tax assets and valuation allowances:
Net operating loss, unused amount	90
Net operating loss, deferred tax assets	31
Net operating loss, valuation allowance	$ (31)

Income Taxes - Unrecognized Tax

Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Unrecognized Tax Benefits
Balance at beginning of period	$ 23	$ 21	$ 18
Reductions based on statute expirations	(5)	(5)	0
Audit settlement	(1)	0	0
Additions to state reserves for prior years	1	7	3
Balance at end of period	18	$ 23	$ 21
Other Disclosures
Amounts which, if recognized, would affect the effective tax rate	18
Increase in Unrecognized Tax Benefits is Reasonably Possible	$ 4

Property, Plant and Equipment_3

Property, Plant and Equipment, net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 37,297	$ 35,599
Depreciation Depletion and Amortization Expense for Property, Plant and Equipment	2,020	1,905	$ 1,873
Interstate Natural Gas FERC-Regulated
Property, Plant and Equipment [Line Items]
Accumulated depreciation, depletion and amortization	(10,301)	(9,883)
Depreciable assets	11,731	11,582
Property, plant and equipment, net	12,524	12,228
Interstate Natural Gas FERC-Regulated \| Pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 12,019	11,793
Interstate Natural Gas FERC-Regulated \| Pipelines \| Minimum
Property, Plant and Equipment [Line Items]
Composite Depreciation Rates	0.80%
Interstate Natural Gas FERC-Regulated \| Pipelines \| Maximum
Property, Plant and Equipment [Line Items]
Composite Depreciation Rates	6.67%
Interstate Natural Gas FERC-Regulated \| Equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 9,190	8,839
Interstate Natural Gas FERC-Regulated \| Equipment \| Minimum
Property, Plant and Equipment [Line Items]
Composite Depreciation Rates	0.80%
Interstate Natural Gas FERC-Regulated \| Equipment \| Maximum
Property, Plant and Equipment [Line Items]
Composite Depreciation Rates	6.67%
Interstate Natural Gas FERC-Regulated \| Other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 823	833
Interstate Natural Gas FERC-Regulated \| Other \| Minimum
Property, Plant and Equipment [Line Items]
Composite Depreciation Rates	0%
Interstate Natural Gas FERC-Regulated \| Other \| Maximum
Property, Plant and Equipment [Line Items]
Composite Depreciation Rates	25%
Interstate Natural Gas FERC-Regulated \| Land and land rights-of-way
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 399	388
Interstate Natural Gas FERC-Regulated \| Construction work in process
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	394	258
Interstate Natural Gas FERC-Regulated \| Land Rights of Way
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	346	346
Other
Property, Plant and Equipment [Line Items]
Accumulated depreciation, depletion and amortization	(11,774)	(10,529)
Depreciable assets	22,604	21,236
Property, plant and equipment, net	24,773	23,371
Other \| Pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 9,631	8,329
Other \| Pipelines \| Minimum
Property, Plant and Equipment [Line Items]
Straight-Line Estimated Useful Life	5 years
Composite Depreciation Rates	0.09%
Other \| Pipelines \| Maximum
Property, Plant and Equipment [Line Items]
Straight-Line Estimated Useful Life	40 years
Composite Depreciation Rates	33.33%
Other \| Equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 19,974	18,645
Other \| Equipment \| Minimum
Property, Plant and Equipment [Line Items]
Straight-Line Estimated Useful Life	5 years
Composite Depreciation Rates	0.09%
Other \| Equipment \| Maximum
Property, Plant and Equipment [Line Items]
Straight-Line Estimated Useful Life	40 years
Composite Depreciation Rates	33.33%
Other \| Other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 4,773	4,791
Other \| Other \| Minimum
Property, Plant and Equipment [Line Items]
Straight-Line Estimated Useful Life	3 years
Composite Depreciation Rates	0%
Other \| Other \| Maximum
Property, Plant and Equipment [Line Items]
Straight-Line Estimated Useful Life	10 years
Composite Depreciation Rates	33.33%
Other \| Land and land rights-of-way
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 1,518	1,350
Other \| Construction work in process
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	651	785
Other \| Land Rights of Way
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 720	$ 551

Investments - Equity investment

Investments - Equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Mar. 08, 2021
Schedule of Equity Method Investments [Line Items]
Equity Investments	$ 7,874	$ 7,653
Earnings (Loss) from Equity Investments	838	803	$ 591
Amortization of excess cost of equity investments	$ (66)	(75)	(78)
Related Party \| NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Interest rate, stated percentage	6.75%
Note receivable	$ 375	375		$ 500
ArcLight \| Related Party \| NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Note receivable				$ 125
Earnings from equity investments \| Related Party \| NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Interest income	$ 25	25	27
Citrus Corporation
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50%
Equity Investments	$ 1,789	1,781
Earnings (Loss) from Equity Investments	$ 143	145	151
SNG
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50%
Equity Investments	$ 1,668	1,669
Earnings (Loss) from Equity Investments	$ 140	145	128
PHP
Schedule of Equity Method Investments [Line Items]
Ownership Interest	27.74%
Equity Investments	$ 763	666
Earnings (Loss) from Equity Investments	$ 70	70	63
NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	37.50%
Equity Investments	$ 623	610
Earnings (Loss) from Equity Investments	$ 121	111	94
NGPL Holdings, LLC \| ArcLight
Schedule of Equity Method Investments [Line Items]
Ownership Interest	37.50%			25%
NGPL Holdings, LLC \| KMI
Schedule of Equity Method Investments [Line Items]
Ownership Interest	37.50%
NGPL Holdings, LLC \| Brookfield
Schedule of Equity Method Investments [Line Items]
Ownership Interest	25%
Gulf Coast Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	34%
Equity Investments	$ 566	597
Earnings (Loss) from Equity Investments	$ 93	91	86
Dos Caminos LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50%
Equity Investments	$ 192	0
Earnings (Loss) from Equity Investments	$ 0	0	0
Products (SE) Pipe Line Corporation
Schedule of Equity Method Investments [Line Items]
Ownership Interest	51.17%
Equity Investments	$ 369	348
Earnings (Loss) from Equity Investments	$ 65	51	48
MEP
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50%
Equity Investments	$ 342	371
Earnings (Loss) from Equity Investments	$ 87	10	(17)
Utopia Holding LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50%
Equity Investments	$ 322	325
Earnings (Loss) from Equity Investments	$ 22	20	20
Gulf LNG
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50%
Equity Investments	$ 275	311
Earnings (Loss) from Equity Investments	$ 25	24	22
EagleHawk
Schedule of Equity Method Investments [Line Items]
Ownership Interest	25%
Equity Investments	$ 273	273
Earnings (Loss) from Equity Investments	$ 18	13	8
Red Cedar Gathering Company
Schedule of Equity Method Investments [Line Items]
Ownership Interest	49%
Equity Investments	$ 155	155
Earnings (Loss) from Equity Investments	15	17	10
Watco Companies, LLC
Schedule of Equity Method Investments [Line Items]
Equity Investments	84	79
Earnings (Loss) from Equity Investments	$ 10	9	9
Watco Companies, LLC \| Preferred Class B
Schedule of Equity Method Investments [Line Items]
Shares owned	50,000
Quarterly preferred distribution rate	3%
Cortez Pipeline Company
Schedule of Equity Method Investments [Line Items]
Ownership Interest	52.98%
Equity Investments	$ 30	31
Earnings (Loss) from Equity Investments	$ 25	30	29
Double Eagle Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50%
Equity Investments	$ 14	90
Earnings (Loss) from Equity Investments	(42)	18	9
Impairments of equity investments	67
Ruby
Schedule of Equity Method Investments [Line Items]
Equity Investments	0	0
Earnings (Loss) from Equity Investments	0	0	(116)
Ruby \| Notes Receivable
Schedule of Equity Method Investments [Line Items]
Impairments of equity investments			117
All others
Schedule of Equity Method Investments [Line Items]
Equity Investments	409	347
Earnings (Loss) from Equity Investments	$ 46	$ 49	$ 47

Investments - Summary of Signif

Investments - Summary of Significant Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Revenues	$ 15,334	$ 19,200	$ 16,610
Costs and expenses	11,071	15,135	13,694
Net income (loss)	2,486	2,625	1,850
Current assets	2,542	3,803
Current liabilities	7,221	6,930
Non-current liabilities	32,070	31,034
Partners’/owners’ equity	30,306	30,742
Ruby Pipeline Holding Company LLC
Schedule of Equity Method Investments [Line Items]
Non-cash impairment charge			2,200
Equity Method Investment, Nonconsolidated Investee or Group of Investees
Schedule of Equity Method Investments [Line Items]
Revenues	5,981	5,953	5,521
Costs and expenses	4,149	4,193	6,137
Net income (loss)	1,832	1,760	$ (616)
Current assets	1,844	1,461
Non-current assets	23,193	23,360
Current liabilities	1,534	1,617
Non-current liabilities	10,102	10,206
Partners’/owners’ equity	$ 13,401	$ 12,998

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	May 31, 2023	Dec. 31, 2021	Aug. 20, 2021
Goodwill [Line Items]
Gross goodwill	$ 26,907			$ 26,700
Accumulated impairment losses	(6,786)			(6,786)
Goodwill	20,121	$ 19,965		19,914
Acquisitions	156	51
Kinetrex Energy
Goodwill [Line Items]
Goodwill					$ 53
Natural Gas Pipelines Regulated
Goodwill [Line Items]
Gross goodwill	15,892			15,892
Accumulated impairment losses	(1,643)			(1,643)
Goodwill	14,249	14,249		14,249
Acquisitions	0	0
Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Gross goodwill	5,096			4,940
Accumulated impairment losses	(2,597)			(2,597)
Goodwill	2,499	2,343		2,343
Acquisitions	156	0
CO2
Goodwill [Line Items]
Gross goodwill	1,528			1,528
Accumulated impairment losses	(600)			(600)
Goodwill	928	928		928
Acquisitions	0	0
Products Pipelines
Goodwill [Line Items]
Gross goodwill	2,575			2,575
Accumulated impairment losses	(1,197)			(1,197)
Goodwill	1,378	1,378		1,378
Acquisitions	0	0
Products Pipelines Terminals
Goodwill [Line Items]
Gross goodwill	221			221
Accumulated impairment losses	(70)			(70)
Goodwill	151	151		151
Acquisitions	0	0
Terminals
Goodwill [Line Items]
Gross goodwill	1,481			1,481
Accumulated impairment losses	(679)			(679)
Goodwill	802	802		802
Acquisitions	0	0
Terminals \| Maximum
Goodwill [Line Items]
Fair value in excess of their respective carrying values (percentage)			10%
Energy Transition Ventures
Goodwill [Line Items]
Gross goodwill	114			63
Accumulated impairment losses	0			0
Goodwill	114	114		$ 63
Acquisitions	$ 0	51
Energy Transition Ventures \| Kinetrex Energy
Goodwill [Line Items]
Goodwill purchase price adjustment		$ (10)

Debt - Schedule of Debt (Detail

Debt - Schedule of Debt (Details) - USD ($) $ in Millions	Feb. 01, 2024	Jan. 31, 2023	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries			$ 31,929	$ 31,673
Less: Current portion of debt			4,049	3,385
Total long-term debt – KMI and Subsidiaries(g)			27,880	28,288
Credit facility and commercial paper borrowings(a)
Debt Instrument [Line Items]
Less: Current portion of debt			$ 1,989	0
EPC Building, LLC, promissory note, 3.967%, due January 2022 through December 2035 \| EPC Building LLC
Debt Instrument [Line Items]
Interest rate, stated percentage			3.967%
Total debt – KMI and Subsidiaries			$ 330	348
Trust I Preferred Securities, 4.75%, due March 2028(e) \| Capital Trust I
Debt Instrument [Line Items]
Interest rate, stated percentage			4.75%
Total debt – KMI and Subsidiaries			$ 221	220
Less: Current portion of debt			111	111
Other miscellaneous debt(f)
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries			234	242
Less: Current portion of debt			49	$ 49
Senior Notes \| Subsequent Event
Debt Instrument [Line Items]
Proceeds from debt, net	$ 2,230
Senior Notes \| 3.15%, due January 2023
Debt Instrument [Line Items]
Interest rate, stated percentage				3.15%
Total debt – KMI and Subsidiaries			0	$ 1,000
Less: Current portion of debt			0	1,000
Senior Notes \| Floating rate, due January 2023(c)
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries			0	250
Less: Current portion of debt			0	$ 250
Senior Notes \| 3.45%, due February 2023
Debt Instrument [Line Items]
Interest rate, stated percentage				3.45%
Total debt – KMI and Subsidiaries			0	$ 625
Less: Current portion of debt			0	$ 625
Senior Notes \| 3.50%, due September 2023
Debt Instrument [Line Items]
Interest rate, stated percentage				3.50%
Total debt – KMI and Subsidiaries			0	$ 600
Less: Current portion of debt			0	$ 600
Senior Notes \| 5.625%, due November 2023
Debt Instrument [Line Items]
Interest rate, stated percentage				5.625%
Total debt – KMI and Subsidiaries			0	$ 750
Less: Current portion of debt			$ 0	750
Senior Notes \| 4.15%, due February 2024
Debt Instrument [Line Items]
Interest rate, stated percentage			4.15%
Total debt – KMI and Subsidiaries			$ 650	650
Less: Current portion of debt			$ 650	0
Senior Notes \| 4.30%, due May 2024
Debt Instrument [Line Items]
Interest rate, stated percentage			4.30%
Total debt – KMI and Subsidiaries			$ 600	600
Less: Current portion of debt			$ 600	0
Senior Notes \| 4.25%, due September 2024
Debt Instrument [Line Items]
Interest rate, stated percentage			4.25%
Total debt – KMI and Subsidiaries			$ 650	650
Less: Current portion of debt			$ 650	0
Senior Notes \| 4.30%, due June 2025
Debt Instrument [Line Items]
Interest rate, stated percentage			4.30%
Total debt – KMI and Subsidiaries			$ 1,500	1,500
Senior Notes \| 1.75%, due November 2026
Debt Instrument [Line Items]
Interest rate, stated percentage			1.75%
Total debt – KMI and Subsidiaries			$ 500	500
Senior Notes \| 6.70%, due February 2027
Debt Instrument [Line Items]
Interest rate, stated percentage			6.70%
Total debt – KMI and Subsidiaries			$ 7	7
Senior Notes \| 2.25%, due March 2027(d)
Debt Instrument [Line Items]
Interest rate, stated percentage			2.25%
Total debt – KMI and Subsidiaries			$ 552	535
Senior Notes \| 6.67%, due November 2027
Debt Instrument [Line Items]
Interest rate, stated percentage			6.67%
Total debt – KMI and Subsidiaries			$ 7	7
Senior Notes \| 4.30%, due March 2028
Debt Instrument [Line Items]
Interest rate, stated percentage			4.30%
Total debt – KMI and Subsidiaries			$ 1,250	1,250
Senior Notes \| 7.25%, due March 2028
Debt Instrument [Line Items]
Interest rate, stated percentage			7.25%
Total debt – KMI and Subsidiaries			$ 32	32
Senior Notes \| 6.95%, due June 2028
Debt Instrument [Line Items]
Interest rate, stated percentage			6.95%
Total debt – KMI and Subsidiaries			$ 31	31
Senior Notes \| 8.05%, due October 2030
Debt Instrument [Line Items]
Interest rate, stated percentage			8.05%
Total debt – KMI and Subsidiaries			$ 234	234
Senior Notes \| 2.00%, due February 2031
Debt Instrument [Line Items]
Interest rate, stated percentage			2%
Total debt – KMI and Subsidiaries			$ 750	750
Senior Notes \| 7.40%, due March 2031
Debt Instrument [Line Items]
Interest rate, stated percentage			7.40%
Total debt – KMI and Subsidiaries			$ 300	300
Senior Notes \| 7.80%, due August 2031
Debt Instrument [Line Items]
Interest rate, stated percentage			7.80%
Total debt – KMI and Subsidiaries			$ 537	537
Senior Notes \| 7.75%, due January 2032
Debt Instrument [Line Items]
Interest rate, stated percentage			7.75%
Total debt – KMI and Subsidiaries			$ 1,005	1,005
Senior Notes \| 7.75%, due March 2032
Debt Instrument [Line Items]
Interest rate, stated percentage			7.75%
Total debt – KMI and Subsidiaries			$ 300	300
Senior Notes \| 4.80%, due February 2033
Debt Instrument [Line Items]
Interest rate, stated percentage			4.80%
Total debt – KMI and Subsidiaries			$ 750	750
Senior Notes \| 5.20%, due June 2033
Debt Instrument [Line Items]
Interest rate, stated percentage		5.20%	5.20%
Total debt – KMI and Subsidiaries		$ 1,500	$ 1,500	0
Proceeds from debt, net		$ 1,485
Senior Notes \| 7.30%, due August 2033
Debt Instrument [Line Items]
Interest rate, stated percentage			7.30%
Total debt – KMI and Subsidiaries			$ 500	500
Senior Notes \| 5.30%, due December 2034
Debt Instrument [Line Items]
Interest rate, stated percentage			5.30%
Total debt – KMI and Subsidiaries			$ 750	750
Senior Notes \| 5.80%, due March 2035
Debt Instrument [Line Items]
Interest rate, stated percentage			5.80%
Total debt – KMI and Subsidiaries			$ 500	500
Senior Notes \| 7.75%, due October 2035
Debt Instrument [Line Items]
Interest rate, stated percentage			7.75%
Total debt – KMI and Subsidiaries			$ 1	1
Senior Notes \| 6.40%, due January 2036
Debt Instrument [Line Items]
Interest rate, stated percentage			6.40%
Total debt – KMI and Subsidiaries			$ 36	36
Senior Notes \| 6.50%, due February 2037
Debt Instrument [Line Items]
Interest rate, stated percentage			6.50%
Total debt – KMI and Subsidiaries			$ 400	400
Senior Notes \| 7.42%, due February 2037
Debt Instrument [Line Items]
Interest rate, stated percentage			7.42%
Total debt – KMI and Subsidiaries			$ 47	47
Senior Notes \| 6.95%, due January 2038
Debt Instrument [Line Items]
Interest rate, stated percentage			6.95%
Total debt – KMI and Subsidiaries			$ 1,175	1,175
Senior Notes \| 6.50%, due September 2039
Debt Instrument [Line Items]
Interest rate, stated percentage			6.50%
Total debt – KMI and Subsidiaries			$ 600	600
Senior Notes \| 6.55%, due September 2040
Debt Instrument [Line Items]
Interest rate, stated percentage			6.55%
Total debt – KMI and Subsidiaries			$ 400	400
Senior Notes \| 7.50%, due November 2040
Debt Instrument [Line Items]
Interest rate, stated percentage			7.50%
Total debt – KMI and Subsidiaries			$ 375	375
Senior Notes \| 6.375%, due March 2041
Debt Instrument [Line Items]
Interest rate, stated percentage			6.375%
Total debt – KMI and Subsidiaries			$ 600	600
Senior Notes \| 5.625%, due September 2041
Debt Instrument [Line Items]
Interest rate, stated percentage			5.625%
Total debt – KMI and Subsidiaries			$ 375	375
Senior Notes \| 5.00%, due August 2042
Debt Instrument [Line Items]
Interest rate, stated percentage			5%
Total debt – KMI and Subsidiaries			$ 625	625
Senior Notes \| 4.70%, due November 2042
Debt Instrument [Line Items]
Interest rate, stated percentage			4.70%
Total debt – KMI and Subsidiaries			$ 475	475
Senior Notes \| 5.00%, due March 2043
Debt Instrument [Line Items]
Interest rate, stated percentage			5%
Total debt – KMI and Subsidiaries			$ 700	700
Senior Notes \| 5.50%, due March 2044
Debt Instrument [Line Items]
Interest rate, stated percentage			5.50%
Total debt – KMI and Subsidiaries			$ 750	750
Senior Notes \| 5.40%, due September 2044
Debt Instrument [Line Items]
Interest rate, stated percentage			5.40%
Total debt – KMI and Subsidiaries			$ 550	550
Senior Notes \| 5.55%, due June 2045
Debt Instrument [Line Items]
Interest rate, stated percentage			5.55%
Total debt – KMI and Subsidiaries			$ 1,750	1,750
Senior Notes \| 5.05%, due February 2046
Debt Instrument [Line Items]
Interest rate, stated percentage			5.05%
Total debt – KMI and Subsidiaries			$ 800	800
Senior Notes \| 5.20%, due March 2048
Debt Instrument [Line Items]
Interest rate, stated percentage			5.20%
Total debt – KMI and Subsidiaries			$ 750	750
Senior Notes \| 3.25%, due August 2050
Debt Instrument [Line Items]
Interest rate, stated percentage			3.25%
Total debt – KMI and Subsidiaries			$ 500	500
Senior Notes \| 3.60%, due February 2051
Debt Instrument [Line Items]
Interest rate, stated percentage			3.60%
Total debt – KMI and Subsidiaries			$ 1,050	1,050
Senior Notes \| 5.45%, due January 2052
Debt Instrument [Line Items]
Interest rate, stated percentage			5.45%
Total debt – KMI and Subsidiaries			$ 750	750
Senior Notes \| 7.45%, due March 2098
Debt Instrument [Line Items]
Interest rate, stated percentage			7.45%
Total debt – KMI and Subsidiaries			$ 26	26
Senior Notes \| 7.00%, due March 2027 \| TGP
Debt Instrument [Line Items]
Interest rate, stated percentage			7%
Total debt – KMI and Subsidiaries			$ 300	300
Senior Notes \| 7.00%, due October 2028 \| TGP
Debt Instrument [Line Items]
Interest rate, stated percentage			7%
Total debt – KMI and Subsidiaries			$ 400	400
Senior Notes \| 2.90%, due March 2030 \| TGP
Debt Instrument [Line Items]
Interest rate, stated percentage			2.90%
Total debt – KMI and Subsidiaries			$ 1,000	1,000
Senior Notes \| 8.375%, due June 2032 \| TGP
Debt Instrument [Line Items]
Interest rate, stated percentage			8.375%
Total debt – KMI and Subsidiaries			$ 240	240
Senior Notes \| 7.625%, due April 2037 \| TGP
Debt Instrument [Line Items]
Interest rate, stated percentage			7.625%
Total debt – KMI and Subsidiaries			$ 300	300
Senior Notes \| 7.50%, due November 2026 \| EPNG
Debt Instrument [Line Items]
Interest rate, stated percentage			7.50%
Total debt – KMI and Subsidiaries			$ 200	200
Senior Notes \| 3.50%, due February 2032 \| EPNG
Debt Instrument [Line Items]
Interest rate, stated percentage			3.50%
Total debt – KMI and Subsidiaries			$ 300	300
Senior Notes \| 8.375%, due June 2032 \| EPNG
Debt Instrument [Line Items]
Interest rate, stated percentage			8.375%
Total debt – KMI and Subsidiaries			$ 300	300
Senior Notes \| 4.15%, due August 2026 \| CIG
Debt Instrument [Line Items]
Interest rate, stated percentage			4.15%
Total debt – KMI and Subsidiaries			$ 375	375
Senior Notes \| 6.85%, due June 2037 \| CIG
Debt Instrument [Line Items]
Interest rate, stated percentage			6.85%
Total debt – KMI and Subsidiaries			$ 100	$ 100
Senior Notes \| 5.00% due January 31, 2029 \| Subsequent Event
Debt Instrument [Line Items]
Interest rate, stated percentage	5%
Total debt – KMI and Subsidiaries	$ 1,250
Senior Notes \| 5.40% due February 2034 \| Subsequent Event
Debt Instrument [Line Items]
Interest rate, stated percentage	5.40%
Total debt – KMI and Subsidiaries	$ 1,000

Debt - Additional Information (

Debt - Additional Information (Details) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) $ / shares $ / € shares	Dec. 31, 2022 USD ($) $ / €
Debt Instrument [Line Items]
Aggregate principal amount	$ 31,929	$ 31,673
Exchange rate \| $ / €	1.1039	1.0705
Debt Fair Value Adjustments	$ 187	$ 115
Commercial paper notes
Debt Instrument [Line Items]
Weighted average interest rate	5.68%
Capital Trust I
Debt Instrument [Line Items]
Ownership percentage	100%
Senior Notes
Debt Instrument [Line Items]
Redemption Price	100%
2.250% Senior Notes due March 2027 \| Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage	2.25%
Aggregate principal amount	$ 552	535
Change to debt as a result of changes in exchange rate	$ 9	(8)
Trust I Preferred Securities, 4.75%, due March 2028(e) \| Capital Trust I
Debt Instrument [Line Items]
Interest rate, stated percentage	4.75%
Aggregate principal amount	$ 221	$ 220
Trust Convertible Preferred Securities Outstanding \| shares	4.4
Liquidation preference \| $ / shares	$ 50
Conversion price \| $ / shares	$ 25.18
Trust I Preferred Securities, 4.75%, due March 2028(e) \| Capital Trust I \| Class P
Debt Instrument [Line Items]
Conversion rate	0.7197

Debt - Schedule of Current Port

Debt - Schedule of Current Portion of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Current portion of debt	$ 4,049	$ 3,385
$3.5 billion credit facility due August 20, 2027
Debt Instrument [Line Items]
Current portion of debt	0	0
Maximum borrowing capacity	3,500
$500 million credit facility due November 16, 2023
Debt Instrument [Line Items]
Current portion of debt	0	0
Maximum borrowing capacity		500
Commercial paper notes
Debt Instrument [Line Items]
Current portion of debt	1,989	0
Maximum borrowing capacity	3,500
3.15%, due January 2023 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 1,000
Interest rate, stated percentage		3.15%
Senior Notes, floating rate, due January 15, 2023 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 250
3.45%, due February 2023 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 625
Interest rate, stated percentage		3.45%
3.50%, due September 2023 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 600
Interest rate, stated percentage		3.50%
5.625%, due November 2023 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 750
Interest rate, stated percentage		5.625%
4.15%, due February 2024 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 650	$ 0
Interest rate, stated percentage	4.15%
4.30%, due May 2024 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 600	0
Interest rate, stated percentage	4.30%
4.25%, due September 2024 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 650	0
Interest rate, stated percentage	4.25%
Trust I Preferred Securities, 4.75%, due March 2028(e) \| Capital Trust I
Debt Instrument [Line Items]
Current portion of debt	$ 111	111
Interest rate, stated percentage	4.75%
Current portion of other debt
Debt Instrument [Line Items]
Current portion of debt	$ 49	$ 49

Debt - Credit Facilities and Re

Debt - Credit Facilities and Restrictive Covenants (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Line of Credit Facility [Line Items]
Current portion of debt	$ 4,049	$ 3,385
$3.5 billion credit facility due August 20, 2027
Line of Credit Facility [Line Items]
Maximum borrowing capacity	3,500
Borrowing Capacity, Optional Increase	$ 1,000
Maximum ratio of consolidated total funded debt to consolidated earnings before interest income taxes DDA	5.50
Current portion of debt	$ 0	0
$3.5 billion credit facility due August 20, 2027 \| Minimum
Line of Credit Facility [Line Items]
Standby fee rate	0.10%
$3.5 billion credit facility due August 20, 2027 \| Maximum
Line of Credit Facility [Line Items]
Standby fee rate	0.25%
$3.5 billion credit facility due August 20, 2027 \| Secured Overnight Financing Rate (SOFR) \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1%
$3.5 billion credit facility due August 20, 2027 \| Secured Overnight Financing Rate (SOFR) \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.75%
$3.5 billion credit facility due August 20, 2027 \| Federal Funds Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
$3.5 billion credit facility due August 20, 2027 \| Eurodollar
Line of Credit Facility [Line Items]
Basis spread on variable rate	1%
$3.5 billion credit facility due August 20, 2027 \| SOFR Alternative Base Rate \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.10%
$3.5 billion credit facility due August 20, 2027 \| SOFR Alternative Base Rate \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.75%
$500 million credit facility due November 16, 2023
Line of Credit Facility [Line Items]
Maximum borrowing capacity		500
Current portion of debt	$ 0	0
Commercial paper notes
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 3,500
Debt term	270 days
Current portion of debt	$ 1,989	$ 0
Credit Facilities
Line of Credit Facility [Line Items]
Current portion of debt	0
Letters of credit outstanding	81
Remaining borrowing capacity	$ 1,400

Debt - Schedule of Maturities o

Debt - Schedule of Maturities of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
2024	$ 4,049
2025	1,566
2026	1,102
2027	906
2028	1,867
Thereafter	22,439
Total debt – KMI and Subsidiaries	$ 31,929	$ 31,673

Debt - Schedule of Debt Fair Va

Debt - Schedule of Debt Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
Purchase accounting debt fair value adjustments	$ 430	$ 472
Carrying value adjustment to hedged debt	(236)	(367)
Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a)	185	204
Unamortized debt discounts, net	(67)	(68)
Unamortized debt issuance costs	(125)	(126)
Total debt fair value adjustments	$ 187	$ 115
Weighted-average amortization period of the unamortized premium from the termination of interest rate swaps	11 years

Debt - Schedule of Fair Value o

Debt - Schedule of Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	$ 32,116	$ 31,788
Estimated fair value(a)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	31,370	30,070
Estimated fair value(a) \| Capital Trust I \| Trust I preferred securities, 4.75%, due March 2028
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Convertible Debt	$ 207	$ 195

Debt - Interest Rates, Interest

Debt - Interest Rates, Interest Rate Swaps and Contingent Debt (Details)	Dec. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
Debt, weighted average interest rate	5.84%	4.76%

Share-based Compensation and _3

Share-based Compensation and Employee Benefits - Summary of Stock Compensation Plans (Details) - Restricted Stock Awards - Class P	12 Months Ended
	Dec. 31, 2023 shares
Directors' Plan
Share-based Compensation
Total number of shares of Class P common stock authorized	1,190,000
Vesting period	6 months
Grants during the period (shares)	11,220
LTIP
Share-based Compensation
Total number of shares of Class P common stock authorized	63,000,000
Grants during the period (shares)	5,253,000
LTIP \| Minimum
Share-based Compensation
Vesting period	1 year
LTIP \| Maximum
Share-based Compensation
Vesting period	10 years

Share-based Compensation and _4

Share-based Compensation and Employee Benefits - Summary of Activity and Related Balances of Restricted Stock Awards (Details) - Restricted Stock Awards - Class P - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Shares
Outstanding at end of period (shares)	13,000
LTIP
Shares
Outstanding at beginning of period (shares)	13,288
Granted (shares)	5,253
Vested (shares)	(5,226)
Forfeited (shares)	(454)
Outstanding at end of period (shares)	12,861	13,288
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (dollars per share)	$ 16.87
Granted (dollars per share)	17.41	$ 17.31	$ 17.44
Vested (dollars per share)	16.09
Forfeited (dollars per share)	17.03
Outstanding at end of period (dollars per share)	$ 17.41	$ 16.87

Share-based Compensation and _5

Share-based Compensation and Employee Benefits - Summary of Additional Information Related to Restricted Stock Awards (Details) - LTIP - Restricted Stock Awards - Class P - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value per share	$ 17.41	$ 17.31	$ 17.44
Intrinsic value of awards vested during the year	$ 93	$ 47	$ 77
Restricted stock awards expense	63	60	59
Restricted stock awards capitalized	10	$ 9	$ 9
Unrecognized restricted stock awards compensation costs, less estimated forfeitures	$ 117
Weighted average remaining amortization period	2 years 21 days

Share-based Compensation and _6

Share-based Compensation and Employee Benefits - Pensions and Other Postretirement Benefit Plans - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Savings plan - defined contribution plan
Pension and Other Postretirement Benefit Plans
Percentage of eligible compensation contributed	5%
Plan vesting period	2 years
Plan cost	$ 53	$ 51	$ 48
Pension Benefits
Pension and Other Postretirement Benefit Plans
Percentage of employees covered	100%
Vesting period	3 years
Settlements	$ 179
OPEB
Pension and Other Postretirement Benefit Plans
Medicare participation, age	65
Actuarial Assumptions and Sensitivity Analysis
Weighted-average annual rate of increase in the per capita cost of covered health care benefits	5.60%
Ultimate health care cost trend rate	4%

Share-based Compensation and _7

Share-based Compensation and Employee Benefits - Benefit Obligation, Plan Assets and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$ 2,077	$ 2,658
Service cost	55	55	$ 53
Interest cost	107	57	45
Actuarial loss (gain)	14	(503)
Benefits paid	(132)	(190)
Participant contributions	0	0
Settlements	(219)	0
Other	0	0
Benefit obligation at end of period	1,902	2,077	2,658
Change in plan assets:
Fair value of plan assets at beginning of period	1,741	2,231
Actual return on plan assets	122	(350)
Employer contributions	50	50
Participant contributions	0	0
Benefits paid	(132)	(190)
Settlements	(219)	0
Other	0	0
Fair value of plan assets at end of period	1,562	1,741	2,231
Funded status - net (liability) asset at December 31,	(340)	(336)
Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)	0	0
Current benefit liability	0	0
Non-current benefit liability	(340)	(336)
Funded status - net (liability) asset at December 31,	(340)	(336)
Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:
Unrecognized net actuarial (loss) gain	(384)	(455)
Unrecognized prior service (cost) credit	0	(1)
Accumulated other comprehensive (loss) income	(384)	(456)
Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:
Accumulated benefit obligation	1,870	2,047
Fair value of plan assets	1,562	1,741
OPEB
Change in benefit obligation:
Benefit obligation at beginning of period	195	257
Service cost	1	1	1
Interest cost	10	5	4
Actuarial loss (gain)	(6)	(44)
Benefits paid	(25)	(26)
Participant contributions	1	1
Settlements	0	0
Other	1	1
Benefit obligation at end of period	177	195	257
Change in plan assets:
Fair value of plan assets at beginning of period	302	382
Actual return on plan assets	44	(63)
Employer contributions	0	7
Participant contributions	1	1
Benefits paid	(25)	(26)
Settlements	0	0
Other	1	1
Fair value of plan assets at end of period	323	302	$ 382
Funded status - net (liability) asset at December 31,	146	107
Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)	263	239
Current benefit liability	(14)	(15)
Non-current benefit liability	(103)	(117)
Funded status - net (liability) asset at December 31,	146	107
Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:
Unrecognized net actuarial (loss) gain	149	135
Unrecognized prior service (cost) credit	3	4
Accumulated other comprehensive (loss) income	152	139
Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:
Accumulated benefit obligation	119	167
Fair value of plan assets	2	34
OPEB \| Other Affiliates
Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)	$ 53	$ 45

Share-based Compensation and _8

Share-based Compensation and Employee Benefits - Target Asset Allocation (Details)	Dec. 31, 2023
Pension Benefits \| Equities \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	42%
Pension Benefits \| Equities \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	52%
Pension Benefits \| Fixed Income Securities \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	37%
Pension Benefits \| Fixed Income Securities \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	47%
Pension Benefits \| Real Estate \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	2%
Pension Benefits \| Real Estate \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	12%
Pension Benefits \| Company Securities \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	0%
Pension Benefits \| Company Securities \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	10%
OPEB \| Cash \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	0%
OPEB \| Cash \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	23%
OPEB \| Equities \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	43%
OPEB \| Equities \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	71%
OPEB \| Fixed Income Securities \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	26%
OPEB \| Fixed Income Securities \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	50%

Share-based Compensation and _9

Share-based Compensation and Employee Benefits - Fair Value of Pension and OPEB Assets by Level of Assets (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 1,562	$ 1,741	$ 2,231
Pension Benefits \| Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	585	600
Pension Benefits \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	143	152
Pension Benefits \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	442	448
Pension Benefits \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	977	1,141
Pension Benefits \| Short-term Investment Funds \| Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	32	27
Pension Benefits \| Short-term Investment Funds \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits \| Short-term Investment Funds \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	32	27
Pension Benefits \| Equities \| Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	143	152
Pension Benefits \| Equities \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	143	152
Pension Benefits \| Equities \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits \| Fixed Income Securities \| Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	410	421
Pension Benefits \| Fixed Income Securities \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits \| Fixed Income Securities \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	410	421
Pension Benefits \| Common/Collective Trusts \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 976	$ 1,138
Pension Benefits \| Common/Collective Trusts Invested in Equity Securities \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	64%	66%
Pension Benefits \| Common/Collective Trusts Invested in Fixed Income Securities \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	23%	22%
Pension Benefits \| Common/Collective Trusts Invested in Real Estate \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	13%	12%
Pension Benefits \| Private Limited Partnerships \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 1	$ 3
OPEB
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	323	302	$ 382
OPEB \| Short-term Investment Funds \| Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	5	3
OPEB \| Short-term Investment Funds \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB \| Short-term Investment Funds \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	5	3
OPEB \| Common/Collective Trusts \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 318	$ 299
OPEB \| Common/Collective Trusts Invested in Equity Securities \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	62%	61%
OPEB \| Common/Collective Trusts Invested in Fixed Income Securities \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	38%	39%
Class P \| Pension Benefits \| Equities \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Amount of KMI securities invested in	$ 107	$ 110

Share-based Compensation and_10

Share-based Compensation and Employee Benefits - Schedule of Expected Payment of Future Benefits and Employer Contributions (Details) $ in Millions	Dec. 31, 2023 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Contributions expected in 2024	$ 50
Benefit payments expected in:
2024	190
2025	187
2026	185
2027	179
2028	175
2029 - 2033	777
OPEB
Defined Benefit Plan Disclosure [Line Items]
Contributions expected in 2024	0
Benefit payments expected in:
2024	24
2025	22
2026	21
2027	19
2028	18
2029 - 2033	$ 67

Share-based Compensation and_11

Share-based Compensation and Employee Benefits - Schedule of Weighted-Average Actuarial Assumptions (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Assumptions related to benefit obligations:
Discount rate	5.13%	5.41%
Rate of compensation increase	3.50%	3.50%
Interest crediting rate	3.85%	3.50%
Assumptions related to benefit costs:
Discount rate	5.41%	2.74%	2.27%
Expected return on plan assets	7%	6.50%	6.25%
Rate of compensation increase	3.50%	3.50%	3.50%
Interest crediting rate	3.50%	3.01%	2.57%
OPEB
Assumptions related to benefit obligations:
Discount rate	5.08%	5.38%
Assumptions related to benefit costs:
Discount rate	5.38%	2.56%	2.08%
Expected return on plan assets	6%	5.75%	5.75%

Share-based Compensation and_12

Share-based Compensation and Employee Benefits - Schedule of Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Components of net benefit cost (credit):
Service cost	$ 55	$ 55	$ 53
Interest cost	107	57	45
Expected return on assets	(117)	(142)	(133)
Amortization of prior service cost (credit)	1	1	0
Amortization of net actuarial loss (gain)	35	29	52
Settlement loss	46	0	0
Net benefit cost (credit)	127	0	17
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net loss (gain) arising during period	10	(11)	(127)
Amortization or settlement recognition of net actuarial (loss) gain	(81)	(29)	(52)
Amortization of prior service (cost) credit	(1)	(1)	0
Total recognized in total other comprehensive (income) loss(a)	(72)	(41)	(179)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss	55	(41)	(162)
Pension Benefits \| Other Plans
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Total recognized in total other comprehensive (income) loss(a)		4	3
OPEB
Components of net benefit cost (credit):
Service cost	1	1	1
Interest cost	10	5	4
Expected return on assets	(13)	(17)	(16)
Amortization of prior service cost (credit)	(3)	(3)	(5)
Amortization of net actuarial loss (gain)	(16)	(18)	(17)
Settlement loss	0	0	0
Net benefit cost (credit)	(21)	(32)	(33)
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net loss (gain) arising during period	(30)	24	(40)
Amortization or settlement recognition of net actuarial (loss) gain	16	17	17
Amortization of prior service (cost) credit	1	2	3
Total recognized in total other comprehensive (income) loss(a)	(13)	43	(20)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss	$ (34)	$ 11	$ (53)

Stockholders' Equity - Common E

Stockholders' Equity - Common Equity (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		2 Months Ended	12 Months Ended			75 Months Ended
	Jan. 17, 2024	Feb. 16, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Feb. 16, 2024	Jan. 18, 2023	Jul. 19, 2017	Dec. 19, 2014
Class of Stock [Line Items]
Common share buy-back program, amount							$ 3,000	$ 2,000
Total value of shares repurchased			$ 522	$ 368	$ 0
Average repurchase price per share			$ 16.56	$ 16.94	$ 0
Per share cash dividend declared for the period			1.13	1.11	1.08
Per share cash dividend paid in the period			$ 1.1250	$ 1.1025	$ 1.0725
Subsequent Event
Class of Stock [Line Items]
Total value of shares repurchased		$ 7				$ 1,472
Average repurchase price per share		$ 16.50				$ 17.09
Remaining repurchase authorization amount		$ 1,500				$ 1,500
Per share cash dividend declared for the period	$ 0.2825
Equity distribution agreement \| Class P
Class of Stock [Line Items]
Value of Stock Available for Sale Under Equity Distribution Agreement									$ 5,000
Share issued (in shares)			0	0	0
Common stock
Class of Stock [Line Items]
Total value of shares repurchased				$ 1
Total number of shares repurchased			32	21	0
Common stock \| Subsequent Event
Class of Stock [Line Items]
Total number of shares repurchased		1				86

Stockholders' Equity - New Acco

Stockholders' Equity - New Accounting Pronouncements (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity	$ 31,729	$ 32,114	$ 31,921	$ 31,838
Additional paid-in capital
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity	$ 41,190	$ 41,673	41,806	$ 41,756
Impact of Adoption of ASU
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity			(11)
Impact of Adoption of ASU \| Additional paid-in capital
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity			(11)
Impact of Adoption of ASU \| Accounting Standards Update 2020-06
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Unamortized debt discount			14
Impact of Adoption of ASU \| Accounting Standards Update 2020-06 \| Additional paid-in capital
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity			$ (11)

Stockholders' Equity - Accumula

Stockholders' Equity - Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	$ 32,114	$ 31,921	$ 31,838
Balance	31,729	32,114	31,921
Net unrealized gains/(losses) on cash flow hedge derivatives
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(164)	(172)	(13)
Other comprehensive (loss) gain before reclassifications	155	(312)	(432)
Losses (gains) reclassified from accumulated other comprehensive loss	(35)	320	273
Net current-period change in accumulated other comprehensive loss	120	8	(159)
Balance	(44)	(164)	(172)
Pension and other postretirement liability adjustments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(238)	(239)	(394)
Other comprehensive (loss) gain before reclassifications	65	1	155
Losses (gains) reclassified from accumulated other comprehensive loss	0	0	0
Net current-period change in accumulated other comprehensive loss	65	1	155
Balance	(173)	(238)	(239)
Total Accumulated other comprehensive loss
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(402)	(411)	(407)
Other comprehensive (loss) gain before reclassifications	220	(311)	(277)
Losses (gains) reclassified from accumulated other comprehensive loss	(35)	320	273
Net current-period change in accumulated other comprehensive loss	185	9	(4)
Balance	$ (217)	$ (402)	$ (411)

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 REVENUES
Revenues	$ 15,334	$ 19,200	$ 16,610
RELATED PARTY OPERATING COSTS, EXPENSES AND OTHER
Other operating expenses	2	(7)	(7)
Accounts receivable	1,588	1,840
All other current assets	207	304
Assets	71,020	70,078
Current portion of debt	4,049	3,385
Accounts Payable, Current	1,366	1,444
Other current liabilities	816	857
Long-term Debt, Excluding Current Maturities	28,067	28,403
Other long-term liabilities and deferred credits	2,615	2,008
Total Liabilities	39,291	37,964
Related Party
RELATED PARTY REVENUES
Revenues	172	172	164
RELATED PARTY OPERATING COSTS, EXPENSES AND OTHER
Costs of sales	132	134	145
Other operating expenses	57	50	$ 52
Accounts receivable	45	39
All other current assets	2	3
Assets	47	42
Current portion of debt	5	6
Accounts Payable, Current	16	19
Other current liabilities	3	8
Long-term Debt, Excluding Current Maturities	137	142
Other long-term liabilities and deferred credits	54	47
Total Liabilities	$ 215	$ 222

Commitments and Contingent Li_2

Commitments and Contingent Liabilities Rights-of-way obligations (Details) $ in Millions	Dec. 31, 2023 USD ($)
ROW
Other Commitments [Line Items]
Contractual Obligation	$ 98

Commitments and Contingent Li_3

Commitments and Contingent Liabilities Contingent Debt (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) investees	Dec. 31, 2022 USD ($) investees
Indirect Guarantee of Indebtedness
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 154	$ 163
Cortez Pipeline Company
Guarantor Obligations [Line Items]
Percentage of Debt Guaranteed	100%	100%
Cortez Pipeline Company \| Indirect Guarantee of Indebtedness
Guarantor Obligations [Line Items]
Number of equity investees subject to contingent obligation \| investees	1	1
Long-term Debt \| Cortez Pipeline Company \| Indirect Guarantee of Indebtedness
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 120	$ 120

Risk Management - Energy Commod

Risk Management - Energy Commodity Price Risk Management (Details) - Short - Energy commodity derivative contracts	12 Months Ended
	Dec. 31, 2023 MMBbls Bcf
Designated as Hedging Instrument \| Crude Oil Fixed Price
Derivative [Line Items]
Net open position	(16.9)
Designated as Hedging Instrument \| Natural Gas Fixed Price
Derivative [Line Items]
Net open position \| Bcf	(61)
Designated as Hedging Instrument \| Natural Gas Basis
Derivative [Line Items]
Net open position \| Bcf	(35.4)
Designated as Hedging Instrument \| NGL Fixed Price
Derivative [Line Items]
Net open position	(0.6)
Not Designated as Hedging Instrument \| Crude Oil Fixed Price
Derivative [Line Items]
Net open position	(1.2)
Not Designated as Hedging Instrument \| Crude Oil Basis
Derivative [Line Items]
Net open position	(4.1)
Not Designated as Hedging Instrument \| Natural Gas Fixed Price
Derivative [Line Items]
Net open position \| Bcf	(7.5)
Not Designated as Hedging Instrument \| Natural Gas Basis
Derivative [Line Items]
Net open position \| Bcf	(101.6)
Not Designated as Hedging Instrument \| NGL Fixed Price
Derivative [Line Items]
Net open position	(0.7)

Risk Management - Interest Rate

Risk Management - Interest Rate Risk Management (Details) $ in Millions	Dec. 31, 2023 USD ($)
Fair Value Hedging \| Fixed-To-Variable Interest Rate Contracts \| Designated as Hedging Instrument
Derivative [Line Items]
Notional amount	$ 6,200
Fair Value Hedging \| Treasury Lock \| Designated as Hedging Instrument
Derivative [Line Items]
Notional amount	1,000
Current Portion of Debt \| Fixed-To-Variable Interest Rate Contracts
Derivative [Line Items]
Principal amount of hedged senior notes	1,450
Long-term Debt \| Fixed-To-Variable Interest Rate Contracts
Derivative [Line Items]
Principal amount of hedged senior notes	$ 4,750

Risk Management - Foreign Curre

Risk Management - Foreign Currency Risk Management (Details) $ in Millions	Dec. 31, 2023 USD ($)
Cash Flow Hedging \| Cross Currency Interest Rate Contract
Derivative [Line Items]
Notional amount	$ 543

Risk Management - Fair Value of

Risk Management - Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Asset derivatives	$ 178	$ 299
Liability derivatives	(395)	(868)
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	140	259
Liability derivatives	(113)	(428)
Foreign currency contracts
Derivatives, Fair Value [Line Items]
Liability derivatives	(4)	(35)
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Asset derivatives	126	195
Liability derivatives	(386)	(687)
Designated as Hedging Instrument \| Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	89	156
Liability derivatives	(104)	(247)
Designated as Hedging Instrument \| Energy commodity derivative contracts \| Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	77	150
Designated as Hedging Instrument \| Energy commodity derivative contracts \| (Fair Value of Derivative Contracts)
Derivatives, Fair Value [Line Items]
Liability derivatives	(75)	(156)
Designated as Hedging Instrument \| Energy commodity derivative contracts \| Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	12	6
Designated as Hedging Instrument \| Energy commodity derivative contracts \| (Other Long-Term Liabilities and Deferred Credits)
Derivatives, Fair Value [Line Items]
Liability derivatives	(29)	(91)
Designated as Hedging Instrument \| Interest rate contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	37	39
Liability derivatives	(278)	(405)
Designated as Hedging Instrument \| Interest rate contracts \| Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Designated as Hedging Instrument \| Interest rate contracts \| (Fair Value of Derivative Contracts)
Derivatives, Fair Value [Line Items]
Liability derivatives	(120)	(144)
Designated as Hedging Instrument \| Interest rate contracts \| Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	37	39
Designated as Hedging Instrument \| Interest rate contracts \| (Other Long-Term Liabilities and Deferred Credits)
Derivatives, Fair Value [Line Items]
Liability derivatives	(158)	(261)
Designated as Hedging Instrument \| Foreign currency contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Liability derivatives	(4)	(35)
Designated as Hedging Instrument \| Foreign currency contracts \| Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Designated as Hedging Instrument \| Foreign currency contracts \| (Fair Value of Derivative Contracts)
Derivatives, Fair Value [Line Items]
Liability derivatives	(2)	(3)
Designated as Hedging Instrument \| Foreign currency contracts \| Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Designated as Hedging Instrument \| Foreign currency contracts \| (Other Long-Term Liabilities and Deferred Credits)
Derivatives, Fair Value [Line Items]
Liability derivatives	(2)	(32)
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Asset derivatives	52	104
Liability derivatives	(9)	(181)
Not Designated as Hedging Instrument \| Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	52	103
Liability derivatives	(9)	(181)
Not Designated as Hedging Instrument \| Energy commodity derivative contracts \| Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	49	80
Not Designated as Hedging Instrument \| Energy commodity derivative contracts \| (Fair Value of Derivative Contracts)
Derivatives, Fair Value [Line Items]
Liability derivatives	(8)	(162)
Not Designated as Hedging Instrument \| Energy commodity derivative contracts \| Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	3	23
Not Designated as Hedging Instrument \| Energy commodity derivative contracts \| (Other Long-Term Liabilities and Deferred Credits)
Derivatives, Fair Value [Line Items]
Liability derivatives	(1)	(19)
Not Designated as Hedging Instrument \| Interest rate contracts \| Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	0	1
Not Designated as Hedging Instrument \| Interest rate contracts \| (Fair Value of Derivative Contracts)
Derivatives, Fair Value [Line Items]
Liability derivatives	$ 0	$ 0

Risk Management - FV Input Leve

Risk Management - FV Input Level - Assets (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Gross amount	$ 178	$ 299
Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	140	259
Contracts available for netting	(16)	(186)
Cash collateral held(b)	0	0
Net amount	124	73
Interest rate contracts
Derivative [Line Items]
Gross amount	38	40
Contracts available for netting	0	0
Cash collateral held(b)	0	0
Net amount	38	40
Level 1 \| Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	65	115
Level 1 \| Interest rate contracts
Derivative [Line Items]
Gross amount	0	0
Level 2 \| Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	75	144
Level 2 \| Interest rate contracts
Derivative [Line Items]
Gross amount	38	40
Level 3 \| Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	0	0
Level 3 \| Interest rate contracts
Derivative [Line Items]
Gross amount	$ 0	$ 0

Risk Management - FV Input Le_2

Risk Management - FV Input Level - Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Gross amount	$ (395)	$ (868)
Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	(113)	(428)
Contracts available for netting	16	186
Collateral posted(b)	(85)	(30)
Net amount	(182)	(272)
Interest rate contracts
Derivative [Line Items]
Gross amount	(278)	(405)
Contracts available for netting	0	0
Collateral posted(b)	0	0
Net amount	(278)	(405)
Foreign currency contracts
Derivative [Line Items]
Gross amount	(4)	(35)
Contracts available for netting	0	0
Collateral posted(b)	0	0
Net amount	(4)	(35)
Level 1 \| Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	(17)	(23)
Level 1 \| Interest rate contracts
Derivative [Line Items]
Gross amount	0	0
Level 1 \| Foreign currency contracts
Derivative [Line Items]
Gross amount	0	0
Level 2 \| Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	(96)	(405)
Level 2 \| Interest rate contracts
Derivative [Line Items]
Gross amount	(278)	(405)
Level 2 \| Foreign currency contracts
Derivative [Line Items]
Gross amount	(4)	(35)
Level 3 \| Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	0	0
Level 3 \| Interest rate contracts
Derivative [Line Items]
Gross amount	0	0
Level 3 \| Foreign currency contracts
Derivative [Line Items]
Gross amount	$ 0	$ 0

Risk Management - FV Hedging Ef

Risk Management - FV Hedging Effect on Income Statements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Cumulative amount of fair value hedging adjustments included in "Debt fair value adjustments"	$ (236)	$ (367)
Designated as Hedging Instrument \| Fair Value Hedging \| Interest rate contracts
Derivative [Line Items]
Location	Interest, net	Interest, net	Interest, net
Gain/(loss) recognized in income on derivatives and related hedged item	$ 138	$ (738)	$ (322)
Designated as Hedging Instrument \| Fair Value Hedging \| Hedged Fixed Rate Debt
Derivative [Line Items]
Location	Interest, net	Interest, net	Interest, net
Gain/(loss) recognized in income on derivatives and related hedged item	$ (132)	$ 743	$ 326
Cumulative amount of fair value hedging adjustments included in "Debt fair value adjustments"	$ (236)

Risk Management - CF Hedging Ef

Risk Management - CF Hedging Effect on the Income Statements (Details) - Designated as Hedging Instrument - Cash Flow Hedging - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	$ 202	$ (404)	$ (563)
Gain/(loss) reclassified from Accumulated OCI into income	47	(415)	(356)
Loss to be reclassified within twelve months	10
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	182	(338)	(475)
Energy commodity derivative contracts \| Revenues—Commodity sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	103	(491)	(271)
Energy commodity derivative contracts \| Costs of sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	(73)	144	20
Energy commodity derivative contracts \| Write-down of hedged inventory
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	0	121	41
Interest rate contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	(10)	7	5
Interest rate contracts \| Interest, net
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	0	0	0
Foreign currency contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	30	(73)	(93)
Foreign currency contracts \| Other, net
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	$ 17	$ (68)	$ (105)

Risk Management - Not Designate

Risk Management - Not Designated as Hedges Effect on Income Statements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ 178	$ (74)	$ (493)
Natural gas, crude and NGL derivative contract settlements
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	58	(11)	(479)
Revenues—Commodity sales \| Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	75	137	(652)
Costs of sales \| Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	100	(190)	152
Earnings from equity investments \| Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	2	(11)	(5)
Interest, net \| Interest rate contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ 1	$ (10)	$ 12

Risk Management - Credit Risks

Risk Management - Credit Risks (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	$ 54
Energy commodity derivative contracts
Credit Derivatives [Line Items]
Letters of credit outstanding	0	$ 0
Initial margin requirement	22
Variation Margin Payable, Derivative	85
Other Current Liabilities \| Contract and Over the Counter \| Energy commodity derivative contracts
Credit Derivatives [Line Items]
Cash margin	$ 63	$ 1

Revenue Recognition - Schedule

Revenue Recognition - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 13,647	$ 18,128	$ 16,154
Leasing services(d)	1,368	1,302	1,266
Derivatives adjustments on commodity sales	178	(354)	(923)
Other	141	124	113
Total other revenues	1,687	1,072	456
Total revenues	15,334	19,200	16,610
Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,537	4,515	4,411
Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,502	2,360	2,114
Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	7,039	6,875	6,525
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,724	6,340	6,480
Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,884	4,913	3,149
Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,608	11,253	9,629
Total revenues	6,786	10,897	8,714
Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	9,152	12,659	11,644
Products Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	3,066	3,418	2,245
Terminals
Disaggregation of Revenue [Line Items]
Total revenues	1,911	1,789	1,712
CO2
Disaggregation of Revenue [Line Items]
Total revenues	1,205	1,334	1,009
Operating Segments \| Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	8,312	12,172	11,871
Leasing services(d)	475	474	473
Derivatives adjustments on commodity sales	285	(26)	(700)
Other	96	66	65
Total other revenues	856	514	(162)
Total revenues	9,168	12,686	11,709
Operating Segments \| Natural Gas Pipelines \| Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,543	3,547	3,402
Operating Segments \| Natural Gas Pipelines \| Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,008	926	746
Operating Segments \| Natural Gas Pipelines \| Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,551	4,473	4,148
Operating Segments \| Natural Gas Pipelines \| Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,651	6,266	6,463
Operating Segments \| Natural Gas Pipelines \| Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,110	1,433	1,260
Operating Segments \| Natural Gas Pipelines \| Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,761	7,699	7,723
Operating Segments \| Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,842	3,201	2,053
Leasing services(d)	200	194	172
Derivatives adjustments on commodity sales	0	(3)	(1)
Other	24	26	21
Total other revenues	224	217	192
Total revenues	3,066	3,418	2,245
Operating Segments \| Products Pipelines \| Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	171	207	259
Operating Segments \| Products Pipelines \| Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,036	962	949
Operating Segments \| Products Pipelines \| Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,207	1,169	1,208
Operating Segments \| Products Pipelines \| Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments \| Products Pipelines \| Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,635	2,032	845
Operating Segments \| Products Pipelines \| Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,635	2,032	845
Operating Segments \| Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,279	1,218	1,150
Leasing services(d)	638	574	565
Derivatives adjustments on commodity sales	0	0	0
Other	0	0	0
Total other revenues	638	574	565
Total revenues	1,917	1,792	1,715
Operating Segments \| Terminals \| Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	819	763	751
Operating Segments \| Terminals \| Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	427	426	375
Operating Segments \| Terminals \| Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,246	1,189	1,126
Operating Segments \| Terminals \| Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Operating Segments \| Terminals \| Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	33	29	24
Operating Segments \| Terminals \| Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	33	29	24
Operating Segments \| CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,240	1,567	1,148
Leasing services(d)	55	60	56
Derivatives adjustments on commodity sales	(107)	(325)	(222)
Other	21	32	27
Total other revenues	(31)	(233)	(139)
Total revenues	1,209	1,334	1,009
Operating Segments \| CO2 \| Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1	1	1
Operating Segments \| CO2 \| Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	40	46	45
Operating Segments \| CO2 \| Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	41	47	46
Operating Segments \| CO2 \| Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	85	94	32
Operating Segments \| CO2 \| Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,114	1,426	1,070
Operating Segments \| CO2 \| Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,199	1,520	1,102
Corporate and Eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(26)	(30)	(68)
Leasing services(d)	0	0	0
Derivatives adjustments on commodity sales	0	0	0
Other	0	0	0
Total other revenues	0	0	0
Total revenues	(26)	(30)	(68)
Corporate and Eliminations \| Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3	(3)	(2)
Corporate and Eliminations \| Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(9)	0	(1)
Corporate and Eliminations \| Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(6)	(3)	(3)
Corporate and Eliminations \| Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(12)	(20)	(15)
Corporate and Eliminations \| Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(8)	(7)	(50)
Corporate and Eliminations \| Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ (20)	$ (27)	$ (65)

Revenue Recognition - Contract

Revenue Recognition - Contract Balances (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2022
Contract Assets
Contract assets balances	$ 34	$ 34	$ 33
Transfer to accounts receivable		23
Contract Liabilities
Contract liability balances	415	415	$ 204
Transfer to revenues		71
Long-Term Transportation and Terminaling Customer
Contract Liabilities
Proceeds from Customers	843
Lease services liability	643	643
Contract liability balances	$ 195	$ 195

Revenue Recognition - Revenue A

Revenue Recognition - Revenue Allocated to Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated Revenue	$ 31,851
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Estimated Revenue	$ 4,687
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Estimated Revenue	$ 4,007
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Estimated Revenue	$ 3,472
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Estimated Revenue	$ 2,874
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Estimated Revenue	$ 2,475
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition
Estimated Revenue	$ 14,336

Reportable Segments Revenues (D

Reportable Segments Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Revenues	$ 15,334	$ 19,200	$ 16,610
Other
Segment Reporting Information [Line Items]
Revenues	(26)	(30)	(68)
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(26)	(30)	(68)
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Revenues	9,152	12,659	11,644
Natural Gas Pipelines \| Operating Segments
Segment Reporting Information [Line Items]
Revenues	9,168	12,686	11,709
Natural Gas Pipelines \| Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(16)	(27)	(65)
Products Pipelines
Segment Reporting Information [Line Items]
Revenues	3,066	3,418	2,245
Products Pipelines \| Operating Segments
Segment Reporting Information [Line Items]
Revenues	3,066	3,418	2,245
Terminals
Segment Reporting Information [Line Items]
Revenues	1,911	1,789	1,712
Terminals \| Operating Segments
Segment Reporting Information [Line Items]
Revenues	1,917	1,792	1,715
Terminals \| Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(6)	(3)	(3)
CO2
Segment Reporting Information [Line Items]
Revenues	1,205	1,334	1,009
CO2 \| Operating Segments
Segment Reporting Information [Line Items]
Revenues	1,209	1,334	1,009
CO2 \| Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (4)	$ 0	$ 0
Revenue Benchmark \| Customer Concentration Risk
Segment Reporting Information [Line Items]
Concentration Risk, Percentage Meet Certain Threshold	10%	10%	10%

Reportable Segments Operating e

Reportable Segments Operating expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Operating expenses	$ 8,166	$ 12,351	$ 9,287
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Operating expenses	4,700	8,562	7,000
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Operating expenses	2,024	2,391	1,239
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Operating expenses	896	853	793
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Operating expenses	550	554	289
Other
Segment Reporting Information [Line Items]
Operating expenses	$ (4)	$ (9)	$ (34)

Reportable Segments Other expen

Reportable Segments Other expense (income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Other expense (income)	$ (13)	$ (39)	$ 1,617
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other expense (income)	(12)	(13)	1,597
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Other expense (income)	4	(12)	0
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Other expense (income)	(2)	(14)	32
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Other expense (income)	0	(1)	(8)
Other
Segment Reporting Information [Line Items]
Other expense (income)	$ (3)	$ 1	$ (4)

Reportable Segments Depreciatio

Reportable Segments Depreciation, depletion and amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
DD&A	$ 2,250	$ 2,186	$ 2,135
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
DD&A	1,041	1,096	1,099
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
DD&A	367	336	335
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
DD&A	493	458	440
Operating Segments \| CO2
Segment Reporting Information [Line Items]
DD&A	325	272	236
Other
Segment Reporting Information [Line Items]
DD&A	$ 24	$ 24	$ 25

Reportable Segments Earnings (l

Reportable Segments Earnings (loss) from equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments	$ 772	$ 728	$ 513
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments	746	650	435
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments	(6)	33	34
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments	9	14	15
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments	$ 23	$ 31	$ 29

Reportable Segments Other, net-

Reportable Segments Other, net-income(expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Other, net-income (expense)	$ (37)	$ 55	$ 282
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other, net-income (expense)	26	(19)	216
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Other, net-income (expense)	1	0	1
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Other, net-income (expense)	8	8	3
Other
Segment Reporting Information [Line Items]
Other, net-income (expense)	$ (72)	$ 66	$ 62

Reportable Segments Segment ear

Reportable Segments Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
DD&A	$ (2,250)	$ (2,186)	$ (2,135)
Amortization of excess cost of equity investments	(66)	(75)	(78)
General and administrative and corporate charges	759	593	623
Interest, net	(1,797)	(1,513)	(1,492)
Income tax expense	(715)	(710)	(369)
Net income (loss)	2,486	2,625	1,850
Operating Segments
Segment Reporting Information [Line Items]
Net income (loss)	8,073	7,702	6,547
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
DD&A	(1,041)	(1,096)	(1,099)
Net income (loss)	5,282	4,801	3,815
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
DD&A	(367)	(336)	(335)
Net income (loss)	1,062	1,107	1,064
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
DD&A	(493)	(458)	(440)
Net income (loss)	1,040	975	908
Operating Segments \| CO2
Segment Reporting Information [Line Items]
DD&A	(325)	(272)	(236)
Net income (loss)	689	819	760
Other
Segment Reporting Information [Line Items]
DD&A	$ (24)	$ (24)	$ (25)

Reportable Segments Capital exp

Reportable Segments Capital expenditures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Capital Expenditures	$ 2,317	$ 1,621	$ 1,281
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Capital Expenditures	1,299	666	570
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Capital Expenditures	221	0	122
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Capital Expenditures	406	552	332
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Capital Expenditures	355	371	230
Other
Segment Reporting Information [Line Items]
Capital Expenditures	$ 36	$ 32	$ 27

Reportable Segments Investments

Reportable Segments Investments (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Investments	$ 7,874	$ 7,653
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments	7,273	6,993
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Investments	390	445
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Investments	130	128
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Investments	$ 81	$ 87

Reportable Segments Other Intan

Reportable Segments Other Intangibles, Net (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Other intangibles, net	$ 1,957	$ 1,809
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other intangibles, net	742	439
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Other intangibles, net	687	777
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Other intangibles, net	26	38
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Other intangibles, net	$ 502	$ 555

Reportable Segments Assets (Det

Reportable Segments Assets (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Assets	$ 71,020	$ 70,078
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets	49,883	47,978
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Assets	8,781	8,985
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Assets	8,235	8,357
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Assets	3,497	3,449
Other
Segment Reporting Information [Line Items]
Assets	$ 624	$ 1,309

Reportable Segments Geographica

Reportable Segments Geographical information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Revenues	$ 15,334	$ 19,200	$ 16,610
Long-term assets, excluding goodwill and other intangibles	46,400	44,501	44,995
U.S.
Segment Reporting Information [Line Items]
Revenues	15,255	19,036	16,479
Long-term assets, excluding goodwill and other intangibles	46,328	44,425	44,916
Canada
Segment Reporting Information [Line Items]
Long-term assets, excluding goodwill and other intangibles	0	1	1
Mexico and other foreign
Segment Reporting Information [Line Items]
Revenues	79	164	131
Long-term assets, excluding goodwill and other intangibles	$ 72	$ 75	$ 78

Leases - Lessee (Details)

Leases - Lessee (Details) - USD ($) $ in Millions	12 Months Ended
Leases - Lessee (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lease, Cost [Abstract]
Operating leases	$ 71	$ 62	$ 60
Short-term and variable leases	127	101	109
Total lease cost	198	163	169
Lessee, Operating Lease, Description [Abstract]
Operating cash flows from operating leases	(157)	(132)	(137)
Investing cash flows from operating leases	(41)	(31)	(32)
ROU assets obtained in exchange for operating lease obligations, net of retirements	56	22	59
Amortization of ROU assets	$ 58	$ 50	$ 47
Weighted average remaining lease term	8 years 8 months 19 days	9 years 9 months 18 days	10 years 4 months 20 days
Weighted average discount rate	4.59%	4.26%	3.95%
Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Deferred charges and other assets	Deferred charges and other assets
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities	Other current liabilities
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other long-term liabilities and deferred credits	Other long-term liabilities and deferred credits
ROU assets	$ 285	$ 287
Short-term lease liability	55	47
Long-term lease liability	230	$ 240
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2024	67
2025	56
2026	40
2027	33
2028	25
Thereafter	145
Total lease payments	366
Less: Interest	(81)
Present value of lease liabilities	$ 285

Litigation and Environmental -

Litigation and Environmental - Other Commercial Matters (Details) - Pending Litigation $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) claims
Freeport LNG Marketing, LLC Case
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value \| $	$ 104
Pension Plan Litigation
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number \| claims	6

Litigation and Environmental _2

Litigation and Environmental - General (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Loss Contingency, Information about Litigation Matters [Abstract]
Estimated Litigation Liability	$ 23	$ 70

Litigation and Environmental _3

Litigation and Environmental - Portland (Details) - Portland Harbor Superfund Site, Willamette River, Portland, Oregon $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) Terminals Parties
Environmental Protection Agency \| KMLT
Site Contingency [Line Items]
Estimated Remedy Implementation Period	10 years
Number of Parties Involved In Site Cleanup Allocation Negotiations \| Parties	90
Number of Liquid Terminals \| Terminals	2
Site Contingency, Loss Exposure Not Accrued, Best Estimate \| $	$ 2,800
Environmental Protection Agency \| KMBT
Site Contingency [Line Items]
Number of Liquid Terminals \| Terminals	2
State And Federal Trustees \| KMLT
Site Contingency [Line Items]
Loss Contingency, Damages Sought, Value \| $	$ 5

Litigation and Environmental _4

Litigation and Environmental - Lower Passaic River (Details) - Environmental Protection Agency $ in Millions			12 Months Ended
	Oct. 04, 2021 USD ($)	Mar. 04, 2016 USD ($)	Dec. 31, 2023	Jan. 17, 2024 Parties	Dec. 16, 2022 USD ($) Parties
Lower Passaic River Study Area \| EPA Proposed Consent Decree
Site Contingency [Line Items]
Number of Parties Involved in Proposed Consent Decree \| Parties					85
Proposed Environmental Remediation Settlement \| $					$ 150
Lower Passaic River Study Area \| EPA Complaint Filed \| Subsequent Event
Site Contingency [Line Items]
Number of Parties Included in Complaint \| Parties				82
Lower Passaic River Study Area \| Pending Litigation \| EPA preferred alternative estimate
Site Contingency [Line Items]
Site Contingency, Loss Exposure Not Accrued, Best Estimate \| $		$ 1,700
Lower Passaic River Study Area \| Pending Litigation \| Clean Up Implementation
Site Contingency [Line Items]
Estimated Remedy Implementation Period			6 years
Lower Passaic River Study Area \| Litigation Dismissed \| EPA Complaint Filed \| Subsequent Event
Site Contingency [Line Items]
Number of Parties Included in Complaint \| Parties				3
Upper Passaic River Study Area, Upper Portion \| Pending Litigation
Site Contingency [Line Items]
Site Contingency, Loss Exposure Not Accrued, Best Estimate \| $	$ 440

Litigation and Environmental _5

Litigation and Environmental - Louisiana Governmental (Details) - Coastal Zone	Mar. 29, 2019 Parties	Nov. 08, 2013 Parties	Dec. 31, 2023 cases
Judicial District of Louisiana
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number			40
TGP \| Judicial District of Louisiana
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number			1
TGP \| Parish of Plaquemines, Louisiana
Loss Contingencies [Line Items]
Loss Contingency, Number of Defendants \| Parties		17
SNG \| Judicial District of Louisiana
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number			1
SNG \| Parish of Orleans, Louisiana
Loss Contingencies [Line Items]
Loss Contingency, Number of Defendants \| Parties	10

Litigation and Environmental _6

Litigation and Environmental - Environmental Matters - General (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Loss Contingency, Information about Litigation Matters [Abstract]
Accrual for Environmental Loss Contingencies	$ 199	$ 221
Recorded Third-Party Environmental Recoveries Receivable	$ 11	$ 12
Environmental Loss Contingency, Statement Of Financial Position [Extensible Enumeration], Not Disclosed Flag	true	true

Recent Accounting Pronoucemen_2

Recent Accounting Pronoucements (Details) $ in Millions	Dec. 31, 2023 USD ($)
Fixed-To-Variable Interest Rate Contracts \| Fair Value Hedging \| Designated as Hedging Instrument
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Notional amount	$ 6,200