Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2022	Feb. 07, 2023	Jun. 30, 2022
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Period End Date	Dec. 31, 2022
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
Entity Shell Company	false
Entity Public Float			$ 33,112,481,840
Entity Common Stock, Shares Outstanding		2,248,003,224
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	12 Months Ended
Audit Information	Dec. 31, 2022
Auditor [Abstract]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Houston, Texas
Auditor Firm ID	238

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues
Total Revenues	$ 19,200	$ 16,610	$ 11,700
Operating Costs, Expenses and Other
Costs of sales	9,255	6,493	2,545
Operations and maintenance	2,655	2,368	2,475
Depreciation, depletion and amortization	2,186	2,135	2,164
General and administrative	637	655	648
Taxes, other than income taxes	441	426	378
(Gain) loss on divestitures and impairments, net (Note 4)	(32)	1,624	1,932
Other income, net	(7)	(7)	(2)
Total Operating Costs, Expenses and Other	15,135	13,694	10,140
Operating Income	4,065	2,916	1,560
Other Income (Expense)
Earnings from equity investments	803	591	780
Amortization of excess cost of equity investments	(75)	(78)	(140)
Interest, net	(1,513)	(1,492)	(1,595)
Other, net (Note 3)	55	282	56
Total Other Expense	(730)	(697)	(899)
Income Before Income Taxes	3,335	2,219	661
Income Tax Expense	(710)	(369)	(481)
Net Income	2,625	1,850	180
Net Income Attributable to Noncontrolling Interests	(77)	(66)	(61)
Net Income Attributable to Kinder Morgan, Inc.	$ 2,548	$ 1,784	$ 119
Class P Common Stock
Basic Earnings Per Share	$ 1.12	$ 0.78	$ 0.05
Diluted Earnings Per Share	$ 1.12	$ 0.78	$ 0.05
Basic Weighted Average Shares Outstanding	2,258	2,266	2,263
Diluted Weighted Average Shares Outstanding	2,258	2,266	2,263
Services
Revenues
Total Revenues	$ 8,145	$ 7,757	$ 7,618
Commodity sales
Revenues
Total Revenues	10,897	8,714	3,891
Other
Revenues
Total Revenues	$ 158	$ 139	$ 191

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Net income	$ 2,625	$ 1,850	$ 180
Other comprehensive income (loss), net of tax
Net unrealized (loss) gain from derivative instruments (net of taxes of $92, $131, and $(75), respectively)	(312)	(432)	249
Reclassification into earnings of net derivative instruments loss (gain) to net income (net of taxes of $(95), $(83), and $78, respectively)	320	273	(255)
Benefit plan adjustments (net of taxes of $(1), $(47), and $19, respectively)	1	155	(68)
Total other comprehensive income (loss)	9	(4)	(74)
Comprehensive income	2,634	1,846	106
Comprehensive income attributable to noncontrolling interests	(77)	(66)	(61)
Comprehensive income attributable to KMI	$ 2,557	$ 1,780	$ 45

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Change in fair value of derivative instruments, tax	$ 92	$ 131	$ (75)
Reclassification of change in fair value of derivative instruments to net income, tax	(95)	(83)	78
Benefit plan adjustments, tax	$ (1)	$ (47)	$ 19

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents	$ 745	$ 1,140
Restricted deposits	49	7
Accounts receivable	1,840	1,611
Fair value of derivative contracts	231	220
Inventories	634	562
Other current assets	304	289
Total current assets	3,803	3,829
Property, plant and equipment, net	35,599	35,653
Investments	7,653	7,578
Goodwill	19,965	19,914
Other intangible, net	1,809	1,678
Deferred income taxes	0	115
Deferred charges and other assets	1,249	1,649
Total Assets	70,078	70,416
Current liabilities
Current portion of debt	3,385	2,646
Accounts payable	1,444	1,259
Accrued interest	515	504
Accrued taxes	264	270
Fair value of derivative contracts	465	178
Other current liabilities	857	964
Total current liabilities	6,930	5,821
Long-term debt
Outstanding	28,288	29,772
Debt fair value adjustments	115	902
Total long-term debt	28,403	30,674
Deferred income taxes	623	0
Other long-term liabilities and deferred credits	2,008	2,000
Total long-term liabilities and deferred credits	31,034	32,674
Total Liabilities	37,964	38,495
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, 2,247,681,626 and 2,267,391,527 shares, respectively, issued and outstanding	22	23
Additional paid-in capital	41,673	41,806
Accumulated deficit	(10,551)	(10,595)
Accumulated other comprehensive loss	(402)	(411)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,742	30,823
Noncontrolling interests	1,372	1,098
Total Stockholders’ Equity	32,114	31,921
Total Liabilities and Stockholders’ Equity	$ 70,078	$ 70,416

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
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)	2,247,681,626	2,267,391,527
Common stock, shares outstanding (in shares)	2,247,681,626	2,267,391,527

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash Flows From Operating Activities
Net income	$ 2,625	$ 1,850	$ 180
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	2,186	2,135	2,164
Deferred income taxes	692	355	345
Amortization of excess cost of equity investments	75	78	140
(Gain) loss on divestitures and impairments, net (Note 4)	(32)	1,624	1,932
Gain on sale of interest in equity investment (Note 3)	0	(206)	0
Earnings from equity investments	(803)	(591)	(780)
Distributions of equity investment earnings	725	720	633
Pension contributions net of noncash pension benefit expenses	(50)	(39)	(90)
Changes in components of working capital, net of the effects of acquisitions and dispositions
Accounts receivable	(220)	(265)	88
Inventories	(183)	(202)	16
Other current assets	(51)	(109)	49
Accounts payable	161	387	(19)
Accrued interest, net of interest rate swaps	50	(17)	(51)
Accrued taxes	(5)	2	(93)
Other current liabilities	(10)	146	(81)
Rate reparations, refunds and other litigation reserve adjustments	(190)	(57)	40
Other, net	(3)	(103)	77
Net Cash Provided by Operating Activities	4,967	5,708	4,550
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired (Note 3)	(487)	(1,547)	(16)
Capital expenditures	(1,621)	(1,281)	(1,707)
Sales of property, plant and equipment, investments, and other net assets, net of removal costs	6	406	1,069
Contributions to investments	(229)	(38)	(386)
Distributions from equity investments in excess of cumulative earnings	156	163	154
Other, net	0	(8)	(25)
Net Cash Used in Investing Activities	(2,175)	(2,305)	(911)
Cash Flows From Financing Activities
Issuances of debt	9,058	5,959	3,888
Payments of debt	(9,735)	(6,831)	(3,996)
Debt issue costs	(25)	(27)	(25)
Dividends (Note 11)	(2,504)	(2,443)	(2,362)
Repurchases of shares	(368)	0	(50)
Proceeds from sale of noncontrolling interests (Note 3)	557	0	0
Contributions from investment partner and noncontrolling interests	2	4	14
Distributions to investment partner	0	(82)	(79)
Distributions to noncontrolling interests	(116)	(20)	(15)
Other, net	(14)	(25)	(13)
Net Cash Used in Financing Activities	(3,145)	(3,465)	(2,638)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	0	0	(1)
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Deposits	(353)	(62)	1,000
Cash, Cash Equivalents and Restricted Deposits, beginning of period	1,147	1,209	209
Cash, Cash Equivalents and Restricted Deposits, end of period	794	1,147	1,209
Cash and Cash Equivalents, beginning of period	1,140	1,184	185
Restricted Deposits, beginning of period	7	25	24
Cash and Cash Equivalents, end of period	745	1,140	1,184
Restricted Deposits, end of period	49	7	25
Noncash Investing and Financing Activities
Increase in property, plant and equipment from both accruals and contractor retainage	72	74
ROU assets and operating lease obligations recognized (Note 17)	22	59	20
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,460	1,529	1,661
Cash paid during the period for income taxes, net	$ 13	$ 10	$ 227

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Millions, $ in Millions	Total	Common stock	Additional paid-in capital	Accumulated deficit	Accumulated other comprehensive loss	Stockholders’ equity attributable to KMI	Non-controlling interests	Impact of Adoption of ASU	Impact of Adoption of ASU Additional paid-in capital	Impact of Adoption of ASU Stockholders’ equity attributable to KMI	Adjusted Balance	Adjusted Balance Common stock	Adjusted Balance Additional paid-in capital	Adjusted Balance Accumulated deficit	Adjusted Balance Accumulated other comprehensive loss	Adjusted Balance Stockholders’ equity attributable to KMI	Adjusted Balance Non-controlling interests
Balance at Dec. 31, 2019	$ 34,086	$ 23	$ 41,745	$ (7,693)	$ (333)	$ 33,742	$ 344
Balance (shares) at Dec. 31, 2019		2,265
Repurchases of shares	(50)		(50)			(50)
Repurchases of shares (shares)		(4)
Restricted shares	61		61			61
Restricted shares (shares)		3
Net income	180			119		119	61
Dividends	(2,362)			(2,362)		(2,362)
Distributions	(15)					0	(15)
Contributions	11					0	11
Other	1					0	1
Other comprehensive (loss) income	(74)				(74)	(74)
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	$ 23	41,806	(10,595)	(411)	30,823	1,098	$ (11)	$ (11)	$ (11)	$ 31,910	$ 23	$ 41,795	$ (10,595)	$ (411)	$ 30,812	$ 1,098
Balance (shares) at Dec. 31, 2021		2,267										2,267
Accounting Standards Update [Extensible List]	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

General (Notes)

12 Months Ended

Dec. 31, 2022

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, renewable fuels, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, renewable fuel feedstocks, chemicals, ethanol, metals and petroleum coke.

Summary of Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2022

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, 2022 and 2021 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 CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected.

•The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected.

•When CO2 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 CO2 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,
	2022		2021
	(In millions)
Balance at beginning of period	$	196	$	215
Accretion expense	12		7
New obligations	2		6
Settlements	(6)		(8)
Revisions to previous estimates	—		(24)
Balance at end of period(a)	$	204	$	196

(a)Balances at December 31, 2022 and 2021 include $3 million and $4 million, respectively, included within “Other current liabilities” on our accompanying consolidated balance sheets.

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 is 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, 2022 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (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 circumstance 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, 2022 and 2021 and our amortization expense for the years ended December 31, 2022, 2021 and 2020:


	Weighted Average Amortization Period (years)	December 31,
		2022		2021
		(In millions)
Gross	11.2	$	3,382	$	3,036
Accumulated amortization		(1,573)		(1,358)
Net carrying amount		$	1,809	$	1,678


	December 31,
	2022		2021		2020
	(In millions)
Amortization expense	$	253	$	237	$	212

Our estimated amortization expense for our intangible assets for each of the next five fiscal years is:


	2023		2024		2025		2026		2027
	(In millions)
Estimated amortization expenses	$	201	$	175	$	170	$	168	$	167

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, CO2 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.

Cost of Sales

Cost 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 CO2 producing activities, such as those in our CO2 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 CO2 producing activities included within operations and maintenance totaled $367 million, $180 million and $319 million for the years ended December 31, 2022, 2021 and 2020, respectively.

Environmental Matters

We capitalize or expense, as appropriate, environmental expenditures. 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. Generally, our accrual of these environmental liabilities coincides with either our completion of a feasibility study or our 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 could impact our assets or operations. These reviews 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. These revisions are reflected in our income in the period in which they are reasonably determinable.

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 to 48 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception or upon modification. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.

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,” 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

We capitalize financing costs incurred with new borrowings and amortize the costs over the contractual term of the related obligations.

Redeemable Noncontrolling Interest

Through December 14, 2021, we had a redeemable noncontrolling interest which represented the interest in one of our consolidated subsidiaries, ELC, not owned by us, and which in certain limited circumstances, the partner had the right to relinquish its interest in the subsidiary and redeem its cumulative contributions, net of distributions it had received through date of the amended operating agreement. Distributions paid to EIG 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 statements of cash flows. On December 14, 2021, the ownership agreement was modified such that EIG’s interest was no longer contingently redeemable, and the balance was reclassified to “Noncontrolling Interests.” Net income attributable to redeemable noncontrolling interest was $58 million and $54 million for the years ended December 31, 2021 and 2020, respectively, and is included in “Net Income Attributable to Noncontrolling Interests” in our accompanying consolidated statements 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 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.

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

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.

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 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.

The following table summarizes our regulatory asset and liability balances as of December 31, 2022 and 2021:


	December 31,
	2022		2021
	(In millions)
Current regulatory assets	$	73	$	66
Non-current regulatory assets	183		220
Total regulatory assets(a)	$	256	$	286

Current regulatory liabilities	$	50	$	32
Non-current regulatory liabilities	175		163
Total regulatory liabilities(b)	$	225	$	195

(a)Regulatory assets as of December 31, 2022 include (i) $110 million of unamortized losses on disposal of assets; (ii) $45 million income tax gross up on equity AFUDC; and (iii) $101 million of other assets, including amounts related to fuel tracker arrangements. Approximately $143 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, 2022 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 $110 million of the $175 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 15 years, while the remaining $65 million is not subject to a defined period.

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.

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,
	2022		2021		2020
	(In millions, except per share amounts)
Net Income Available to Stockholders	$	2,548	$	1,784	$	119
Participating securities:
Less: Net Income Allocated to Restricted stock awards(a)	(13)		(14)		(13)
Net Income Allocated to Class P Stockholders	$	2,535	$	1,770	$	106

Basic Weighted Average Shares Outstanding	2,258		2,266		2,263
Basic Earnings Per Share	$	1.12	$	0.78	$	0.05

(a)As of December 31, 2022, there were approximately 13 million restricted stock awards outstanding.

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,
	2022	2021	2020
	(In millions on a weighted average basis)
Unvested restricted stock awards	13	13	13
Convertible trust preferred securities	3	3	3

Acquisitions and Divestitures (Notes)

12 Months Ended

Dec. 31, 2022

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.

As of December 31, 2022, our allocation of the purchase price for significant acquisitions completed during the years ended December 31, 2022 and 2021 are detailed below:


					Assignment of Purchase Price
Ref	Date	Acquisition	Purchase price		Current assets		Property, plant & equipment		Other long-term assets		Current liabilities		Long-term liabilities		Resulting goodwill
			(In millions)
(1)	8/22	North American Natural Resources	$	132	$	2	$	5	$	64	$	—	$	—	$	61
(2)	7/22	Mas Ranger, LLC	358		9		31		320		(2)		—		—
(3)	8/21	Kinetrex	318		18		49		272		(6)		(68)		53
(4)	7/21	Stagecoach	1,258		53		1,187		24		(6)		—		—

(1) 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 preliminary 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 CO2 business segment.

(2) 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 preliminary purchase price adjustments for working capital. Other long-term assets within the preliminary 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 CO2 business segment.

(3) Kinetrex Acquisition

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex from an affiliate of Parallel49 Equity for $318 million, including purchase price adjustments for working capital. Deferred charges and other 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 is a supplier of LNG in the Midwest and a producer and supplier of

RNG under long-term contracts to transportation service providers. Kinetrex has 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 CO2 business segment.

(4) 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. Deferred charges and other within the purchase price allocation relates to customer contracts with a weighted average amortization period of less than 2 years. The determination of fair value utilized valuation methodologies including discounted cash flows and the cost approach. The significant assumptions made in performing these valuations include a discount rate of approximately 12%, future revenues and replacement costs. To compute estimated future cash flows for Stagecoach, transportation and storage revenue forecasts were developed based on projected demand and future rates for services in the Northeast market areas.

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, 2021 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 sheet:


	December 31, 2022
	(In millions)
Assets
Current assets	$	34
Property, plant and equipment, net	1,197
Deferred charges and other assets	6

Liabilities
Current liabilities	$	15
Other long-term liabilities and deferred credits	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. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

Gains and Losses on Divestitures, Impairments and Other Write-downs (Notes)

12 Months Ended

Dec. 31, 2022

Impairments [Abstract]

Impairments, Divestitures And Other Write-downs

4. Gains and Losses on Divestitures, Impairments and Other Write-downs

During the years ended December 31, 2022, 2021, and 2020, we recorded net pre-tax (gains) losses of $(32) million, $1,535 million and $1,922 million, respectively, reflecting net (gains) losses 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. The year ended December 31, 2020 amount primarily includes pre-tax goodwill and long-lived asset impairment losses of $1,600 million and $376 million, respectively.

We recognized the following non-cash pre-tax (gains) losses on divestitures, impairments or other write-downs on assets and equity investments during the years ended December 31, 2022, 2021, and 2020:


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Natural Gas Pipelines
Impairments of long-lived assets(a)	$	—	$	1,600	$	—
Impairment of goodwill(b)	—		—		1,000
Gain on sale of interest in NGPL Holdings(c)	—		(206)		—
Loss on write-down of related party note receivable(d)	—		117		—
(Gains) losses on divestitures of long-lived assets	(10)		(1)		10


Products Pipelines
Impairments of long-lived assets	—		—		21
Gain on divestiture of long-lived asset	(12)		—		—

Terminals
Impairments of long-lived assets	—		34		5
(Gains) losses on divestitures of long-lived assets(e)	(9)		2		(54)
Gain on sale of equity investment interests	—		—		(10)
CO2
Impairment of goodwill(b)	—		—		600
Impairments of long-lived assets(f)	—		—		350
Gains on divestitures of long-lived assets	(1)		(8)		—

Other gains on divestitures of long-lived assets	—		(3)		—
Pre-tax (gains) losses on divestitures, impairments and other write-downs, net	$	(32)	$	1,535	$	1,922

(a)2021 amount represents non-cash impairments associated with our South Texas gathering and processing assets.

(b)2020 amount represent non-cash goodwill impairments associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units (see “—Impairments—Goodwill” below).

(c)See Note 3.

(d)See “—Investment in Ruby” below for a further discussion.

(e)2020 amount includes a $55 million gain related to the sale of our Staten Island terminal.

(f)2020 amount represents a non-cash impairment of oil and gas properties.

Impairments

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.

During the first half of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented a triggering event that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO2 business segment which resulted in a non-cash impairment of long-lived assets within our CO2 business segment shown in the above table during the year ended December 31, 2020.

As of March 31, 2020, for our CO2 assets, the computation of estimated undiscounted future cash flows included the following:

•To compute estimated future cash flows for our oil and gas producing properties, we used our reserve engineer specialists to estimate future oil and gas production volumes. These estimates of future oil and gas production volumes are based upon historical performance along with adjustments for expected crude oil and natural gas field development. In calculating future cash flows, management utilized estimates of commodity prices based on a March 31, 2020 NYMEX forward curve adjusted for the impact of our existing sales contracts to determine the applicable net crude oil and NGL pricing for each property. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.

•To compute estimated future cash flows for our CO2 source and transportation assets, throughput and production volume forecasts were developed based on projected demand for our CO2 services based upon management’s projections of the availability of CO2 supply and the future demand for CO2 for use in enhanced oil recovery projects. The CO2 pricing assumption was a function of the March 31, 2020 NYMEX forward curve adjusted for the impact of existing sales contracts to determine the applicable net CO2 pricing. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.

For certain oil and gas properties that failed the first step, we used a discounted cash flow analysis to estimate fair value. We applied a 10.5% discount rate, which we believe represented the estimated weighted average cost of capital of a theoretical market participant. Based on step two of our long-lived assets impairment test, we recognized $350 million of impairments on those oil and gas producing properties where the total carrying value exceeded its total estimated fair market value as of March 31, 2020.

Goodwill

The fair value estimates used in our goodwill impairment test are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates using market and income approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect to market multiples, comparable sales transactions, weighted average costs of capital, general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding future cash flows based on production growth rate assumptions, terminal values and discount rates. Prior to 2022, we used primarily a market approach and, in some instances where deemed necessary, also used discounted cash flow analyses to determine the fair value of our assets. We used discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular reporting unit.

During the first quarter of 2020, we conducted interim impairment tests of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated reporting units, and during the second quarter 2020, we conducted our annual impairment test of goodwill for all of our reporting units which resulted in non-cash impairments of goodwill within our CO2 and Natural Gas Pipelines business segments during the year ended December 31, 2020 as shown in the table above.

•Our May 31, 2020 goodwill impairment tests of the Products Pipelines, Products Pipelines Terminals, Natural Gas Pipelines Regulated and CO2 reporting units indicated that their fair values exceeded their carrying values. The results of our impairment analyses for our Products Pipelines, Terminals and CO2 reporting units, determined that each of the three reporting unit’s fair value was in excess of carrying value by less than 10%. For the Products Pipelines and Terminals reporting units, we used the market approach with assumptions similar to those described below for the Natural Gas Pipelines Non-Regulated reporting unit. For our May 31, 2020 goodwill impairment test of the CO2 reporting unit we used the income approach with assumptions similar to those used for its March 31, 2020 goodwill impairment test.

•In regards to our Natural Gas Pipelines Non-Regulated reporting unit, while no impairment was required as of March 31, 2020, it experienced a sharp decline in customer demand for its services during the second quarter of 2020. This represented a timing lag from the initial economic decline impacts resulting from the severe downturn in the upstream energy industry, including our CO2 business, whereby oil and gas producing companies accelerated their shut down of wells and reduced production during the second quarter which consequently adversely impacted the demand for our midstream services. In addition, continued diminished (i) current and expected future commodity pricing and (ii) peer group market capitalization values provided further indicators that an impairment of goodwill had occurred for this reporting unit during the second quarter.

Our May 31, 2020 goodwill impairment test for the Natural Gas Pipelines Non-Regulated reporting unit utilized a weighted average of a market approach (25%) and income approach (75%) to estimate its fair value. We gave higher weighting to the income approach as we believe it was more representative of the value that would be received from a market participant.

The market approach was based on enterprise value (EV) to estimated 2020 EBITDA multiples for a selected number of peer group midstream companies with comparable operations and economic characteristics. We estimated the median EV to EBITDA multiple to be approximately 10x without consideration of any control premium. The income approach we used to determine fair value included an analysis of estimated discounted cash flows based on 6.5 years of projections and application of an exit multiple based on management’s expectations of a discount rate and exit multiple that would be applied by a theoretical market participant and for market transactions of comparable assets. We applied an approximate 8% discount rate to the undiscounted cash flow amounts which represents our estimate of the weighted average cost of capital of a theoretical market participant. The discounted cash flows included various assumptions on forecasted commodity throughput volumes and contract prices for each underlying asset within the reporting unit. The fair value based on a weighting of the market and income approaches resulted in an implied EV to 2020 EBITDA multiple valuation of approximately 11x. Management believes this is a reasonable estimate of fair value based on comparable sales transactions and the fact that it implies a reasonable control premium.

The results of the Natural Gas Pipelines Non-Regulated reporting unit goodwill impairment analysis was a partial impairment of goodwill of approximately $1,000 million as of May 31, 2020.

•For our March 31, 2020 interim goodwill impairment test of the CO2 reporting unit, we applied an income approach to evaluate its fair value based on the present value of its cash flows that it is expected to generate in the future. Due to the uncertainty and volatility in market conditions within its peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020.

In determining the fair value for our CO2 reporting unit, we applied a 9.25% discount rate to the undiscounted cash flow amounts computed in the long-lived asset impairment analyses described above. The discount rate we used represents our estimate of the weighted average cost of capital of a theoretical market participant. The result of our goodwill analysis was a partial impairment of goodwill in our CO2 reporting unit of approximately $600 million as of March 31, 2020.

The fair value estimates used in the long-lived asset and goodwill tests were primarily based on Level 3 inputs of the fair value hierarchy.

Economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as sustained low crude oil demand and continued low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets, which will have an adverse effect on the demand for services provided by our four business segments. Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.

As conditions warrant, we routinely evaluate our assets for potential triggering events that could impact the fair value of certain assets or our ability to recover the carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future volume expectations, current and future commodity prices, discount rates, regulatory environment, as well as general economic conditions and the related demand for products handled or transported by our assets. Because certain of our assets have been written down to fair value, or its fair value is close to carrying value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.

For additional information regarding changes in our goodwill, see Note 8.

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 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 sheets associated with Ruby as of December 31, 2022 or 2021.

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)

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Income Taxes


5.			Income Taxes

The components of “Income Before Income Taxes” are as follows:


	Year Ended December 31,
	2022		2021		2020
	(In millions)
U.S.	$	3,318	$	2,217	$	663
Foreign	17		2		(2)
Total Income Before Income Taxes	$	3,335	$	2,219	$	661

Components of the income tax provision applicable for federal, foreign and state taxes are as follows:


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Current tax expense (benefit)
Federal	$	—	$	—	$	(20)
State	14		11		9
Foreign	4		3		147
Total	18		14		136
Deferred tax expense (benefit)
Federal	642		334		440
State	50		21		49
Foreign	—		—		(144)
Total	692		355		345
Total tax provision	$	710	$	369	$	481

The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:


	Year Ended December 31,
	2022				2021				2020
	(In millions, except percentages)
Federal income tax	$	700	21.0	%	$	466	21.0	%	$	139	21.0	%
Increase (decrease) as a result of:
Net effects of noncontrolling interests	(16)		(0.5)	%	(14)		(0.6)	%	(13)		(2.0)	%
State income tax, net of federal benefit	69		2.0	%	50		2.2	%	52		7.9	%


Dividend received deduction	(36)		(1.1)	%	(46)		(2.1)	%	(27)		(4.1)	%

Release of valuation allowance	—		—	%	(38)		(1.7)	%	—		—	%
Nondeductible goodwill	—		—	%	—		—	%	336		50.8	%
General business credit	—		—	%	(36)		(1.6)	%	—		—	%
Federal refunds	—		—	%	—		—	%	(20)		(3.0)	%

Other	(7)		(0.2)	%	(13)		(0.6)	%	14		2.2	%
Total	$	710	21.2	%	$	369	16.6	%	$	481	72.8	%

Deferred tax assets and liabilities result from the following:


	December 31,
	2022		2021
	(In millions)
Deferred tax assets
Employee benefits	$	116	$	154

Net operating loss carryforwards	2,007		1,476
Tax credit carryforwards	303		301

Interest expense limitation	82		—
Other	192		229
Valuation allowances	(79)		(93)
Total deferred tax assets	2,621		2,067
Deferred tax liabilities
Property, plant and equipment	163		166

Investments	3,056		1,769
Other	25		17
Total deferred tax liabilities	3,244		1,952
Net deferred tax (liability)/asset	$	(623)	$	115

Deferred Tax Assets and Valuation Allowances

A reconciliation of our valuation allowances for the year ended December 31, 2022 is as follows:


	Year Ended December 31, 2022
	(In millions)
Balance at beginning of period	$	93
Statute expirations for federal and state NOL and foreign tax credits	(16)
Currency fluctuation	2

Balance at end of period	$	79

The following table provides details related to our deferred tax assets and valuation allowances as of December 31, 2022:


	Unused Amount		Deferred Tax Asset		Valuation Allowance		Expiration Period
	(In millions)
Net Operating Loss
U.S. federal net operating loss	$	5,005	$	1,051	$	—	Indefinite
U.S. federal net operating loss	3,209		674		—		2029 - 2037
State losses	5,034		254		(47)		2023 - 2042
Foreign losses	83		28		(28)		Indefinite
Tax Credits
General business credits	299		299		—		2036 - 2042
Foreign tax credits	4		4		(4)		2023 - 2027

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,
	2022		2021		2020
	(In millions)
Balance at beginning of period	$	21	$	18	$	16
Reductions based on statute expirations	(5)		—		—
Additions to state reserves for prior years	7		3		2
Balance at end of period	$	23	$	21	$	18

Amounts which, if recognized, would affect the effective tax rate	$	23

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.						2017 - 2021
Various states						2012 - 2021
Foreign						2008 - 2021

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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-Subparagraph (b)
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 10
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-URI https://asc.fasb.org/extlink&oid=121826272&loc=d3e32705-109319

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI https://asc.fasb.org/extlink&oid=6424409&loc=d3e44925-109338

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-URI https://asc.fasb.org/topic&trid=2144680

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 30
-Section 50
-Paragraph 2
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=6424122&loc=d3e41874-109331

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
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-Paragraph 1
-Subparagraph (SX 210.4-08(h)(2))
-URI https://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

+ Details

Property, Plant and Equipment, net (Notes)

12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, net

6. Property, Plant and Equipment, net

As of December 31, 2022 and 2021, our property, plant and equipment, net consisted of the following:


	Straight Line Estimated Useful Life	Composite Depreciation Rates	December 31,
			2022		2021
	(Years)	(%)	(In millions)
Interstate Natural Gas FERC-Regulated
Pipelines (Natural gas)		0.80-6.67	$	11,793	$	11,718
Equipment (Natural gas)		0.80-6.67	8,839		8,722
Other(a)		0.00-25	833		769
Accumulated depreciation, depletion and amortization			(9,883)		(9,433)
Depreciable assets			11,582		11,776
Land and land rights-of-way			388		387
Construction work in process			258		114
Total interstate natural gas FERC-regulated			12,228		12,277

Other
Pipelines (Natural gas, liquids, crude oil and CO2)	5-40	0.79-33.33	8,329		8,536
Equipment (Natural gas, liquids, crude oil, CO2 and terminals)	5-40	0.79-33.33	18,645		17,789
Other(a)	3-10	0.00-33.33	4,791		4,587
Accumulated depreciation, depletion and amortization			(10,529)		(9,359)
Depreciable assets			21,236		21,553
Land and land rights-of-way			1,350		1,331
Construction work in process			785		492
Total other			23,371		23,376

Property, plant and equipment, net			$	35,599	$	35,653

(a)Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and miscellaneous property, plant and equipment.

Depreciation, depletion and amortization expense for property, plant and equipment was $1,905 million, $1,873 million and $1,928 million for the years ended December 31, 2022, 2021 and 2020, respectively.

Investments (Notes)

12 Months Ended

Dec. 31, 2022

Investments [Abstract]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

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, 2022 and 2021, and our earnings (loss) from these respective investments for the years ended December 31, 2022, 2021 and 2020:


	Ownership Interest	Equity Investments				Earnings (Loss) from Equity Investments
	December 31,	December 31,				Year Ended December 31,
	2022	2022		2021		2022		2021		2020
		(In millions)
Citrus Corporation	50%	$	1,781	$	1,768	$	145	$	151	$	165
SNG	50%	1,669		1,514		145		128		129
PHP	26.67%	666		647		70		63		—
NGPL Holdings(a)	37.5%	610		604		111		94		116
Gulf Coast Express Pipeline LLC	34%	597		618		91		86		90
MEP	50%	371		388		10		(17)		(6)
Products (SE) Pipe Line Corporation	51.17%	348		346		51		48		43
Utopia Holding LLC	50%	325		328		20		20		20
Gulf LNG Holdings Group, LLC	50%	311		347		24		22		19
EagleHawk	25%	273		266		13		8		17
Red Cedar Gathering Company	49%	155		168		17		10		12
Double Eagle Pipeline LLC	50%	90		112		18		9		12
Watco Companies, LLC	(b)	79		75		9		9		16
Cortez Pipeline Company	52.98%	31		28		30		29		24
FEP	50%	—		—		2		—		70
Ruby(c)	(d)	—		—		—		(116)		15
All others		347		369		47		47		38
Total investments		$	7,653	$	7,578	$	803	$	591	$	780
Amortization of excess cost						$	(75)	$	(78)	$	(140)

(a)Our investment in NPGL Holdings includes a related party promissory note receivable from NGPL Holdings with quarterly interest payments at 6.75%. On March 8, 2021, we and Brookfield completed the sale of a combined 25% interest in our joint venture, NGPL Holdings, to ArcLight including a transfer of $125 million in principal amount of our related party promissory note receivable (see Note 3). We and Brookfield now each hold a 37.5% interest in NGPL Holdings. The outstanding principal amount of our related party promissory note receivable at both December 31, 2022 and 2021 was $375 million. For the years ended December 31, 2022, 2021 and 2020, we recognized $25 million, $27 million and $34 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. During the fourth quarter of 2020, we sold our Preferred A and common equity investment in Watco, and recognized a pre-tax gain of $10 million within “Other, net” on our accompanying consolidated statement of income for the year ended December 31, 2020.

(c)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 (see Note 4 “Gains and Losses on Divestitures, Impairments, and Other Write-downs—Investment in Ruby.)

(d)As of December 31, 2022, we operated Ruby and owned an effective 50% interest. As of January 13, 2023, we no longer own an interest in Ruby. For further information regarding Ruby’s bankruptcy filing, see Note 4 “Gains and Losses on Divestitures, Impairments, and Other Write-downs—Investment in Ruby—Ruby Chapter 11 Bankruptcy Filing.”

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	2022		2021(a)		2020
	(In millions)
Revenues	$	5,967	$	5,537	$	5,200
Costs and expenses	4,204		6,153		4,325
Net income (loss)	$	1,763	$	(616)	$	875


	December 31,
Balance Sheet	2022		2021
	(In millions)
Current assets	$	1,470	$	1,314
Non-current assets	23,361		23,154
Current liabilities	1,622		1,808
Non-current liabilities	10,207		10,001
Partners’/owners’ equity	13,002		12,659

(a)2021 amounts include a non-cash impairment charge of $2.2 billion recorded by Ruby.

Goodwill (Notes)

12 Months Ended

Dec. 31, 2022

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, 2022 and 2021 are summarized by reporting unit as follows:


	Natural Gas Pipelines Regulated		Natural Gas Pipelines Non-Regulated		CO2		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	$	—	$	26,637
Accumulated impairment losses	(1,643)		(2,597)		(600)		(1,197)		(70)		(679)		—		(6,786)
December 31, 2020	14,249		2,343		928		1,378		151		802		—		19,851

Acquisitions	—		—		—		—		—		—		63		63


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

Gross goodwill	15,892		4,940		1,528		2,575		221		1,481		114		26,751
Accumulated impairment losses	(1,643)		(2,597)		(600)		(1,197)		(70)		(679)		—		(6,786)
December 31, 2022	$	14,249	$	2,343	$	928	$	1,378	$	151	$	802	$	114	$	19,965

(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.

As of May 31, 2022, the results of our annual analysis did not indicate an impairment of goodwill. Each of our reporting units had an estimated fair value in excess of their respective carrying values (by at least 10%). We did not identify any triggers requiring further impairment analysis during the remainder of the year.

We estimated fair value based on a market approach utilizing forecasted earnings before interest, taxes, depreciation and amortization (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.

The fair value estimates used in our Step 1 analysis are subject to variability in the forecasted EBITDA projections and in the enterprise value to estimated EBITDA multiples of comparable companies for each of our reporting units. A significant unfavorable change to any one or combination of these factors would result in a change to the reporting unit fair values discussed above and potentially result in future impairments of goodwill. Such non-cash impairments could have a significant effect on our results of operations.

Debt (Notes)

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Debt

9. Debt

The following table provides detail on the principal amount of our outstanding debt balances:


	December 31,
	2022		2021
	(In millions)
Credit facility and commercial paper borrowings	$	—	$	—
Corporate senior notes(a)
4.15%, due March 2022	—		375
1.50%, due March 2022(b)	—		853
3.95%, due September 2022	—		1,000
3.15%, due January 2023	1,000		1,000
Floating rate, due January 2023(c)	250		250
3.45%, due February 2023	625		625
3.50%, due September 2023	600		600
5.625%, due November 2023	750		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(b)	535		569
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		—
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


	December 31,
	2022		2021
3.25%, due August 2050	500		500
3.60%, due February 2051	1,050		1,050
5.45%, due January 2052	750		—
7.45%, due March 2098	26		26
TGP senior notes(a)
7.00%, due March 2027	300		300
7.00%, due October 2028	400		400
2.90%, due March 2030	1,000		1,000
8.375%, due June 2032	240		240
7.625%, due April 2037	300		300
EPNG senior notes(a)
8.625%, due January 2022	—		260
7.50%, due November 2026	200		200
3.50%, due February 2032	300		—
8.375%, due June 2032	300		300
CIG senior notes(a)
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	348		364
Trust I Preferred Securities, 4.75%, due March 2028(d)	220		221
Other miscellaneous debt(e)	242		248
Total debt – KMI and Subsidiaries	31,673		32,418
Less: Current portion of debt	3,385		2,646
Total long-term debt – KMI and Subsidiaries(f)	$	28,288	$	29,772

(a)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.

(b)Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2022 exchange rate of 1.0705 U.S. dollars per Euro and at the December 31, 2021 exchange rate of 1.1370 U.S. dollars per Euro. As of December 31, 2022 and 2021, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in a decrease of $8 million and an increase of $26 million, respectively, related to the 2.25% series, and as of December 31, 2021, an increase of $38 million to our debt balance related to the 1.50% series. As of December 31, 2022, we had outstanding associated cross-currency swap agreements which are designated as cash flow hedges.

(c)As of December 31, 2022, we had outstanding an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge.

(d)Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2022, 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, 2022 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.

(e)Includes finance lease obligations with monthly installments. The lease terms expire between 2026 and 2070.

(f)Excludes our “Debt fair value adjustments” which, as of December 31, 2022 and 2021, increased our combined debt balances by $115 million and $902 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 February 23, 2022, EPNG issued in a private offering $300 million aggregate principal amount of 3.50% senior notes due 2032 and received net proceeds of $298 million after discount and issuance costs.

On August 3, 2022, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 4.80% senior notes due 2033 and $750 million aggregate principal amount of 5.45% senior notes due 2052 and received combined net proceeds of $1,484 million. We used a portion of the proceeds to repay short-term borrowings and for general corporate purposes.

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.

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,
	2022		2021

	(In millions)
$3.5 billion credit facility due August 20, 2027	$	—	$	—
$500 million credit facility due November 16, 2023	—		—
Commercial paper notes	—		—
Current portion of senior notes
8.625%, due January 2022(a)	—		260
4.15%, due March 2022(a)	—		375
1.50%, due March 2022(a)(b)	—		853
3.95% due September 2022(c)	—		1,000
3.15% due January 2023(d)	1,000		—
Floating rate, due January 2023(d)(e)	250		—
3.45% due February 2023	625		—
3.50% due September 2023	600		—
5.625%, due November 2023	750		—
Trust I Preferred Securities, 4.75% due March 2028(f)	111		111
Current portion of other debt	49		47
Total current portion of debt	$	3,385	$	2,646

(a)We repaid the principal amount of these senior notes during the first quarter of 2022.

(b)Denominated in Euros.

(c)We repaid the principal amount of these senior notes on June 1, 2022.

(d)On January 17, 2023, we repaid these senior notes using cash on hand and short-term borrowings.

(e)These senior notes have an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge.

(f)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 Facilities and Restrictive Covenants

On December 15, 2022, we amended our credit facilities, discussed further below, to provide for, among other things, the replacement of LIBOR-based provisions with term SOFR provisions, related updates to benchmark replacement provisions and the extension of the maturity date on our $3.5 billion credit facility from August 2026 to August 2027.

Our revolving credit facilities consist of (i) 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, and (ii) a $500 million amended revolving credit facility due November 2023. Borrowings under our credit facilities can be used for working capital and other general corporate purposes and as backup to our commercial paper program.

We maintain a $3.5 billion commercial paper program through the private placement of short-term notes. On September 26, 2022, we reduced our commercial paper program from $4.0 billion to $3.5 billion to conform its size to that of our $3.5 billion revolving credit facility, 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 facilities.

Depending on the type of loan request, our borrowings under our credit facilities bear interest at either (i) SOFR, plus (x) a credit spread adjustment and (y) an applicable margin ranging from 1.000% to 1.750% (for our $3.5 billion credit facility) or to 2.000% (for our $500 million credit facility) 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% (for our $3.5 billion credit facility) or to 1.000% (for our $500 million credit facility) 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% (for our $3.5 billion credit facility) or to 0.300% (for our $500 million credit facility).

Our credit facilities contain 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 facilities, 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 facilities also restrict our ability to make certain restricted payments if an event of default (as defined in the credit facilities) has occurred and is continuing or would occur and be continuing.

As of December 31, 2022, we had no borrowings outstanding under our credit facilities, no borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facilities as of December 31, 2022 was approximately $3.9 billion. As of December 31, 2022, 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, 2022, are summarized as follows:


Year	Total
	(In millions)
2023	$	3,385
2024	1,925
2025	1,566
2026	1,102
2027	890
Thereafter	22,805
Total	$	31,673

Debt Fair Value Adjustments

The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets:


	December 31,
	2022		2021
	(In millions)
Purchase accounting debt fair value adjustments	$	472	$	498
Carrying value adjustment to hedged debt	(367)		376
Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a)	204		223
Unamortized debt discounts, net	(68)		(71)
Unamortized debt issuance costs	(126)		(124)
Total debt fair value adjustments	$	115	$	902

(a)As of December 31, 2022, the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 12 years.

Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances is disclosed below:


	December 31, 2022				December 31, 2021
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Total debt	$	31,788	$	30,070	$	33,320	$	37,775

(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $195 million and $218 million as of December 31, 2022 and 2021, respectively.

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2022 and 2021.

Interest Rates, Interest Rate Swaps and Contingent Debt

The weighted average interest rate on all of our borrowings was 4.76% during 2022 and 4.67% during 2021. 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”).

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-URI https://asc.fasb.org/topic&trid=2208564

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (h)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
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-Section 50
-Paragraph 1C
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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-Paragraph 1I
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-URI https://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (g)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1E
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495348-112611

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
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-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

+ Details

Share-based Compensation and Employee Benefits (Notes)

12 Months Ended

Dec. 31, 2022

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, 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, 2022, we made restricted Class P common stock grants to our non-employee directors of 34,820.

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, 2021	12,617	$	17.63
Granted	4,110	17.31
Vested	(2,744)	20.94
Forfeited	(695)	17.17
Outstanding at December 31, 2022	13,288	$	16.87

The following tables set forth additional information related to our Long Term Incentive Plan:


	Year Ended December 31,
	2022		2021		2020
	(In millions, except per share amounts)
Weighted average grant date fair value per share	$	17.31	$	17.44	$	15.10
Intrinsic value of awards vested during the year	47		77		59
Restricted stock awards expense(a)	60		59		73
Restricted stock awards capitalized(a)	9		9		11
(a)We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements.

			December 31, 2022
Unrecognized restricted stock awards compensation costs, less estimated forfeitures (in millions)					$	104
Weighted average remaining amortization period					1.99 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 $51 million, $48 million and $53 million for the years ended December 31, 2022, 2021 and 2020, 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.

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, 2022 and 2021:


	Pension Benefits				OPEB
	2022		2021		2022		2021
	(In millions)
Change in benefit obligation:
Benefit obligation at beginning of period	$	2,658	$	2,844	$	257	$	299
Service cost	55		53		1		1
Interest cost	57		45		5		4
Actuarial gain	(503)		(80)		(44)		(21)
Benefits paid	(190)		(204)		(26)		(28)
Participant contributions	—		—		1		1
Other	—		—		1		1




Benefit obligation at end of period	2,077		2,658		195		257

Change in plan assets:
Fair value of plan assets at beginning of period	2,231		2,199		382		361
Actual return on plan assets	(350)		180		(63)		40
Employer contributions	50		56		7		7
Participant contributions	—		—		1		1
Other	—		—		1		1
Benefits paid	(190)		(204)		(26)		(28)



Fair value of plan assets at end of period	1,741		2,231		302		382
Funded status - net (liability) asset at December 31,	$	(336)	$	(427)	$	107	$	125

Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)	$	—	$	—	$	239	$	302
Current benefit liability	—		—		(15)		(18)
Non-current benefit liability	(336)		(427)		(117)		(159)
Funded status - net (liability) asset at December 31,	$	(336)	$	(427)	$	107	$	125

Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:
Unrecognized net actuarial (loss) gain	$	(455)	$	(495)	$	135	$	176
Unrecognized prior service (cost) credit	(1)		(2)		4		6
Accumulated other comprehensive (loss) income	$	(456)	$	(497)	$	139	$	182

Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:
Accumulated benefit obligation	$	2,047	$	2,608	$	167	$	219
Fair value of plan assets	1,741		2,231		34		42

(a)2022 and 2021 OPEB amounts include $45 million and $54 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 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. The 2021 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, 2021, partially offset by changes made to the assumptions used to determine at what age and in what form benefits commence. The 2021 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, 2021 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, 2022, by asset category, are as follows:

Pension Benefits

OPEB

Cash

0% to 23%

Equities

42% to 52%

42% to 72%

Fixed income securities

37% to 47%

25% 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 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, 2022 and 2021:


	Pension Assets
	2022						2021
	Level 1		Level 2		Total		Level 1		Level 2		Total
	(In millions)
Measured within fair value hierarchy
Cash	$	—	$	—	$	—	$	11	$	—	$	11
Short-term investment funds	—		27		27		—		25		25
Equities(a)	152		—		152		153		—		153
Fixed income securities	—		421		421		—		566		566

Subtotal	$	152	$	448	600		$	164	$	591	755
Measured at NAV
Common/collective trusts(b)					1,138						1,389
Private investment funds(c)					—						39
Private limited partnerships(d)					3						48


Subtotal					1,141						1,476
Total plan assets fair value					$	1,741					$	2,231

(a)Plan assets include $110 million and $97 million of KMI Class P common stock for 2022 and 2021, respectively.

(b)Common/collective trust funds were invested in approximately 66% equities, 22% fixed income securities and 12% real estate in 2022 and 83% equities and 17% fixed income securities in 2021.

(c)Private investment funds were invested in 100% fixed income securities in 2021.

(d)Includes assets invested in real estate, venture and buyout funds.


	OPEB Assets
	2022				2021
	Level 1		Level 2		Total		Level 1		Level 2		Total
	(In millions)
Measured within fair value hierarchy

Short-term investment funds	$	—	$	3	$	3	$	—	$	3	$	3





Measured at NAV
Common/collective trusts(a)					299						379



Total plan assets fair value					$	302					$	382

(a)Common/collective trust funds were invested in approximately 61% equities and 39% fixed income securities for 2022 and 63% equities and 37% fixed income securities for 2021.

Employer Contributions and Expected Payment of Future Benefits. As of December 31, 2022, we expect the following cash flows under our plans:


	Pension Benefits		OPEB
	(In millions)
Contributions expected in 2023	$	50	$	—

Benefit payments expected in:
2023	$	210	$	26
2024	206		24
2025	202		23
2026	199		21
2027	191		20
2028 - 2032	861		76

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, 2022 and 2021 and net benefit costs of our pension and OPEB plans for 2022, 2021 and 2020:


					Pension Benefits				OPEB
					2022		2021		2022		2021
Assumptions related to benefit obligations:
Discount rate					5.41	%	2.74	%	5.38	%	2.56	%
Rate of compensation increase					3.50	%	3.50	%	n/a		n/a
Interest crediting rate					3.50	%	3.01	%	n/a		n/a

	Pension Benefits						OPEB
	2022		2021		2020		2022		2021		2020
Assumptions related to benefit costs:
Discount rate	2.74	%	2.27	%	3.17	%	2.56	%	2.08	%	3.03	%



Expected return on plan assets	6.50	%	6.25	%	6.75	%	5.75	%	5.75	%	6.50	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	n/a		n/a		n/a
Interest crediting rate	3.01	%	2.57	%	3.71	%	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 5.87% 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
	2022		2021		2020		2022		2021		2020
	(In millions)
Components of net benefit cost (credit):
Service cost	$	55	$	53	$	59	$	1	$	1	$	1
Interest cost	57		45		71		5		4		8
Expected return on assets	(142)		(133)		(137)		(17)		(16)		(16)
Amortization of prior service cost (credit)	1		—		1		(3)		(5)		(5)
Amortization of net actuarial loss (gain)	29		52		40		(18)		(17)		(13)

Net benefit cost (credit)	—		17		34		(32)		(33)		(25)

Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net (gain) loss arising during period	(11)		(127)		157		24		(40)		(43)

Amortization or settlement recognition of net actuarial (loss) gain	(29)		(52)		(40)		17		17		13
Amortization of prior service (cost) credit	(1)		—		(1)		2		3		3

Total recognized in total other comprehensive (income) loss(a)	(41)		(179)		116		43		(20)		(27)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss	$	(41)	$	(162)	$	150	$	11	$	(53)	$	(52)

(a)Excludes $4 million, $3 million and $2 million for the years ended December 31, 2022, 2021 and 2020 respectively, associated with other plans.

Stockholders' Equity (Notes)

12 Months Ended

Dec. 31, 2022

Stockholders' Equity Note [Abstract]

Stockholders’ Equity


11.			Stockholders’ Equity

Class P Common Stock

On July 19, 2017, our board of directors approved a $2 billion share buy-back program that began in December 2017. On January 18, 2023, our board of directors approved an increase in our share repurchase authorization to $3 billion. Activity under the buy-back program is as follows:


		Year Ended December 31,
		2022		2021		2020
	(In millions, except per share amounts)
Total value of shares repurchased		$	368	$	—	$	50
Total number of shares repurchased		21		—		4
Average repurchase price per share		$	16.94	$	—	$	13.93

Since December 2017, in total, we have repurchased 54 million of our shares under the program at an average price of $17.40 per share for $943 million, leaving capacity under the program, after our subsequent increase, of $2.1 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, 2022, 2021 and 2020 we did not issue any shares under this agreement.

Dividends

The following table provides information about our per share dividends:


	Year Ended December 31,
	2022		2021		2020
Per share cash dividend declared for the period	$	1.11	$	1.08	$	1.05
Per share cash dividend paid in the period	1.1025		1.0725		1.0375

On January 18, 2023, our board of directors declared a cash dividend of $0.2775 per share for the quarterly period ended December 31, 2022, which is payable on February 15, 2023 to shareholders of record as of January 31, 2023.

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 gains/(losses) on cash flow hedge derivatives		Pension and other postretirement liability adjustments		Total Accumulated other comprehensive loss
	(In millions)
Balance at December 31, 2019	$	(7)	$	(326)	$	(333)
Other comprehensive gain (loss) before reclassifications	249		(68)		181
Gains reclassified from accumulated other comprehensive loss	(255)		—		(255)
Net current-period change in accumulated other comprehensive loss	(6)		(68)		(74)
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)

- Definition

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-URI https://asc.fasb.org/topic&trid=2208762

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496158-112644

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 13
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496158-112644

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 14
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496171-112644

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 14
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496171-112644

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI https://asc.fasb.org/extlink&oid=120397183&loc=d3e187085-122770

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 18
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496189-112644

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (g)
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496158-112644

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 18
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496189-112644

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (h)
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496158-112644

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 14
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496171-112644

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 18
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496189-112644

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-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
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-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496180-112644

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (i)
-URI https://asc.fasb.org/extlink&oid=126973232&loc=SL123496158-112644

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(e)(1))
-URI https://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 40
-Section 50
-Paragraph 6
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126731327&loc=SL126733271-114008

+ Details

Related Party Transactions (Notes)

12 Months Ended

Dec. 31, 2022

Related Party Transactions

12. Related Party Transactions

Affiliate Balances

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,
	2022		2021
	(In millions)
Balance sheet location
Accounts receivable	$	39	$	38
Other current assets	3		4


	$	42	$	42

Current portion of debt	$	6	$	6
Accounts payable	19		21
Other current liabilities	8		4
Long-term debt	142		148
Other long-term liabilities and deferred credits	47		56

	$	222	$	235


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Income statement location

Revenues	$	172	$	164	$	206



Operating Costs, Expenses and Other
Costs of sales	$	134	$	145	$	116

Other operating expenses	50		52		119

Commitments and Contingent Liabilities (Notes)	12 Months Ended
Commitments and Contingent Liabilities (Notes)	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	13. Commitments and Contingent Liabilities Rights-Of-Way Obligations 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 $120 million as of December 31, 2022. 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, 2022 and 2021, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $163 million and $170 million, respectively. December 31, 2022 and 2021 amounts are represented by 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, 2022 and 2021 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)

12 Months Ended

Dec. 31, 2022

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, 2022, 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	(18.4)	MMBbl
Crude oil basis	(4.2)	MMBbl
Natural gas fixed price	(62.6)	Bcf
Natural gas basis	(40.1)	Bcf
NGL fixed price	(0.6)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.0)	MMBbl
Crude oil basis	(9.2)	MMBbl
Natural gas fixed price	(7.1)	Bcf
Natural gas basis	(44.7)	Bcf
NGL fixed price	(0.8)	MMBbl

As of December 31, 2022, 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 2026.

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, 2022:

Notional amount

Accounting treatment

Maximum term

(In millions)

Derivatives designated as hedging instruments

Fixed-to-variable interest rate contracts(a)(b)

$

7,500

Fair value hedge

March 2035

Variable-to-fixed interest rate contracts

250

Cash flow hedge

January 2023

Derivatives not designated as hedging instruments

Variable-to-fixed interest rate contracts

1,250

Mark-to-Market

December 2023

(a)The principal amount of hedged senior notes consisted of $1,300 million included in “Current portion of debt” and $6,200 million included in “Long-term debt” on our accompanying consolidated balance sheet.

(b)During the year ended December 31, 2022, 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.

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, 2022:

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 swaps 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
		Derivatives Asset				Derivatives Liability
		December 31,				December 31,
		2022		2021		2022		2021
	Location	Fair value				Fair value
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	$	150	$	61	$	(156)	$	(141)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	6		3		(91)		(94)
Subtotal		156		64		(247)		(235)
Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	—		101		(144)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	39		284		(261)		(15)
Subtotal		39		385		(405)		(18)
Foreign currency contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	—		35		(3)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		6		(32)		—
Subtotal		—		41		(35)		(3)
Total		195		490		(687)		(256)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	80		11		(162)		(31)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	23		1		(19)		(6)
Subtotal		103		12		(181)		(37)
Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	1		12		—		—





Total		104		24		(181)		(37)
Total derivatives		$	299	$	514	$	(868)	$	(293)

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, 2022
Energy commodity derivative contracts(b)	$	115	$	144	$	—	$	259	$	(186)	$	—	$	73
Interest rate contracts	—		40		—		40		—		—		40

As of December 31, 2021
Energy commodity derivative contracts(b)	$	56	$	20	$	—	$	76	$	(53)	$	(20)	$	3
Interest rate contracts	—		397		—		397		(9)		—		388
Foreign currency contracts	—		41		—		41		(3)		—		38


	Balance sheet liability fair value measurements by level
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral posted(a)		Net amount
	(In millions)
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)
As of December 31, 2021
Energy commodity derivative contracts(b)	(15)		(257)		—		(272)		53		—		(219)
Interest rate contracts	—		(18)		—		(18)		9		—		(9)
Foreign currency contracts	—		(3)		—		(3)		3		—		—

(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,
		2022		2021		2020
		(In millions)
Interest rate contracts	Interest, net	$	(738)	$	(322)	$	335

Hedged fixed rate debt(a)	Interest, net	$	743	$	326	$	(343)

(a)As of December 31, 2022, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $367 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheets.


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)						Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Year Ended							Year Ended
	December 31,							December 31,
	2022		2021		2020			2022		2021		2020
	(In millions)							(In millions)
Energy commodity derivative contracts	$	(338)	$	(475)	$	240	Revenues—Commodity sales	$	(491)	$	(271)	$	222

							Costs of sales	144		20		(14)
Interest rate contracts(c)	7		5		(8)		Interest, net	—		—		—
Foreign currency contracts	(73)		(93)		92		Other, net	(68)		(105)		125
Total	$	(404)	$	(563)	$	324	Total	$	(415)	$	(356)	$	333

(a)We expect to reclassify an approximately $92 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2022 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, 2022, 2021 and 2020, we recognized approximate gains of $121 million, $41 million and no gains, 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,
		2022		2021		2020
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	137	$	(652)	$	(1)

	Costs of sales	(190)		152		25
	Earnings from equity investments(a)	(11)		(5)		—
Interest rate contracts	Interest, net	(10)		12		—
Total(b)		$	(74)	$	(493)	$	24

(a)Amounts represent our share of an equity investee’s income (loss).

(b)The years ended December 31, 2022, 2021 and 2020 include approximate losses of $11 million, $479 million and $11 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, 2022 and 2021, we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2022, we had cash margins of $1 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. As of December 31, 2021 we had cash margins of $14 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The balance at December 31, 2022 represents the initial margin requirements of $29 million, offset by counterparty variation margin requirements of $30 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, 2022, 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 $144 million of additional collateral.

Revenue Recognition (Notes)

12 Months Ended

Dec. 31, 2022

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.

CO2 Segment

Our crude oil, NGL, CO2 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 revenue source and type of revenue for each revenue source:


	Year Ended December 31, 2022
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		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		CO2		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


	Year Ended December 31, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	3,345	$	271	$	756	$	1	$	(3)	$	4,370
Fee-based services	714		905		395		42		—		2,056
Total services	4,059		1,176		1,151		43		(3)		6,426
Commodity sales
Natural gas sales	2,038		—		—		1		(7)		2,032
Product sales	562		358		14		735		(30)		1,639

Total commodity sales	2,600		358		14		736		(37)		3,671
Total revenues from contracts with customers	6,659		1,534		1,165		779		(40)		10,097
Other revenues(c)
Leasing services(d)	466		166		557		47		—		1,236
Derivatives adjustments on commodity sales	18		—		—		203		—		221
Other	116		21		—		9		—		146
Total other revenues	600		187		557		259		—		1,603
Total revenues	$	7,259	$	1,721	$	1,722	$	1,038	$	(40)	$	11,700

(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 indexed-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, 2022 and 2021, our contract asset balances were $33 million and $39 million, respectively. Of the contract asset balance at December 31, 2021, $14 million was transferred to accounts receivable during the year ended December 31, 2022. As of December 31, 2022 and 2021, our contract liability balances were $204 million and $212 million, respectively. Of the contract liability balance at December 31, 2021, $90 million was recognized as revenue during the year ended December 31, 2022.

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, 2022 that we will invoice or transfer from contract liabilities and recognize in future periods:


Year	Estimated Revenue
	(In millions)
2023	$	4,312
2024	3,401
2025	2,800
2026	2,466
2027	2,132
Thereafter	12,340
Total	$	27,451

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 generally exclude, based on the following practical expedient that we elected to apply, 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.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI https://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 9
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (e)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

+ Details

Reportable Segments (Notes)

12 Months Ended

Dec. 31, 2022

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, renewable fuel stocks, chemicals, ethanol, metals and petroleum coke; and (ii) Jones Act-qualified tankers;

•CO2—(i) the production, transportation and marketing of CO2 to oil fields that use CO2 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; and (iv) the ownership and operation of RNG and LNG facilities in Indiana associated with our acquisition of Kinetrex in 2021 and the ownership and operation of GTE facilities in Michigan and Kentucky associated with our acquisition of NANR in 2022 (see Note 3).

We evaluate performance principally based on each segment’s 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 2022, 2021 and 2020, 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,
	2022		2021		2020
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	12,659	$	11,644	$	7,222
Intersegment revenues	27		65		37
Products Pipelines	3,418		2,245		1,721

Terminals
Revenues from external customers	1,789		1,712		1,719
Intersegment revenues	3		3		3
CO2	1,334		1,009		1,038
Corporate and intersegment eliminations	(30)		(68)		(40)
Total consolidated revenues	$	19,200	$	16,610	$	11,700


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Operating expenses(a)
Natural Gas Pipelines	$	8,562	$	7,000	$	3,457
Products Pipelines	2,391		1,239		779
Terminals	853		793		762
CO2	554		289		404
Corporate and intersegment eliminations	(9)		(34)		(4)
Total consolidated operating expenses	$	12,351	$	9,287	$	5,398


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Other expense (income)(b)
Natural Gas Pipelines	$	(13)	$	1,597	$	1,009
Products Pipelines	(12)		—		21
Terminals	(14)		32		(50)
CO2	(1)		(8)		950

Corporate	1		(4)		—
Total consolidated other expense (income)	$	(39)	$	1,617	$	1,930


	Year Ended December 31,
	2022		2021		2020
	(In millions)
DD&A
Natural Gas Pipelines	$	1,096	$	1,099	$	1,062
Products Pipelines	336		335		347
Terminals	458		440		438
CO2	272		236		291
Corporate	24		25		26
Total consolidated DD&A	$	2,186	$	2,135	$	2,164


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Earnings from equity investments and amortization of excess cost of equity investments
Natural Gas Pipelines	$	650	$	435	$	551
Products Pipelines	33		34		45
Terminals	14		15		22
CO2	31		29		22
Total consolidated equity earnings	$	728	$	513	$	640


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Other, net-income (expense)
Natural Gas Pipelines	$	(19)	$	216	$	11
Products Pipelines	—		1		1
Terminals	8		3		13
Corporate	66		62		31
Total consolidated other, net-income (expense)	$	55	$	282	$	56


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Segment EBDA(c)
Natural Gas Pipelines	$	4,801	$	3,815	$	3,483
Products Pipelines	1,107		1,064		977
Terminals	975		908		1,045
CO2	819		760		(292)

Total Segment EBDA	7,702		6,547		5,213
DD&A	(2,186)		(2,135)		(2,164)
Amortization of excess cost of equity investments	(75)		(78)		(140)
General and administrative and corporate charges	(593)		(623)		(653)
Interest, net	(1,513)		(1,492)		(1,595)
Income tax expense	(710)		(369)		(481)
Total consolidated net income	$	2,625	$	1,850	$	180


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Capital expenditures
Natural Gas Pipelines	$	666	$	570	$	945
Products Pipelines	—		122		122
Terminals	552		332		433
CO2	371		230		186
Corporate	32		27		21
Total consolidated capital expenditures	$	1,621	$	1,281	$	1,707


	December 31,
	2022		2021
	(In millions)
Investments
Natural Gas Pipelines	$	6,993	$	6,887
Products Pipelines	445		465
Terminals	128		137
CO2	87		89

Total consolidated investments	$	7,653	$	7,578


	December 31,
	2022		2021
	(In millions)
Other intangibles, net
Natural Gas Pipelines	$	439	$	557
Products Pipelines	777		868
Terminals	38		51
CO2	555		202

Total consolidated other intangibles, net	$	1,809	$	1,678


	December 31,
	2022		2021
	(In millions)
Assets
Natural Gas Pipelines	$	47,978	$	47,746
Products Pipelines	8,985		9,088
Terminals	8,357		8,513
CO2	3,449		2,843

Corporate assets(d)	1,309		2,226

Total consolidated assets	$	70,078	$	70,416

(a)Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

(b)Includes (gain) loss on divestitures and impairments, net and other income, net.

(c)Includes revenues, earnings from equity investments, and other, net, less operating expenses, (gain) loss on divestitures and impairments, net and other income, net.

(d)Includes cash and cash equivalents, margin and restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy balances) 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,
	2022		2021		2020
	(In millions)
Revenues from external customers
U.S.	$	19,036	$	16,479	$	11,625

Mexico and other foreign	164		131		75
Total consolidated revenues from external customers	$	19,200	$	16,610	$	11,700


	December 31,
	2022		2021		2020
	(In millions)
Long-term assets, excluding goodwill and other intangibles
U.S.	$	44,425	$	44,916	$	46,384
Mexico and other foreign	75		78		81
Canada	1		1		1
Total consolidated long-lived assets	$	44,501	$	44,995	$	46,466

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8924-108599

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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-Subparagraph (e)
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-Paragraph 21
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8721-108599

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-URI https://asc.fasb.org/topic&trid=2134510

+ Details

Leases (Notes)

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Leases: Lessee

17. Leases

Following are components of our lease cost:


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Operating leases	$	62	$	60	$	55
Short-term and variable leases	101		109		101
Total lease cost	$	163	$	169	$	156

Other information related to our operating leases are as follows:


	Year Ended December 31,
	2022			2021			2020
	(In millions, except lease term and discount rate)
Operating cash flows from operating leases	$	(132)		$	(137)		$	(131)
Investing cash flows from operating leases	(31)			(32)			(25)
ROU assets obtained in exchange for operating lease obligations, net of retirements	22			59			20
Amortization of ROU assets	50			47			46


Weighted average remaining lease term	9.8 years			10.39 years			11.56 years
Weighted average discount rate	4.26		%	3.95		%	4.27		%

Amounts recognized in the accompanying consolidated balance sheets are as follows:


		December 31,
Lease Activity(a)	Balance sheet location	2022		2021
		(In millions)
ROU assets	Deferred charges and other assets	$	287	$	315
Short-term lease liability	Other current liabilities	47		45
Long-term lease liability	Other long-term liabilities and deferred credits	240		270

(a)We have immaterial financing leases recorded as of December 31, 2022 and 2021.

Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2022 are as follows:


Year	Commitment
	(In millions)
2023	$	58
2024	50
2025	40
2026	32
2027	29
Thereafter	166
Total lease payments	375
Less: Interest	(88)
Present value of lease liabilities	$	287

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 (Notes)	12 Months Ended
Litigation and Environmental (Notes)	Dec. 31, 2022
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 meritorious 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. EPNG FERC Proceeding On April 21, 2022, EPNG was notified by the FERC of the commencement of a rate proceeding against it pursuant to Section 5 of the Natural Gas Act. This proceeding sets the matter for hearing to determine whether EPNG’s current rates remain just and reasonable. A proceeding under Section 5 of the Natural Gas Act is prospective in nature such that a change in rates charged to customers, if any, would likely only occur after the FERC has issued a final order. On November 18, 2022, EPNG filed a Stipulation and Agreement (S&A) to establish base rates and rate reductions during the term of the S&A, including a cumulative 16% reduction on average across mainline rate zones, to be phased in over 3 years beginning January 1, 2023, and a rate moratorium until September 30, 2027. FERC approved the S&A without modification on January 31, 2023. Gulf LNG Facility Disputes On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement (Guarantee) entered into by Eni S.p.A. on December 10, 2007 in connection with a contemporaneous terminal use agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA). The suit to enforce the Guarantee against Eni S.p.A. was filed after an arbitration tribunal delivered an award on June 29, 2018 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 to enforce the Guarantee, Eni S.p.A. filed counterclaims based on the terminal use agreement and a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing counterclaims asserted by Eni S.p.A seek unspecified damages and involve 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 (ALSS), a consortium of international oil companies including Eni S.p.A. On January 4, 2022, the trial court entered a decision granting Eni S.p.A’s motion for summary judgment on the claims asserted by GLNG to enforce the Guarantee. GLNG filed an interlocutory appeal of the decision, which remains pending. Pending resolution of GLNG’s appeal and further proceedings in the trial court, the foregoing counterclaims and other claims asserted by Eni S.p.A based on the terminal use agreement and parent direct agreement remain pending in the trial court. We vigorously dispute that the foregoing counterclaims and other claims asserted by Eni S.p.A. have any merit, particularly since they were dismissed with prejudice in previous arbitrations involving both Eni USA and ALSS. We intend to vigorously pursue our appeal to enforce the Guarantee and are seeking summary judgment on any remaining counterclaims or other claims asserted by Eni S.p.A. Continental Resources, Inc. v. Hiland Partners Holdings, LLC On December 8, 2017, Continental Resources, Inc. (CLR) filed a lawsuit in Garfield County, Oklahoma state court alleging among other claims that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA produced in three counties in North Dakota. CLR sought damages in excess of $276 million. While Hiland Partners denied all of the claims asserted in the lawsuit, the parties entered into a confidential settlement agreement on September 14, 2022, including an unconditional release and dismissal of the litigation with prejudice. Freeport LNG Winter Storm Litigation On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed a lawsuit against Kinder Morgan Texas Pipeline LLC 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 intent to appeal the trial court’s decision. We believe that our declaration of force majeure was valid and we intend 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 lawsuit, which was filed initially in federal court in Michigan and then transferred to the U.S. District Court for the Southern District of Texas (Civil Action No. 4:21-3590), 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. The complaint alleges that the purported class includes over 10,000 individuals. The lawsuit is in the early stages of discovery and no class has been certified. 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 our potential liability for past or future benefits, if any, remains to be determined. We believe that none of the claims are valid 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 is investigating the incident. EPNG began the process of returning the impacted pipeline segment to service on February 6, 2023. While no litigation is pending at this time, we notified our insurers of the incident and do not expect that the resolution of claims will have a material adverse impact to our business. General As of December 31, 2022 and 2021, our total reserve for legal matters was $70 million and $231 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 and CO2 field and oil field 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 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 CO2, including natural resource damage (NRD) claims. PHMSA Enforcement Matter for KMLT Midwest Terminals On July 11, 2022, Kinder Morgan Liquid Terminals (KMLT) received a Notice of Probable Violation (NOPV) from PHMSA relating to inspections conducted during 2021 at KMLT’s Cincinnati, Indianapolis, Dayton, Argo, O’Hare, and Wood River Terminals. The NOPV alleged violations of Department of Transportation regulations, proposed a penalty of approximately $455,000 and sought a compliance agreement relating to certain of the alleged violations. On February 3, 2023, PHMSA and KMLT entered into a Consent Agreement resolving the allegations in the NOPV. Also on February 3, 2023, PHMSA issued a Consent Order approving the Consent Agreement. We do not anticipate the costs to resolve this matter, including any costs to implement the Consent Agreement, will have a material adverse impact to our business. 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 December 2024. 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 Record of Decision (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 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. We believe our share of the costs to resolve this matter, including our share of the settlement with 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 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 December 2013, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In April 2015, the U.S. District Court ordered the case to be remanded to the state district court for Plaquemines Parish. In May 2018, the case was removed for a second time to the U.S. District Court. In May 2019, the U.S. District Court ordered the case to be remanded to the state district court. 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 ordered to be remanded to the state district courts for Plaquemines and Cameron Parishes, respectively. The defendants to those consolidated cases pursued an appeal of the remand decisions to the U.S. Court of Appeals for the Fifth Circuit to determine whether there is federal officer jurisdiction. On October 17, 2022, the U.S. Court of Appeals ordered those consolidated cases to be remanded to the state district courts. On November 14, 2022, the defendants to those consolidated cases filed separate Petitions for Panel Rehearing, and for Rehearing En Banc. On November 29, 2022, the U.S. Court of Appeals denied both Petitions. On December 15, 2022, the case against TGP was remanded to the state district court. On January 30, 2023, the defendants to those consolidated cases filed a Petition for Writ of Certiorari with the U.S. Supreme Court seeking review of the decisions of the U.S. Court of Appeals. 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 and Orleans Parish (collectively, 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 May 2019, Orleans moved to remand the case to the state district court. 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; Parish of Cameron vs. Auster Oil & Gas, Inc., pending in U.S. District Court for the Western District of Louisiana; after which either party may move to re-open the case. On January 23, 2023, the City of New Orleans filed an Ex parte Motion to Reopen Case and Notice of Supplemental Authority asking the U.S. District Court to re-open the case. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to vigorously defend this case. Products Pipeline Incident, Walnut Creek, California On November 20, 2020, SFPP identified an issue on its Line Section 16 (LS-16) which transports petroleum products in California from Concord to San Jose. We shut down the pipeline and notified the appropriate regulatory agencies of a “threatened release” of gasoline. We investigated the issue over the next several days and on November 24, 2020, identified a crack in the pipeline and notified the regulatory agencies of a “confirmed release.” The damaged section of the pipeline was removed and replaced, and the pipeline resumed operations on November 26, 2020. We reported the estimated volume of gasoline released to be 8.1 Bbl. On December 2, 2020, complaints of gasoline odors were reported along the LS-16 pipeline corridor in Walnut Creek. A unified response was implemented by us along with the EPA, the California Office of Spill Prevention and Response, the California Fire Marshall, and the San Francisco Regional Water Quality Control Board. On December 8, 2020, we reported an updated estimated spill volume of up to 1,000 Bbl. On October 28, 2021, we were informed by the California Attorney General it was contemplating criminal charges against us asserting the November 2020 discharge of gasoline affected waters of the State of California, and there was a failure to make timely notices of this discharge to appropriate state agencies. On December 16, 2021, we entered into a plea agreement with the State of California to resolve misdemeanor charges of the unintentional, non-negligent discharge of gasoline resulting from the release and the claimed failure to provide timely notices of the discharge to appropriate state agencies. Under the plea agreement, SFPP plead no-contest to two misdemeanors and paid approximately $2.5 million in fines, penalties, restitution, environmental improvement project funding, and for enforcement training in the State of California, and was placed on informal, unsupervised probation for a term of 18 months. Since the November 2020 release, we have cooperated fully with federal and state agencies and have worked diligently to remediate the affected areas. We anticipate civil enforcement actions by federal and state agencies arising from the November 2020 release as well as ongoing monitoring and, where necessary, remediation under the oversight of the San Francisco Regional Water Quality Control Board until site conditions demonstrate no further actions are required. We do not anticipate the costs to resolve those enforcement matters, including the costs to monitor and further remediate the site, will have a material adverse 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, 2022 and 2021, we have accrued a total reserve for environmental liabilities in the amount of $221 million and $243 million, respectively. In addition, as of both December 31, 2022 and 2021, we had recorded a receivable of $12 million for expected cost recoveries that have been deemed probable.

Recent Accounting Pronoucements (Notes)

12 Months Ended

Dec. 31, 2022

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 – 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.

During the year ended December 31, 2022 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. These agreements contain a combined notional principal amount of $4,425 million and convert a portion of our fixed rate debt to variable rates through March 2035. 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 we continue to amend our interest rate swap agreements to transition from LIBOR to SOFR, we will assess whether such amendments qualify for any of the optional expedients in Topic 848 and, should they qualify, whether we wish to elect any such optional expedients. See Note 14 “Risk Management—Interest Rate Risk Management” for more information on our interest rate risk management activities.

- Definition

The entire disclosure for change in accounting principle. Includes, but is not limited to, nature, reason, and method of adopting amendment to accounting standards or other change in accounting principle.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-URI https://asc.fasb.org/topic&trid=2122394

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 105
-SubTopic 10
-Section 65
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+ Details

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

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.

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 CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected.

•The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected.

•When CO2 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 CO2 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,
	2022		2021
	(In millions)
Balance at beginning of period	$	196	$	215
Accretion expense	12		7
New obligations	2		6
Settlements	(6)		(8)
Revisions to previous estimates	—		(24)
Balance at end of period(a)	$	204	$	196

(a)Balances at December 31, 2022 and 2021 include $3 million and $4 million, respectively, included within “Other current liabilities” on our accompanying consolidated balance sheets.

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 is 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 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 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, 2022 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (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 circumstance 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.

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, CO2 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.

Cost of Sales

Cost 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 CO2 producing activities, such as those in our CO2 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 CO2 producing activities included within operations and maintenance totaled $367 million, $180 million and $319 million for the years ended December 31, 2022, 2021 and 2020, respectively.

Environmental Matters

We capitalize or expense, as appropriate, environmental expenditures. 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. Generally, our accrual of these environmental liabilities coincides with either our completion of a feasibility study or our 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 could impact our assets or operations. These reviews 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. These revisions are reflected in our income in the period in which they are reasonably determinable.

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 to 48 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception or upon modification. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.

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,” 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

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, ELC, not owned by us, and which in certain limited circumstances, the partner had the right to relinquish its interest in the subsidiary and redeem its cumulative contributions, net of distributions it had received through date of the amended operating agreement. Distributions paid to EIG 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 statements of cash flows. On December 14, 2021, the ownership agreement was modified such that EIG’s interest was no longer contingently redeemable, and the balance was reclassified to “Noncontrolling Interests.” Net income attributable to redeemable noncontrolling interest was $58 million and $54 million for the years ended December 31, 2021 and 2020, respectively, and is included in “Net Income Attributable to Noncontrolling Interests” in our accompanying consolidated statements 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 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.

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

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.

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 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

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 (Policies)	12 Months Ended
Acquisitions and Divestitures (Policies)	Dec. 31, 2022
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)	12 Months Ended
Income Taxes (Policies)	Dec. 31, 2022
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 Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2022

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,
	2022		2021
	(In millions)
Balance at beginning of period	$	196	$	215
Accretion expense	12		7
New obligations	2		6
Settlements	(6)		(8)
Revisions to previous estimates	—		(24)
Balance at end of period(a)	$	204	$	196

(a)Balances at December 31, 2022 and 2021 include $3 million and $4 million, respectively, included within “Other current liabilities” on our accompanying consolidated balance sheets.

Schedule of Other Intangibles

The following tables summarize our other intangible assets as of December 31, 2022 and 2021 and our amortization expense for the years ended December 31, 2022, 2021 and 2020:


	Weighted Average Amortization Period (years)	December 31,
		2022		2021
		(In millions)
Gross	11.2	$	3,382	$	3,036
Accumulated amortization		(1,573)		(1,358)
Net carrying amount		$	1,809	$	1,678


	December 31,
	2022		2021		2020
	(In millions)
Amortization expense	$	253	$	237	$	212

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:


	2023		2024		2025		2026		2027
	(In millions)
Estimated amortization expenses	$	201	$	175	$	170	$	168	$	167

Schedule of Regulatory Assets and Liabilities Table [Table Text Block]

The following table summarizes our regulatory asset and liability balances as of December 31, 2022 and 2021:


	December 31,
	2022		2021
	(In millions)
Current regulatory assets	$	73	$	66
Non-current regulatory assets	183		220
Total regulatory assets(a)	$	256	$	286

Current regulatory liabilities	$	50	$	32
Non-current regulatory liabilities	175		163
Total regulatory liabilities(b)	$	225	$	195

(a)Regulatory assets as of December 31, 2022 include (i) $110 million of unamortized losses on disposal of assets; (ii) $45 million income tax gross up on equity AFUDC; and (iii) $101 million of other assets, including amounts related to fuel tracker arrangements. Approximately $143 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, 2022 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 $110 million of the $175 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 15 years, while the remaining $65 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,
	2022		2021		2020
	(In millions, except per share amounts)
Net Income Available to Stockholders	$	2,548	$	1,784	$	119
Participating securities:
Less: Net Income Allocated to Restricted stock awards(a)	(13)		(14)		(13)
Net Income Allocated to Class P Stockholders	$	2,535	$	1,770	$	106

Basic Weighted Average Shares Outstanding	2,258		2,266		2,263
Basic Earnings Per Share	$	1.12	$	0.78	$	0.05

(a)As of December 31, 2022, 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,
	2022	2021	2020
	(In millions on a weighted average basis)
Unvested restricted stock awards	13	13	13
Convertible trust preferred securities	3	3	3

Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2022

Business Combination and Asset Acquisition [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

As of December 31, 2022, our allocation of the purchase price for significant acquisitions completed during the years ended December 31, 2022 and 2021 are detailed below:


					Assignment of Purchase Price
Ref	Date	Acquisition	Purchase price		Current assets		Property, plant & equipment		Other long-term assets		Current liabilities		Long-term liabilities		Resulting goodwill
			(In millions)
(1)	8/22	North American Natural Resources	$	132	$	2	$	5	$	64	$	—	$	—	$	61
(2)	7/22	Mas Ranger, LLC	358		9		31		320		(2)		—		—
(3)	8/21	Kinetrex	318		18		49		272		(6)		(68)		53
(4)	7/21	Stagecoach	1,258		53		1,187		24		(6)		—		—

Schedule of Variable Interest Entities

The following table shows the carrying amount and classification of ELC’s assets and liabilities in our consolidated balance sheet:


	December 31, 2022
	(In millions)
Assets
Current assets	$	34
Property, plant and equipment, net	1,197
Deferred charges and other assets	6

Liabilities
Current liabilities	$	15
Other long-term liabilities and deferred credits	5

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

Gains and Losses on Divestitures, Impairments and Other Write-downs (Tables)

12 Months Ended

Dec. 31, 2022

Impairments [Abstract]

Impairment of Goodwill, Long-lived assets and equity investments [Table Text Block]

We recognized the following non-cash pre-tax (gains) losses on divestitures, impairments or other write-downs on assets and equity investments during the years ended December 31, 2022, 2021, and 2020:


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Natural Gas Pipelines
Impairments of long-lived assets(a)	$	—	$	1,600	$	—
Impairment of goodwill(b)	—		—		1,000
Gain on sale of interest in NGPL Holdings(c)	—		(206)		—
Loss on write-down of related party note receivable(d)	—		117		—
(Gains) losses on divestitures of long-lived assets	(10)		(1)		10


Products Pipelines
Impairments of long-lived assets	—		—		21
Gain on divestiture of long-lived asset	(12)		—		—

Terminals
Impairments of long-lived assets	—		34		5
(Gains) losses on divestitures of long-lived assets(e)	(9)		2		(54)
Gain on sale of equity investment interests	—		—		(10)
CO2
Impairment of goodwill(b)	—		—		600
Impairments of long-lived assets(f)	—		—		350
Gains on divestitures of long-lived assets	(1)		(8)		—

Other gains on divestitures of long-lived assets	—		(3)		—
Pre-tax (gains) losses on divestitures, impairments and other write-downs, net	$	(32)	$	1,535	$	1,922

(a)2021 amount represents non-cash impairments associated with our South Texas gathering and processing assets.

(b)2020 amount represent non-cash goodwill impairments associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units (see “—Impairments—Goodwill” below).

(c)See Note 3.

(d)See “—Investment in Ruby” below for a further discussion.

(e)2020 amount includes a $55 million gain related to the sale of our Staten Island terminal.

(f)2020 amount represents a non-cash impairment of oil and gas properties.

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Schedule of Income Before Income Taxes

The components of “Income Before Income Taxes” are as follows:


	Year Ended December 31,
	2022		2021		2020
	(In millions)
U.S.	$	3,318	$	2,217	$	663
Foreign	17		2		(2)
Total Income Before Income Taxes	$	3,335	$	2,219	$	661

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,
	2022		2021		2020
	(In millions)
Current tax expense (benefit)
Federal	$	—	$	—	$	(20)
State	14		11		9
Foreign	4		3		147
Total	18		14		136
Deferred tax expense (benefit)
Federal	642		334		440
State	50		21		49
Foreign	—		—		(144)
Total	692		355		345
Total tax provision	$	710	$	369	$	481

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,
	2022				2021				2020
	(In millions, except percentages)
Federal income tax	$	700	21.0	%	$	466	21.0	%	$	139	21.0	%
Increase (decrease) as a result of:
Net effects of noncontrolling interests	(16)		(0.5)	%	(14)		(0.6)	%	(13)		(2.0)	%
State income tax, net of federal benefit	69		2.0	%	50		2.2	%	52		7.9	%


Dividend received deduction	(36)		(1.1)	%	(46)		(2.1)	%	(27)		(4.1)	%

Release of valuation allowance	—		—	%	(38)		(1.7)	%	—		—	%
Nondeductible goodwill	—		—	%	—		—	%	336		50.8	%
General business credit	—		—	%	(36)		(1.6)	%	—		—	%
Federal refunds	—		—	%	—		—	%	(20)		(3.0)	%

Other	(7)		(0.2)	%	(13)		(0.6)	%	14		2.2	%
Total	$	710	21.2	%	$	369	16.6	%	$	481	72.8	%

Schedule of Deferred Tax Assets and Liabilities

Deferred tax assets and liabilities result from the following:


	December 31,
	2022		2021
	(In millions)
Deferred tax assets
Employee benefits	$	116	$	154

Net operating loss carryforwards	2,007		1,476
Tax credit carryforwards	303		301

Interest expense limitation	82		—
Other	192		229
Valuation allowances	(79)		(93)
Total deferred tax assets	2,621		2,067
Deferred tax liabilities
Property, plant and equipment	163		166

Investments	3,056		1,769
Other	25		17
Total deferred tax liabilities	3,244		1,952
Net deferred tax (liability)/asset	$	(623)	$	115

Summary of Valuation Allowance

A reconciliation of our valuation allowances for the year ended December 31, 2022 is as follows:


	Year Ended December 31, 2022
	(In millions)
Balance at beginning of period	$	93
Statute expirations for federal and state NOL and foreign tax credits	(16)
Currency fluctuation	2

Balance at end of period	$	79

Summary of Operating Loss Carryforwards

The following table provides details related to our deferred tax assets and valuation allowances as of December 31, 2022:


	Unused Amount		Deferred Tax Asset		Valuation Allowance		Expiration Period
	(In millions)
Net Operating Loss
U.S. federal net operating loss	$	5,005	$	1,051	$	—	Indefinite
U.S. federal net operating loss	3,209		674		—		2029 - 2037
State losses	5,034		254		(47)		2023 - 2042
Foreign losses	83		28		(28)		Indefinite
Tax Credits
General business credits	299		299		—		2036 - 2042
Foreign tax credits	4		4		(4)		2023 - 2027

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,
	2022		2021		2020
	(In millions)
Balance at beginning of period	$	21	$	18	$	16
Reductions based on statute expirations	(5)		—		—
Additions to state reserves for prior years	7		3		2
Balance at end of period	$	23	$	21	$	18

Amounts which, if recognized, would affect the effective tax rate	$	23

Summary of Income Tax Examinations

The following table summarizes information of our open tax years:


Jurisdiction						Open Tax Year
U.S.						2017 - 2021
Various states						2012 - 2021
Foreign						2008 - 2021

Property, Plant and Equipment, net (Tables)

12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

As of December 31, 2022 and 2021, our property, plant and equipment, net consisted of the following:


	Straight Line Estimated Useful Life	Composite Depreciation Rates	December 31,
			2022		2021
	(Years)	(%)	(In millions)
Interstate Natural Gas FERC-Regulated
Pipelines (Natural gas)		0.80-6.67	$	11,793	$	11,718
Equipment (Natural gas)		0.80-6.67	8,839		8,722
Other(a)		0.00-25	833		769
Accumulated depreciation, depletion and amortization			(9,883)		(9,433)
Depreciable assets			11,582		11,776
Land and land rights-of-way			388		387
Construction work in process			258		114
Total interstate natural gas FERC-regulated			12,228		12,277

Other
Pipelines (Natural gas, liquids, crude oil and CO2)	5-40	0.79-33.33	8,329		8,536
Equipment (Natural gas, liquids, crude oil, CO2 and terminals)	5-40	0.79-33.33	18,645		17,789
Other(a)	3-10	0.00-33.33	4,791		4,587
Accumulated depreciation, depletion and amortization			(10,529)		(9,359)
Depreciable assets			21,236		21,553
Land and land rights-of-way			1,350		1,331
Construction work in process			785		492
Total other			23,371		23,376

Property, plant and equipment, net			$	35,599	$	35,653

(a)Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and miscellaneous property, plant and equipment.

Investments (Tables)

12 Months Ended

Dec. 31, 2022

Investments [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, 2022 and 2021, and our earnings (loss) from these respective investments for the years ended December 31, 2022, 2021 and 2020:


	Ownership Interest	Equity Investments				Earnings (Loss) from Equity Investments
	December 31,	December 31,				Year Ended December 31,
	2022	2022		2021		2022		2021		2020
		(In millions)
Citrus Corporation	50%	$	1,781	$	1,768	$	145	$	151	$	165
SNG	50%	1,669		1,514		145		128		129
PHP	26.67%	666		647		70		63		—
NGPL Holdings(a)	37.5%	610		604		111		94		116
Gulf Coast Express Pipeline LLC	34%	597		618		91		86		90
MEP	50%	371		388		10		(17)		(6)
Products (SE) Pipe Line Corporation	51.17%	348		346		51		48		43
Utopia Holding LLC	50%	325		328		20		20		20
Gulf LNG Holdings Group, LLC	50%	311		347		24		22		19
EagleHawk	25%	273		266		13		8		17
Red Cedar Gathering Company	49%	155		168		17		10		12
Double Eagle Pipeline LLC	50%	90		112		18		9		12
Watco Companies, LLC	(b)	79		75		9		9		16
Cortez Pipeline Company	52.98%	31		28		30		29		24
FEP	50%	—		—		2		—		70
Ruby(c)	(d)	—		—		—		(116)		15
All others		347		369		47		47		38
Total investments		$	7,653	$	7,578	$	803	$	591	$	780
Amortization of excess cost						$	(75)	$	(78)	$	(140)

(a)Our investment in NPGL Holdings includes a related party promissory note receivable from NGPL Holdings with quarterly interest payments at 6.75%. On March 8, 2021, we and Brookfield completed the sale of a combined 25% interest in our joint venture, NGPL Holdings, to ArcLight including a transfer of $125 million in principal amount of our related party promissory note receivable (see Note 3). We and Brookfield now each hold a 37.5% interest in NGPL Holdings. The outstanding principal amount of our related party promissory note receivable at both December 31, 2022 and 2021 was $375 million. For the years ended December 31, 2022, 2021 and 2020, we recognized $25 million, $27 million and $34 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. During the fourth quarter of 2020, we sold our Preferred A and common equity investment in Watco, and recognized a pre-tax gain of $10 million within “Other, net” on our accompanying consolidated statement of income for the year ended December 31, 2020.

(c)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 (see Note 4 “Gains and Losses on Divestitures, Impairments, and Other Write-downs—Investment in Ruby.)

(d)As of December 31, 2022, we operated Ruby and owned an effective 50% interest. As of January 13, 2023, we no longer own an interest in Ruby. For further information regarding Ruby’s bankruptcy filing, see Note 4 “Gains and Losses on Divestitures, Impairments, and Other Write-downs—Investment in Ruby—Ruby Chapter 11 Bankruptcy Filing.”

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	2022		2021(a)		2020
	(In millions)
Revenues	$	5,967	$	5,537	$	5,200
Costs and expenses	4,204		6,153		4,325
Net income (loss)	$	1,763	$	(616)	$	875


	December 31,
Balance Sheet	2022		2021
	(In millions)
Current assets	$	1,470	$	1,314
Non-current assets	23,361		23,154
Current liabilities	1,622		1,808
Non-current liabilities	10,207		10,001
Partners’/owners’ equity	13,002		12,659

(a)2021 amounts include a non-cash impairment charge of $2.2 billion recorded by Ruby.

Goodwill (Tables)

12 Months Ended

Dec. 31, 2022

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

Changes in the amounts of our goodwill for each of the years ended December 31, 2022 and 2021 are summarized by reporting unit as follows:


	Natural Gas Pipelines Regulated		Natural Gas Pipelines Non-Regulated		CO2		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	$	—	$	26,637
Accumulated impairment losses	(1,643)		(2,597)		(600)		(1,197)		(70)		(679)		—		(6,786)
December 31, 2020	14,249		2,343		928		1,378		151		802		—		19,851

Acquisitions	—		—		—		—		—		—		63		63


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

Gross goodwill	15,892		4,940		1,528		2,575		221		1,481		114		26,751
Accumulated impairment losses	(1,643)		(2,597)		(600)		(1,197)		(70)		(679)		—		(6,786)
December 31, 2022	$	14,249	$	2,343	$	928	$	1,378	$	151	$	802	$	114	$	19,965

(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.

- Definition

Tabular disclosure of goodwill by reportable segment and in total which includes a rollforward schedule.

+ References

Reference 1: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (h)
-URI https://asc.fasb.org/extlink&oid=121556970&loc=d3e13816-109267

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=121556970&loc=d3e13816-109267

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (g)
-URI https://asc.fasb.org/extlink&oid=121556970&loc=d3e13816-109267

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI https://asc.fasb.org/extlink&oid=121556970&loc=d3e13816-109267

Reference 5: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (e)
-URI https://asc.fasb.org/extlink&oid=121556970&loc=d3e13816-109267

Reference 6: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=121556970&loc=d3e13816-109267

Reference 7: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1A
-URI https://asc.fasb.org/extlink&oid=121556970&loc=SL108378252-109267

Reference 8: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (f)
-URI https://asc.fasb.org/extlink&oid=121556970&loc=d3e13816-109267

Reference 9: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=121556970&loc=d3e13816-109267

Reference 10: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 2
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=121556970&loc=d3e13854-109267

Reference 11: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 55
-Paragraph 24
-URI https://asc.fasb.org/extlink&oid=122137925&loc=d3e14258-109268

Reference 12: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=121556970&loc=d3e13816-109267

+ Details

Debt (Tables)

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Schedule of Debt

The following table provides detail on the principal amount of our outstanding debt balances:


	December 31,
	2022		2021
	(In millions)
Credit facility and commercial paper borrowings	$	—	$	—
Corporate senior notes(a)
4.15%, due March 2022	—		375
1.50%, due March 2022(b)	—		853
3.95%, due September 2022	—		1,000
3.15%, due January 2023	1,000		1,000
Floating rate, due January 2023(c)	250		250
3.45%, due February 2023	625		625
3.50%, due September 2023	600		600
5.625%, due November 2023	750		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(b)	535		569
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		—
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


	December 31,
	2022		2021
3.25%, due August 2050	500		500
3.60%, due February 2051	1,050		1,050
5.45%, due January 2052	750		—
7.45%, due March 2098	26		26
TGP senior notes(a)
7.00%, due March 2027	300		300
7.00%, due October 2028	400		400
2.90%, due March 2030	1,000		1,000
8.375%, due June 2032	240		240
7.625%, due April 2037	300		300
EPNG senior notes(a)
8.625%, due January 2022	—		260
7.50%, due November 2026	200		200
3.50%, due February 2032	300		—
8.375%, due June 2032	300		300
CIG senior notes(a)
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	348		364
Trust I Preferred Securities, 4.75%, due March 2028(d)	220		221
Other miscellaneous debt(e)	242		248
Total debt – KMI and Subsidiaries	31,673		32,418
Less: Current portion of debt	3,385		2,646
Total long-term debt – KMI and Subsidiaries(f)	$	28,288	$	29,772

(a)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.

(b)Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2022 exchange rate of 1.0705 U.S. dollars per Euro and at the December 31, 2021 exchange rate of 1.1370 U.S. dollars per Euro. As of December 31, 2022 and 2021, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in a decrease of $8 million and an increase of $26 million, respectively, related to the 2.25% series, and as of December 31, 2021, an increase of $38 million to our debt balance related to the 1.50% series. As of December 31, 2022, we had outstanding associated cross-currency swap agreements which are designated as cash flow hedges.

(c)As of December 31, 2022, we had outstanding an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge.

(d)Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2022, 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, 2022 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.

(e)Includes finance lease obligations with monthly installments. The lease terms expire between 2026 and 2070.

(f)Excludes our “Debt fair value adjustments” which, as of December 31, 2022 and 2021, increased our combined debt balances by $115 million and $902 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,
	2022		2021

	(In millions)
$3.5 billion credit facility due August 20, 2027	$	—	$	—
$500 million credit facility due November 16, 2023	—		—
Commercial paper notes	—		—
Current portion of senior notes
8.625%, due January 2022(a)	—		260
4.15%, due March 2022(a)	—		375
1.50%, due March 2022(a)(b)	—		853
3.95% due September 2022(c)	—		1,000
3.15% due January 2023(d)	1,000		—
Floating rate, due January 2023(d)(e)	250		—
3.45% due February 2023	625		—
3.50% due September 2023	600		—
5.625%, due November 2023	750		—
Trust I Preferred Securities, 4.75% due March 2028(f)	111		111
Current portion of other debt	49		47
Total current portion of debt	$	3,385	$	2,646

(a)We repaid the principal amount of these senior notes during the first quarter of 2022.

(b)Denominated in Euros.

(c)We repaid the principal amount of these senior notes on June 1, 2022.

(d)On January 17, 2023, we repaid these senior notes using cash on hand and short-term borrowings.

(e)These senior notes have an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge.

(f)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, 2022, are summarized as follows:


Year	Total
	(In millions)
2023	$	3,385
2024	1,925
2025	1,566
2026	1,102
2027	890
Thereafter	22,805
Total	$	31,673

Schedule of Debt Fair Value Adjustments

The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets:


	December 31,
	2022		2021
	(In millions)
Purchase accounting debt fair value adjustments	$	472	$	498
Carrying value adjustment to hedged debt	(367)		376
Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a)	204		223
Unamortized debt discounts, net	(68)		(71)
Unamortized debt issuance costs	(126)		(124)
Total debt fair value adjustments	$	115	$	902

(a)As of December 31, 2022, the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 12 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, 2022				December 31, 2021
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Total debt	$	31,788	$	30,070	$	33,320	$	37,775

(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $195 million and $218 million as of December 31, 2022 and 2021, respectively.

Share-based Compensation and Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2022

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, 2021	12,617	$	17.63
Granted	4,110	17.31
Vested	(2,744)	20.94
Forfeited	(695)	17.17
Outstanding at December 31, 2022	13,288	$	16.87

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,
	2022		2021		2020
	(In millions, except per share amounts)
Weighted average grant date fair value per share	$	17.31	$	17.44	$	15.10
Intrinsic value of awards vested during the year	47		77		59
Restricted stock awards expense(a)	60		59		73
Restricted stock awards capitalized(a)	9		9		11
(a)We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements.

			December 31, 2022
Unrecognized restricted stock awards compensation costs, less estimated forfeitures (in millions)					$	104
Weighted average remaining amortization period					1.99 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, 2022 and 2021:


	Pension Benefits				OPEB
	2022		2021		2022		2021
	(In millions)
Change in benefit obligation:
Benefit obligation at beginning of period	$	2,658	$	2,844	$	257	$	299
Service cost	55		53		1		1
Interest cost	57		45		5		4
Actuarial gain	(503)		(80)		(44)		(21)
Benefits paid	(190)		(204)		(26)		(28)
Participant contributions	—		—		1		1
Other	—		—		1		1




Benefit obligation at end of period	2,077		2,658		195		257

Change in plan assets:
Fair value of plan assets at beginning of period	2,231		2,199		382		361
Actual return on plan assets	(350)		180		(63)		40
Employer contributions	50		56		7		7
Participant contributions	—		—		1		1
Other	—		—		1		1
Benefits paid	(190)		(204)		(26)		(28)



Fair value of plan assets at end of period	1,741		2,231		302		382
Funded status - net (liability) asset at December 31,	$	(336)	$	(427)	$	107	$	125

Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)	$	—	$	—	$	239	$	302
Current benefit liability	—		—		(15)		(18)
Non-current benefit liability	(336)		(427)		(117)		(159)
Funded status - net (liability) asset at December 31,	$	(336)	$	(427)	$	107	$	125

Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:
Unrecognized net actuarial (loss) gain	$	(455)	$	(495)	$	135	$	176
Unrecognized prior service (cost) credit	(1)		(2)		4		6
Accumulated other comprehensive (loss) income	$	(456)	$	(497)	$	139	$	182

Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:
Accumulated benefit obligation	$	2,047	$	2,608	$	167	$	219
Fair value of plan assets	1,741		2,231		34		42

(a)2022 and 2021 OPEB amounts include $45 million and $54 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, 2022, by asset category, are as follows:

Pension Benefits

OPEB

Cash

0% to 23%

Equities

42% to 52%

42% to 72%

Fixed income securities

37% to 47%

25% 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, 2022 and 2021:


	Pension Assets
	2022						2021
	Level 1		Level 2		Total		Level 1		Level 2		Total
	(In millions)
Measured within fair value hierarchy
Cash	$	—	$	—	$	—	$	11	$	—	$	11
Short-term investment funds	—		27		27		—		25		25
Equities(a)	152		—		152		153		—		153
Fixed income securities	—		421		421		—		566		566

Subtotal	$	152	$	448	600		$	164	$	591	755
Measured at NAV
Common/collective trusts(b)					1,138						1,389
Private investment funds(c)					—						39
Private limited partnerships(d)					3						48


Subtotal					1,141						1,476
Total plan assets fair value					$	1,741					$	2,231

(a)Plan assets include $110 million and $97 million of KMI Class P common stock for 2022 and 2021, respectively.

(b)Common/collective trust funds were invested in approximately 66% equities, 22% fixed income securities and 12% real estate in 2022 and 83% equities and 17% fixed income securities in 2021.

(c)Private investment funds were invested in 100% fixed income securities in 2021.

(d)Includes assets invested in real estate, venture and buyout funds.


	OPEB Assets
	2022				2021
	Level 1		Level 2		Total		Level 1		Level 2		Total
	(In millions)
Measured within fair value hierarchy

Short-term investment funds	$	—	$	3	$	3	$	—	$	3	$	3





Measured at NAV
Common/collective trusts(a)					299						379



Total plan assets fair value					$	302					$	382

(a)Common/collective trust funds were invested in approximately 61% equities and 39% fixed income securities for 2022 and 63% equities and 37% fixed income securities for 2021.

Schedule of Expected Payment of Future Benefits and Employer Contributions

Employer Contributions and Expected Payment of Future Benefits. As of December 31, 2022, we expect the following cash flows under our plans:


	Pension Benefits		OPEB
	(In millions)
Contributions expected in 2023	$	50	$	—

Benefit payments expected in:
2023	$	210	$	26
2024	206		24
2025	202		23
2026	199		21
2027	191		20
2028 - 2032	861		76

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, 2022 and 2021 and net benefit costs of our pension and OPEB plans for 2022, 2021 and 2020:


					Pension Benefits				OPEB
					2022		2021		2022		2021
Assumptions related to benefit obligations:
Discount rate					5.41	%	2.74	%	5.38	%	2.56	%
Rate of compensation increase					3.50	%	3.50	%	n/a		n/a
Interest crediting rate					3.50	%	3.01	%	n/a		n/a

	Pension Benefits						OPEB
	2022		2021		2020		2022		2021		2020
Assumptions related to benefit costs:
Discount rate	2.74	%	2.27	%	3.17	%	2.56	%	2.08	%	3.03	%



Expected return on plan assets	6.50	%	6.25	%	6.75	%	5.75	%	5.75	%	6.50	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%	n/a		n/a		n/a
Interest crediting rate	3.01	%	2.57	%	3.71	%	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
	2022		2021		2020		2022		2021		2020
	(In millions)
Components of net benefit cost (credit):
Service cost	$	55	$	53	$	59	$	1	$	1	$	1
Interest cost	57		45		71		5		4		8
Expected return on assets	(142)		(133)		(137)		(17)		(16)		(16)
Amortization of prior service cost (credit)	1		—		1		(3)		(5)		(5)
Amortization of net actuarial loss (gain)	29		52		40		(18)		(17)		(13)

Net benefit cost (credit)	—		17		34		(32)		(33)		(25)

Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net (gain) loss arising during period	(11)		(127)		157		24		(40)		(43)

Amortization or settlement recognition of net actuarial (loss) gain	(29)		(52)		(40)		17		17		13
Amortization of prior service (cost) credit	(1)		—		(1)		2		3		3

Total recognized in total other comprehensive (income) loss(a)	(41)		(179)		116		43		(20)		(27)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss	$	(41)	$	(162)	$	150	$	11	$	(53)	$	(52)

(a)Excludes $4 million, $3 million and $2 million for the years ended December 31, 2022, 2021 and 2020 respectively, associated with other plans.

Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2022

Stockholders' Equity Note [Abstract]

Class of Treasury Stock

On July 19, 2017, our board of directors approved a $2 billion share buy-back program that began in December 2017. On January 18, 2023, our board of directors approved an increase in our share repurchase authorization to $3 billion. Activity under the buy-back program is as follows:


		Year Ended December 31,
		2022		2021		2020
	(In millions, except per share amounts)
Total value of shares repurchased		$	368	$	—	$	50
Total number of shares repurchased		21		—		4
Average repurchase price per share		$	16.94	$	—	$	13.93

Schedule of Dividends Paid and Payable

The following table provides information about our per share dividends:


	Year Ended December 31,
	2022		2021		2020
Per share cash dividend declared for the period	$	1.11	$	1.08	$	1.05
Per share cash dividend paid in the period	1.1025		1.0725		1.0375

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 gains/(losses) on cash flow hedge derivatives		Pension and other postretirement liability adjustments		Total Accumulated other comprehensive loss
	(In millions)
Balance at December 31, 2019	$	(7)	$	(326)	$	(333)
Other comprehensive gain (loss) before reclassifications	249		(68)		181
Gains reclassified from accumulated other comprehensive loss	(255)		—		(255)
Net current-period change in accumulated other comprehensive loss	(6)		(68)		(74)
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)

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2022

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,
	2022		2021
	(In millions)
Balance sheet location
Accounts receivable	$	39	$	38
Other current assets	3		4


	$	42	$	42

Current portion of debt	$	6	$	6
Accounts payable	19		21
Other current liabilities	8		4
Long-term debt	142		148
Other long-term liabilities and deferred credits	47		56

	$	222	$	235


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Income statement location

Revenues	$	172	$	164	$	206



Operating Costs, Expenses and Other
Costs of sales	$	134	$	145	$	116

Other operating expenses	50		52		119

Risk Management (Tables)

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of December 31, 2022, 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	(18.4)	MMBbl
Crude oil basis	(4.2)	MMBbl
Natural gas fixed price	(62.6)	Bcf
Natural gas basis	(40.1)	Bcf
NGL fixed price	(0.6)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.0)	MMBbl
Crude oil basis	(9.2)	MMBbl
Natural gas fixed price	(7.1)	Bcf
Natural gas basis	(44.7)	Bcf
NGL fixed price	(0.8)	MMBbl

Schedule of Interest Rate Derivatives [Table Text Block]

The following table summarizes our outstanding interest rate contracts as of December 31, 2022:

Notional amount

Accounting treatment

Maximum term

(In millions)

Derivatives designated as hedging instruments

Fixed-to-variable interest rate contracts(a)(b)

$

7,500

Fair value hedge

March 2035

Variable-to-fixed interest rate contracts

250

Cash flow hedge

January 2023

Derivatives not designated as hedging instruments

Variable-to-fixed interest rate contracts

1,250

Mark-to-Market

December 2023

(a)The principal amount of hedged senior notes consisted of $1,300 million included in “Current portion of debt” and $6,200 million included in “Long-term debt” on our accompanying consolidated balance sheet.

(b)During the year ended December 31, 2022, 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.

Schedule of Foreign Exchange Contracts, Statement of Financial Position [Table Text Block]

The following table summarizes our outstanding foreign currency contracts as of December 31, 2022:

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 swaps 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
		Derivatives Asset				Derivatives Liability
		December 31,				December 31,
		2022		2021		2022		2021
	Location	Fair value				Fair value
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	$	150	$	61	$	(156)	$	(141)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	6		3		(91)		(94)
Subtotal		156		64		(247)		(235)
Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	—		101		(144)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	39		284		(261)		(15)
Subtotal		39		385		(405)		(18)
Foreign currency contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	—		35		(3)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		6		(32)		—
Subtotal		—		41		(35)		(3)
Total		195		490		(687)		(256)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	80		11		(162)		(31)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	23		1		(19)		(6)
Subtotal		103		12		(181)		(37)
Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	1		12		—		—





Total		104		24		(181)		(37)
Total derivatives		$	299	$	514	$	(868)	$	(293)

Schedule of Derivative Assets and Liabilities at Fair Value [Table Text Block]

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, 2022
Energy commodity derivative contracts(b)	$	115	$	144	$	—	$	259	$	(186)	$	—	$	73
Interest rate contracts	—		40		—		40		—		—		40

As of December 31, 2021
Energy commodity derivative contracts(b)	$	56	$	20	$	—	$	76	$	(53)	$	(20)	$	3
Interest rate contracts	—		397		—		397		(9)		—		388
Foreign currency contracts	—		41		—		41		(3)		—		38


	Balance sheet liability fair value measurements by level
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral posted(a)		Net amount
	(In millions)
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)
As of December 31, 2021
Energy commodity derivative contracts(b)	(15)		(257)		—		(272)		53		—		(219)
Interest rate contracts	—		(18)		—		(18)		9		—		(9)
Foreign currency contracts	—		(3)		—		(3)		3		—		—

(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 Statement 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,
		2022		2021		2020
		(In millions)
Interest rate contracts	Interest, net	$	(738)	$	(322)	$	335

Hedged fixed rate debt(a)	Interest, net	$	743	$	326	$	(343)

(a)As of December 31, 2022, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $367 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheets.


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)						Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Year Ended							Year Ended
	December 31,							December 31,
	2022		2021		2020			2022		2021		2020
	(In millions)							(In millions)
Energy commodity derivative contracts	$	(338)	$	(475)	$	240	Revenues—Commodity sales	$	(491)	$	(271)	$	222

							Costs of sales	144		20		(14)
Interest rate contracts(c)	7		5		(8)		Interest, net	—		—		—
Foreign currency contracts	(73)		(93)		92		Other, net	(68)		(105)		125
Total	$	(404)	$	(563)	$	324	Total	$	(415)	$	(356)	$	333

(a)We expect to reclassify an approximately $92 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2022 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, 2022, 2021 and 2020, we recognized approximate gains of $121 million, $41 million and no gains, 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,
		2022		2021		2020
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	137	$	(652)	$	(1)

	Costs of sales	(190)		152		25
	Earnings from equity investments(a)	(11)		(5)		—
Interest rate contracts	Interest, net	(10)		12		—
Total(b)		$	(74)	$	(493)	$	24

(a)Amounts represent our share of an equity investee’s income (loss).

(b)The years ended December 31, 2022, 2021 and 2020 include approximate losses of $11 million, $479 million and $11 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

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+ Details

Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2022

Revenue from Contract with Customer [Abstract]

Schedule of Disaggregation of Revenue

The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source:


	Year Ended December 31, 2022
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		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		CO2		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


	Year Ended December 31, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	3,345	$	271	$	756	$	1	$	(3)	$	4,370
Fee-based services	714		905		395		42		—		2,056
Total services	4,059		1,176		1,151		43		(3)		6,426
Commodity sales
Natural gas sales	2,038		—		—		1		(7)		2,032
Product sales	562		358		14		735		(30)		1,639

Total commodity sales	2,600		358		14		736		(37)		3,671
Total revenues from contracts with customers	6,659		1,534		1,165		779		(40)		10,097
Other revenues(c)
Leasing services(d)	466		166		557		47		—		1,236
Derivatives adjustments on commodity sales	18		—		—		203		—		221
Other	116		21		—		9		—		146
Total other revenues	600		187		557		259		—		1,603
Total revenues	$	7,259	$	1,721	$	1,722	$	1,038	$	(40)	$	11,700

(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 indexed-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, 2022 that we will invoice or transfer from contract liabilities and recognize in future periods:


Year	Estimated Revenue
	(In millions)
2023	$	4,312
2024	3,401
2025	2,800
2026	2,466
2027	2,132
Thereafter	12,340
Total	$	27,451

Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

Financial information by segment follows:


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	12,659	$	11,644	$	7,222
Intersegment revenues	27		65		37
Products Pipelines	3,418		2,245		1,721

Terminals
Revenues from external customers	1,789		1,712		1,719
Intersegment revenues	3		3		3
CO2	1,334		1,009		1,038
Corporate and intersegment eliminations	(30)		(68)		(40)
Total consolidated revenues	$	19,200	$	16,610	$	11,700


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Operating expenses(a)
Natural Gas Pipelines	$	8,562	$	7,000	$	3,457
Products Pipelines	2,391		1,239		779
Terminals	853		793		762
CO2	554		289		404
Corporate and intersegment eliminations	(9)		(34)		(4)
Total consolidated operating expenses	$	12,351	$	9,287	$	5,398


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Other expense (income)(b)
Natural Gas Pipelines	$	(13)	$	1,597	$	1,009
Products Pipelines	(12)		—		21
Terminals	(14)		32		(50)
CO2	(1)		(8)		950

Corporate	1		(4)		—
Total consolidated other expense (income)	$	(39)	$	1,617	$	1,930


	Year Ended December 31,
	2022		2021		2020
	(In millions)
DD&A
Natural Gas Pipelines	$	1,096	$	1,099	$	1,062
Products Pipelines	336		335		347
Terminals	458		440		438
CO2	272		236		291
Corporate	24		25		26
Total consolidated DD&A	$	2,186	$	2,135	$	2,164


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Earnings from equity investments and amortization of excess cost of equity investments
Natural Gas Pipelines	$	650	$	435	$	551
Products Pipelines	33		34		45
Terminals	14		15		22
CO2	31		29		22
Total consolidated equity earnings	$	728	$	513	$	640


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Other, net-income (expense)
Natural Gas Pipelines	$	(19)	$	216	$	11
Products Pipelines	—		1		1
Terminals	8		3		13
Corporate	66		62		31
Total consolidated other, net-income (expense)	$	55	$	282	$	56


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Segment EBDA(c)
Natural Gas Pipelines	$	4,801	$	3,815	$	3,483
Products Pipelines	1,107		1,064		977
Terminals	975		908		1,045
CO2	819		760		(292)

Total Segment EBDA	7,702		6,547		5,213
DD&A	(2,186)		(2,135)		(2,164)
Amortization of excess cost of equity investments	(75)		(78)		(140)
General and administrative and corporate charges	(593)		(623)		(653)
Interest, net	(1,513)		(1,492)		(1,595)
Income tax expense	(710)		(369)		(481)
Total consolidated net income	$	2,625	$	1,850	$	180


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Capital expenditures
Natural Gas Pipelines	$	666	$	570	$	945
Products Pipelines	—		122		122
Terminals	552		332		433
CO2	371		230		186
Corporate	32		27		21
Total consolidated capital expenditures	$	1,621	$	1,281	$	1,707


	December 31,
	2022		2021
	(In millions)
Investments
Natural Gas Pipelines	$	6,993	$	6,887
Products Pipelines	445		465
Terminals	128		137
CO2	87		89

Total consolidated investments	$	7,653	$	7,578


	December 31,
	2022		2021
	(In millions)
Other intangibles, net
Natural Gas Pipelines	$	439	$	557
Products Pipelines	777		868
Terminals	38		51
CO2	555		202

Total consolidated other intangibles, net	$	1,809	$	1,678


	December 31,
	2022		2021
	(In millions)
Assets
Natural Gas Pipelines	$	47,978	$	47,746
Products Pipelines	8,985		9,088
Terminals	8,357		8,513
CO2	3,449		2,843

Corporate assets(d)	1,309		2,226

Total consolidated assets	$	70,078	$	70,416

(a)Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

(b)Includes (gain) loss on divestitures and impairments, net and other income, net.

(c)Includes revenues, earnings from equity investments, and other, net, less operating expenses, (gain) loss on divestitures and impairments, net and other income, net.

(d)Includes cash and cash equivalents, margin and restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy balances) 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,
	2022		2021		2020
	(In millions)
Revenues from external customers
U.S.	$	19,036	$	16,479	$	11,625

Mexico and other foreign	164		131		75
Total consolidated revenues from external customers	$	19,200	$	16,610	$	11,700


	December 31,
	2022		2021		2020
	(In millions)
Long-term assets, excluding goodwill and other intangibles
U.S.	$	44,425	$	44,916	$	46,384
Mexico and other foreign	75		78		81
Canada	1		1		1
Total consolidated long-lived assets	$	44,501	$	44,995	$	46,466

Leases (Tables)

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Lease, Cost [Table Text Block]

Following are components of our lease cost:


	Year Ended December 31,
	2022		2021		2020
	(In millions)
Operating leases	$	62	$	60	$	55
Short-term and variable leases	101		109		101
Total lease cost	$	163	$	169	$	156

Other information related to our operating leases are as follows:


	Year Ended December 31,
	2022			2021			2020
	(In millions, except lease term and discount rate)
Operating cash flows from operating leases	$	(132)		$	(137)		$	(131)
Investing cash flows from operating leases	(31)			(32)			(25)
ROU assets obtained in exchange for operating lease obligations, net of retirements	22			59			20
Amortization of ROU assets	50			47			46


Weighted average remaining lease term	9.8 years			10.39 years			11.56 years
Weighted average discount rate	4.26		%	3.95		%	4.27		%

Amounts recognized in the accompanying consolidated balance sheets are as follows:


		December 31,
Lease Activity(a)	Balance sheet location	2022		2021
		(In millions)
ROU assets	Deferred charges and other assets	$	287	$	315
Short-term lease liability	Other current liabilities	47		45
Long-term lease liability	Other long-term liabilities and deferred credits	240		270

(a)We have immaterial financing leases recorded as of December 31, 2022 and 2021.

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2022 are as follows:


Year	Commitment
	(In millions)
2023	$	58
2024	50
2025	40
2026	32
2027	29
Thereafter	166
Total lease payments	375
Less: Interest	(88)
Present value of lease liabilities	$	287

Summary of Significant Accounting Policies - Accounts Receivable, Net (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Allowance for Credit Loss	$ 1	$ 1

Summary of Significant Accounting Policies - Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Balance at beginning of period	$ 196	$ 215
Accretion expense	12	7
New obligations	2	6
Settlements	(6)	(8)
Revisions to previous estimates	0	(24)
Balance at end of period	204	196
Asset Retirement Obligation, Current	$ 3	$ 4

Summary of Significant Accounting Policies - Goodwill (Details)	May 31, 2022 segment
Accounting Policies [Abstract]
Number of Reporting Units	7

Summary of Significant Accounting Policies - Other Intangibles (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Intangibles
Weighted Average Amortization Period (years)	11 years 2 months 12 days
Gross	$ 3,382	$ 3,036
Accumulated amortization	(1,573)	(1,358)
Net carrying amount	1,809	1,678
Amortization expense	253	$ 237	$ 212
Estimated amortization expense:
2023	201
2024	175
2025	170
2026	168
2027	$ 167

Summary of Significant Accounting Policies - Operations and Maintenance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
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	$ 367	$ 180	$ 319

Summary of Significant Accounting Policies - Leases (Details)	Dec. 31, 2022
Minimum
Lessee, Operating Lease, Remaining Lease Term	1 year
Maximum
Lessee, Operating Lease, Remaining Lease Term	48 years

Summary of Significant Accounting Policies - Redeemable NCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Elba Liquefaction Company L.L.C.
Variable Interest Entity [Line Items]
Net income (loss) attributable to redeemable noncontrolling interest	$ 58	$ 54

Summary of Significant Accounting Policies - Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Regulatory Assets and Liabilities [Line Items]
Current regulatory assets	$ 73	$ 66
Non-current regulatory assets	183	220
Total regulatory assets(a)	256	286
Current regulatory liabilities	50	32
Non-current regulatory liabilities	175	163
Total regulatory liabilities(b)	225	$ 195
Regulatory assets recoverable without earning a return	$ 143
Regulatory assets, weighted average remaining recovery period	10 years
Remaining Amounts of Regulatory Liabilities Subject to Crediting Period	$ 110
Remaining Recovery Period of Regulatory Liabilities Subject to Defined Crediting Period	15 years
Remaining Amounts of Regulatory Liabilities Not Subject to Defined Crediting Period	$ 65
Loss on Disposal of Assets
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	110
Income Tax Gross Up on AFUDC Equity
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	45
Other Regulatory Assets (Liabilities)
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	$ 101

Summary of Significant Accounting Policies - Earnings per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Stockholders	$ 2,548	$ 1,784	$ 119
Less: Net Income Allocated to Restricted stock awards	$ (13)	$ (14)	$ (13)
Basic Weighted Average Shares Outstanding	2,258	2,266	2,263
Basic Earnings Per Share	$ 1.12	$ 0.78	$ 0.05
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	$ 2,535	$ 1,770	$ 106
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 - Schedule of Recognized Identified Assets and Liabilities Assumed (Details) $ in Millions					5 Months Ended	12 Months Ended
	Aug. 11, 2022 USD ($) assets	Jul. 19, 2022 USD ($) assets	Aug. 20, 2021 USD ($) facilities	Jul. 09, 2021 USD ($)	Nov. 24, 2021 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Business Acquisition [Line Items]
Resulting goodwill						$ 19,965	$ 19,914	$ 19,851
Equity Method Investments						$ 7,653	$ 7,578
Weighted average amortization period, customer relationship						11 years 2 months 12 days
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
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
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)
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						50.00%
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
Resulting goodwill				$ 0
Payments to acquire businesses					$ 1,258
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				12.00%

Acquisitions and Divestitures - Sale of an Interest in ELC (Details) - USD ($) $ in Millions		12 Months Ended
	Sep. 26, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Variable Interest Entity [Line Items]
Proceeds from sale of noncontrolling interests (Note 3)		$ 557	$ 0	$ 0
Impact of change in ownership interest in subsidiary		501
ASSETS
Current assets		3,803	3,829
Property, plant and equipment, net		35,599	35,653
Deferred charges and other assets		1,249	1,649
Liabilities [Abstract]
Current liabilities		6,930	5,821
Other long-term liabilities and deferred credits		2,008	$ 2,000
Elba Liquefaction Company L.L.C.
ASSETS
Current assets		34
Property, plant and equipment, net		1,197
Deferred charges and other assets		6
Liabilities [Abstract]
Current liabilities		15
Other long-term liabilities and deferred credits		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 - Sale of an interest in NGPL Holdings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Mar. 08, 2021
Schedule of Equity Method Investments [Line Items]
Pre-tax gain on sale of interest in equity investment	$ 0	$ 206	$ 0
ArcLight Capital Partners, LLC
Schedule of Equity Method Investments [Line Items]
Related party promissory note receivable from NGPL Holdings				$ 125
NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	37.50%
Proceeds from sales of assets and investments		412
Related party promissory note receivable from NGPL Holdings	$ 375	375		$ 500
Interest rate, stated percentage	6.75%			6.75%
NGPL Holdings, LLC \| Natural Gas Pipelines
Schedule of Equity Method Investments [Line Items]
Pre-tax gain on sale of interest in equity investment	$ 0	$ 206	$ 0
NGPL Holdings, LLC \| ArcLight Capital Partners, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest				25.00%
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	37.50%

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Pre-tax (gains) losses on divestitures, impairments and other write-downs, net		$ (32)	$ 1,535	$ 1,922
Impairments of long-lived assets			1,634	376
Impairment of goodwill				1,600
Gain on sale of interest in equity investment		0	$ (206)	0
Impairment of long-lived assets (Extensible)			Gain (Loss) on Sale of Assets and Asset Impairment Charges
Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of long-lived assets		0	$ 1,600	0
Impairment of goodwill		0	0	1,000
(Gains) losses on divestitures of long-lived assets		(10)	(1)	10
Products Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of long-lived assets		0	0	21
(Gains) losses on divestitures of long-lived assets		(12)	0	0
Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of long-lived assets		0	34	5
(Gains) losses on divestitures of long-lived assets		(9)	2	(54)
Gain on sale of interest in equity investment		0	0	(10)
Terminals \| Staten Island Terminal
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gains) losses on divestitures of long-lived assets				(55)
CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of long-lived assets		0	0	350
Impairment of goodwill		0	0	600
(Gains) losses on divestitures of long-lived assets		(1)	(8)	0
Other
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gains) losses on divestitures of long-lived assets		0	(3)	0
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	(206)	0
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	$ 117	$ 0

Gains and Losses on Divestitures, Impairments and Other Write-downs - Long Lived Assets (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Impairments of long-lived assets			$ 1,634	$ 376
CO2
Property, Plant and Equipment [Line Items]
Impairments of long-lived assets		$ 0	0	350
Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Impairments of long-lived assets		$ 0	$ 1,600	$ 0
Natural Gas Pipelines \| Valuation Technique, Discounted Cash Flow
Property, Plant and Equipment [Line Items]
Estimated weighted average cost of capital			8.50%
Oil and Gas Properties [Member] \| CO2
Property, Plant and Equipment [Line Items]
Impairments of long-lived assets	$ 350
Oil and Gas Properties [Member] \| CO2 \| Valuation Technique, Discounted Cash Flow
Property, Plant and Equipment [Line Items]
Estimated weighted average cost of capital	10.50%

Gains and Losses on Divestitures, Impairments and Other Write-downs - Goodwill (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020
Goodwill [Line Items]
Impairment of goodwill		$ 1,600
CO2
Goodwill [Line Items]
Impairment of goodwill	$ 600
CO2 \| Maximum
Goodwill [Line Items]
Fair value in excess of their respective carrying values (percentage)		10.00%
CO2 \| Valuation Technique, Discounted Cash Flow
Goodwill [Line Items]
Estimated weighted average cost of capital	9.25%
Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Impairment of goodwill		$ 1,000
Natural Gas Pipelines Non-Regulated \| Valuation, Market Approach
Goodwill [Line Items]
Fair Value Measurement Inputs and Valuation Techniques, Weighting Of Approach		0.25
Enterprise Value to EBITDA Multiple Valuation		10
Natural Gas Pipelines Non-Regulated \| Valuation, Income Approach
Goodwill [Line Items]
Fair Value Measurement Inputs and Valuation Techniques, Weighting Of Approach		0.75
Natural Gas Pipelines Non-Regulated \| Valuation Technique, Discounted Cash Flow
Goodwill [Line Items]
Period Used For Projection		6 years 6 months
Estimated weighted average cost of capital		8.00%
Natural Gas Pipelines Non-Regulated \| Weighted Market Approach and Income Approach [Member]
Goodwill [Line Items]
Enterprise Value to EBITDA Multiple Valuation		11
Terminals \| Maximum
Goodwill [Line Items]
Fair value in excess of their respective carrying values (percentage)		10.00%
Products Pipelines \| Maximum
Goodwill [Line Items]
Fair value in excess of their respective carrying values (percentage)		10.00%

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Impairment of Long-lived assets and equity investments [Line Items]
Current portion of debt		$ 3,385.0	$ 2,646.0
Equity Method Investments		7,653.0	7,578.0
Ruby Pipeline Holding Company LLC
Impairment of Long-lived assets and equity investments [Line Items]
Equity Method Investments		0.0	0.0
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		475.0
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	$ 0.0	$ 117.0	$ 0.0

Income Taxes - Income Before Income Taxes and Income Tax Provision (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Components of Income Before Income Taxes
U.S.	$ 3,318	$ 2,217	$ 663
Foreign	17	2	(2)
Income Before Income Taxes	3,335	2,219	661
Current tax expense (benefit)
Federal	0	0	(20)
State	14	11	9
Foreign	4	3	147
Total	18	14	136
Deferred tax expense (benefit)
Federal	642	334	440
State	50	21	49
Foreign	0	0	(144)
Total	692	355	345
Total	$ 710	$ 369	$ 481

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Amount:
Federal income tax	$ 700	$ 466	$ 139
Net effects of noncontrolling interests	(16)	(14)	(13)
State income tax, net of federal benefit	69	50	52
Dividend received deduction	(36)	(46)	(27)
Release of valuation allowance	0	(38)	0
Nondeductible goodwill	0	0	336
General business credit	0	(36)	0
Federal refunds	0	0	(20)
Other	(7)	(13)	14
Total	$ 710	$ 369	$ 481
Percent:
Federal income tax, percent	21.00%	21.00%	21.00%
Net effects of noncontrolling interests, percent	(0.50%)	(0.60%)	(2.00%)
State income tax, net of federal benefit, percent	2.00%	2.20%	7.90%
Dividend received deduction, percent	(1.10%)	(2.10%)	(4.10%)
Release of valuation allowance, percent	0.00%	(1.70%)	0.00%
Nondeductible goodwill, percent	0.00%	0.00%	50.80%
General business credit, percent	0.00%	(1.60%)	0.00%
Federal refunds, percent	0.00%	0.00%	(3.00%)
Other, percent	(0.20%)	(0.60%)	2.20%
Total, percent	21.20%	16.60%	72.80%

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets
Employee benefits	$ 116	$ 154
Net operating loss carryforwards	2,007	1,476
Tax credit carryforwards	303	301
Interest expense limitation	82	0
Other	192	229
Valuation allowances	(79)	(93)
Total deferred tax assets	2,621	2,067
Deferred tax liabilities
Property, plant and equipment	163	166
Investments	3,056	1,769
Other	25	17
Total deferred tax liabilities	3,244	1,952
Net deferred tax (liability)	$ (623)
Net deferred tax asset		$ 115

Income Taxes - Valuation Allowance (Details) $ in Millions	12 Months Ended
Income Taxes - Valuation Allowance (Details) $ in Millions	Dec. 31, 2022 USD ($)
Valuation Allowance [Line Items]
Balance at beginning of period	$ 93
Balance at end of period	79
Statute expirations for federal and state NOL and foreign tax credits
Valuation Allowance [Line Items]
Change in valuation allowances	(16)
Currency Fluctuation
Valuation Allowance [Line Items]
Change in valuation allowances	$ 2

Income Taxes - Deferred Tax Assets and Valuation Allowances (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets and valuation allowances:
Net operating loss, deferred tax assets	$ 2,007	$ 1,476
Tax credits, deferred tax assets	303	$ 301
General Business Credits \| Expires from 2036 - 2042
Deferred tax assets and valuation allowances:
Tax credits, unused amount	299
Tax credits, deferred tax assets	299
Tax credits, valuation allowance	0
U.S. Federal \| Indefinite Tax Period
Deferred tax assets and valuation allowances:
Net operating loss, unused amount	5,005
Net operating loss, deferred tax assets	1,051
Net operating loss, valuation allowance	0
U.S. Federal \| Expires from 2029 - 2037
Deferred tax assets and valuation allowances:
Net operating loss, unused amount	3,209
Net operating loss, deferred tax assets	674
Net operating loss, valuation allowance	0
State \| Expires from 2023 - 2042
Deferred tax assets and valuation allowances:
Net operating loss, unused amount	5,034
Net operating loss, deferred tax assets	254
Net operating loss, valuation allowance	(47)
Foreign \| Indefinite Tax Period
Deferred tax assets and valuation allowances:
Net operating loss, unused amount	83
Net operating loss, deferred tax assets	28
Net operating loss, valuation allowance	(28)
Foreign \| Expires from 2023 - 2027
Deferred tax assets and valuation allowances:
Tax credits, unused amount	4
Tax credits, deferred tax assets	4
Tax credits, valuation allowance	$ (4)

Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Unrecognized Tax Benefits
Balance at beginning of period	$ 21	$ 18	$ 16
Reductions based on statute expirations	(5)	0	0
Additions to state reserves for prior years	7	3	2
Balance at end of period	23	$ 21	$ 18
Other Disclosures
Amounts which, if recognized, would affect the effective tax rate	23
Increase in Unrecognized Tax Benefits is Reasonably Possible	$ 4

Property, Plant and Equipment, net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 35,599	$ 35,653
Depreciation Depletion and Amortization Expense for Property, Plant and Equipment	1,905	1,873	$ 1,928
Interstate Natural Gas FERC-Regulated
Property, Plant and Equipment [Line Items]
Accumulated depreciation, depletion and amortization	(9,883)	(9,433)
Depreciable assets	11,582	11,776
Property, plant and equipment, net	12,228	12,277
Interstate Natural Gas FERC-Regulated \| Pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 11,793	11,718
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	$ 8,839	8,722
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	$ 833	769
Interstate Natural Gas FERC-Regulated \| Other \| Minimum
Property, Plant and Equipment [Line Items]
Composite Depreciation Rates	0.00%
Interstate Natural Gas FERC-Regulated \| Other \| Maximum
Property, Plant and Equipment [Line Items]
Composite Depreciation Rates	25.00%
Interstate Natural Gas FERC-Regulated \| Land and land rights-of-way
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 388	387
Interstate Natural Gas FERC-Regulated \| Construction work in process
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	258	114
Other
Property, Plant and Equipment [Line Items]
Accumulated depreciation, depletion and amortization	(10,529)	(9,359)
Depreciable assets	21,236	21,553
Property, plant and equipment, net	23,371	23,376
Other \| Pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 8,329	8,536
Other \| Pipelines \| Minimum
Property, Plant and Equipment [Line Items]
Straight Line Estimated Useful Life	5 years
Composite Depreciation Rates	0.79%
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	$ 18,645	17,789
Other \| Equipment \| Minimum
Property, Plant and Equipment [Line Items]
Straight Line Estimated Useful Life	5 years
Composite Depreciation Rates	0.79%
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	$ 4,791	4,587
Other \| Other \| Minimum
Property, Plant and Equipment [Line Items]
Straight Line Estimated Useful Life	3 years
Composite Depreciation Rates	0.00%
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	$ 1,350	1,331
Other \| Construction work in process
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 785	$ 492

Investments - Equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Mar. 08, 2021
Schedule of Equity Method Investments [Line Items]
Equity Investments	$ 7,653.0	$ 7,578.0
Earnings (Loss) from Equity Investments	803.0	591.0	$ 780.0
Amortization of excess cost of equity investments	(75.0)	(78.0)	(140.0)
Pre-tax gain on sale of interest in equity investment	$ 0.0	206.0	0.0
ArcLight Capital Partners, LLC
Schedule of Equity Method Investments [Line Items]
Notes Receivable, Related Parties, Noncurrent				$ 125.0
Citrus Corporation
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 1,781.0	1,768.0
Earnings (Loss) from Equity Investments	$ 145.0	151.0	165.0
SNG
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 1,669.0	1,514.0
Earnings (Loss) from Equity Investments	$ 145.0	128.0	129.0
Permian Highway Pipeline
Schedule of Equity Method Investments [Line Items]
Ownership Interest	26.67%
Equity Investments	$ 666.0	647.0
Earnings (Loss) from Equity Investments	$ 70.0	63.0	0.0
NGPL Holdings
Schedule of Equity Method Investments [Line Items]
Ownership Interest	37.50%
Equity Investments	$ 610.0	604.0
Earnings (Loss) from Equity Investments	$ 111.0	94.0	116.0
Debt Instrument, Interest Rate, Stated Percentage	6.75%			6.75%
Notes Receivable, Related Parties, Noncurrent	$ 375.0	375.0		$ 500.0
NGPL Holdings \| ArcLight Capital Partners, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest				25.00%
NGPL Holdings \| KMI
Schedule of Equity Method Investments [Line Items]
Ownership Interest	37.50%
NGPL Holdings \| Brookfield
Schedule of Equity Method Investments [Line Items]
Ownership Interest	37.50%
NGPL Holdings \| Earnings from equity investments
Schedule of Equity Method Investments [Line Items]
Interest	$ 25.0	27.0	34.0
Gulf Coast Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	34.00%
Equity Investments	$ 597.0	618.0
Earnings (Loss) from Equity Investments	$ 91.0	86.0	90.0
MEP
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 371.0	388.0
Earnings (Loss) from Equity Investments	$ 10.0	(17.0)	(6.0)
Products (SE) Pipe Line Corporation
Schedule of Equity Method Investments [Line Items]
Ownership Interest	51.17%
Equity Investments	$ 348.0	346.0
Earnings (Loss) from Equity Investments	$ 51.0	48.0	43.0
Utopia Holding L.L.C.
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 325.0	328.0
Earnings (Loss) from Equity Investments	$ 20.0	20.0	20.0
Gulf LNG
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 311.0	347.0
Earnings (Loss) from Equity Investments	$ 24.0	22.0	19.0
EagleHawk
Schedule of Equity Method Investments [Line Items]
Ownership Interest	25.00%
Equity Investments	$ 273.0	266.0
Earnings (Loss) from Equity Investments	$ 13.0	8.0	17.0
Red Cedar Gathering Company
Schedule of Equity Method Investments [Line Items]
Ownership Interest	49.00%
Equity Investments	$ 155.0	168.0
Earnings (Loss) from Equity Investments	$ 17.0	10.0	12.0
Double Eagle Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 90.0	112.0
Earnings (Loss) from Equity Investments	18.0	9.0	12.0
Watco Companies, LLC
Schedule of Equity Method Investments [Line Items]
Equity Investments	79.0	75.0
Earnings (Loss) from Equity Investments	$ 9.0	9.0	16.0
Watco Companies, LLC \| Preferred Class B
Schedule of Equity Method Investments [Line Items]
Common Unit, Issued	50,000
Quarterly preferred distribution rate	3.00%
Watco Companies, LLC \| Other, net
Schedule of Equity Method Investments [Line Items]
Pre-tax gain on sale of interest in equity investment			10.0
Cortez Pipeline Company
Schedule of Equity Method Investments [Line Items]
Ownership Interest	52.98%
Equity Investments	$ 31.0	28.0
Earnings (Loss) from Equity Investments	$ 30.0	29.0	24.0
FEP
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 0.0	0.0
Earnings (Loss) from Equity Investments	2.0	0.0	70.0
Ruby
Schedule of Equity Method Investments [Line Items]
Equity Investments	0.0	0.0
Earnings (Loss) from Equity Investments	0.0	(116.0)	15.0
Ruby \| Notes Receivable
Schedule of Equity Method Investments [Line Items]
Impairments of equity investments		117.0
All others
Schedule of Equity Method Investments [Line Items]
Equity Investments	347.0	369.0
Earnings (Loss) from Equity Investments	$ 47.0	47.0	$ 38.0
Ruby Pipeline Holding Company LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 0.0	$ 0.0

Investments - Summary of Significant Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Schedule of Equity Method Investments [Line Items]
Revenues	$ 19,200	$ 16,610	$ 11,700
Costs and expenses	15,135	13,694	10,140
Net income (loss)	2,625	1,850	180
Current assets	3,803	3,829
Current liabilities	6,930	5,821
Non-current liabilities	31,034	32,674
Partners’/owners’ equity	30,742	30,823
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	5,967	5,537	5,200
Costs and expenses	4,204	6,153	4,325
Net income (loss)	1,763	(616)	$ 875
Current assets	1,470	1,314
Non-current assets	23,361	23,154
Current liabilities	1,622	1,808
Non-current liabilities	10,207	10,001
Partners’/owners’ equity	$ 13,002	$ 12,659

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	May 31, 2022	Aug. 20, 2021	Dec. 31, 2020
Goodwill [Line Items]
Gross goodwill	$ 26,751				$ 26,637
Accumulated impairment losses	(6,786)				(6,786)
Goodwill	19,965	$ 19,914			19,851
Acquisitions	51	63
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 Regulated \| Minimum
Goodwill [Line Items]
Fair value in excess of their respective carrying values (percentage)			10.00%
Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Gross goodwill	4,940				4,940
Accumulated impairment losses	(2,597)				(2,597)
Goodwill	2,343	2,343			2,343
Acquisitions	0	0
Natural Gas Pipelines Non-Regulated \| Minimum
Goodwill [Line Items]
Fair value in excess of their respective carrying values (percentage)			10.00%
CO2
Goodwill [Line Items]
Gross goodwill	1,528				1,528
Accumulated impairment losses	(600)				(600)
Goodwill	928	928			928
Acquisitions	0	0
CO2 \| Minimum
Goodwill [Line Items]
Fair value in excess of their respective carrying values (percentage)			10.00%
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 \| Minimum
Goodwill [Line Items]
Fair value in excess of their respective carrying values (percentage)			10.00%
Products Pipelines Terminals
Goodwill [Line Items]
Gross goodwill	221				221
Accumulated impairment losses	(70)				(70)
Goodwill	151	151			151
Acquisitions	0	0
Products Pipelines Terminals \| Minimum
Goodwill [Line Items]
Fair value in excess of their respective carrying values (percentage)			10.00%
Terminals
Goodwill [Line Items]
Gross goodwill	1,481				1,481
Accumulated impairment losses	(679)				(679)
Goodwill	802	802			802
Acquisitions	0	0
Terminals \| Minimum
Goodwill [Line Items]
Fair value in excess of their respective carrying values (percentage)			10.00%
Energy Transition Ventures
Goodwill [Line Items]
Gross goodwill	114				0
Accumulated impairment losses	0				0
Goodwill	114	63			$ 0
Acquisitions	51	$ 63
Energy Transition Ventures \| Minimum
Goodwill [Line Items]
Fair value in excess of their respective carrying values (percentage)			10.00%
Energy Transition Ventures \| Kinetrex Energy
Goodwill [Line Items]
Goodwill purchase price adjustment	$ (10)

Debt - Schedule of Debt (Details) - USD ($) $ in Millions		12 Months Ended
Debt - Schedule of Debt (Details) - USD ($) $ in Millions	Aug. 03, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries		$ 31,673	$ 32,418
Less: Current portion of debt		3,385	2,646
Total long-term debt – KMI and Subsidiaries(f)		28,288	29,772
Issuances of debt		9,058	5,959	$ 3,888
Credit facility and commercial paper borrowings
Debt Instrument [Line Items]
Less: Current portion of debt		$ 0	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		$ 348	364
Trust I Preferred Securities, 4.75%, due March 2028(d) \| Capital Trust I
Debt Instrument [Line Items]
Interest rate, stated percentage		4.75%
Total debt – KMI and Subsidiaries		$ 220	221
Less: Current portion of debt		111	111
Other miscellaneous debt(e)
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries		242	248
Less: Current portion of debt		49	$ 47
Senior Notes
Debt Instrument [Line Items]
Issuances of debt	$ 1,484
Senior Notes \| 4.15%, due March 2022
Debt Instrument [Line Items]
Interest rate, stated percentage			4.15%
Total debt – KMI and Subsidiaries		0	$ 375
Less: Current portion of debt		0	$ 375
Senior Notes \| 1.50%, due March 2022(b)
Debt Instrument [Line Items]
Interest rate, stated percentage			1.50%
Total debt – KMI and Subsidiaries		0	$ 853
Less: Current portion of debt		0	$ 853
Senior Notes \| 3.95%, due September 2022
Debt Instrument [Line Items]
Interest rate, stated percentage			3.95%
Total debt – KMI and Subsidiaries		0	$ 1,000
Less: Current portion of debt		$ 0	1,000
Senior Notes \| 3.15%, due January 2023
Debt Instrument [Line Items]
Interest rate, stated percentage		3.15%
Total debt – KMI and Subsidiaries		$ 1,000	1,000
Less: Current portion of debt		1,000	0
Senior Notes \| Floating rate, due January 2023(d)(e)
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries		250	250
Less: Current portion of debt		$ 250	0
Senior Notes \| 3.45%, due February 2023
Debt Instrument [Line Items]
Interest rate, stated percentage		3.45%
Total debt – KMI and Subsidiaries		$ 625	625
Less: Current portion of debt		$ 625	0
Senior Notes \| 3.50%, due September 2023
Debt Instrument [Line Items]
Interest rate, stated percentage		3.50%
Total debt – KMI and Subsidiaries		$ 600	600
Less: Current portion of debt		$ 600	0
Senior Notes \| 5.625%, due November 2023
Debt Instrument [Line Items]
Interest rate, stated percentage		5.625%
Total debt – KMI and Subsidiaries		$ 750	750
Less: Current portion of debt		$ 750	0
Senior Notes \| 4.15%, due February 2024
Debt Instrument [Line Items]
Interest rate, stated percentage		4.15%
Total debt – KMI and Subsidiaries		$ 650	650
Senior Notes \| 4.30%, due May 2024
Debt Instrument [Line Items]
Interest rate, stated percentage		4.30%
Total debt – KMI and Subsidiaries		$ 600	600
Senior Notes \| 4.25%, due September 2024
Debt Instrument [Line Items]
Interest rate, stated percentage		4.25%
Total debt – KMI and Subsidiaries		$ 650	650
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(b)
Debt Instrument [Line Items]
Interest rate, stated percentage		2.25%
Total debt – KMI and Subsidiaries		$ 535	569
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		2.00%
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%	4.80%
Total debt – KMI and Subsidiaries	$ 750	$ 750	0
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		5.00%
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		5.00%
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%	5.45%
Total debt – KMI and Subsidiaries	$ 750	$ 750	0
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		7.00%
Total debt – KMI and Subsidiaries		$ 300	300
Senior Notes \| 7.00%, due October 2028 \| TGP
Debt Instrument [Line Items]
Interest rate, stated percentage		7.00%
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 \| 8.625%, due January 2022 \| EPNG
Debt Instrument [Line Items]
Interest rate, stated percentage			8.625%
Total debt – KMI and Subsidiaries		0	$ 260
Less: Current portion of debt		$ 0	260
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	0
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

Debt - Additional Information (Details) $ / shares in Units, shares in Millions, $ in Millions				12 Months Ended
	Jan. 31, 2023 USD ($)	Aug. 03, 2022 USD ($)	Feb. 23, 2022 USD ($)	Dec. 31, 2022 USD ($) $ / shares $ / € shares	Dec. 31, 2021 USD ($) $ / €	Dec. 31, 2020 USD ($)
Debt Instrument [Line Items]
Aggregate principal amount				$ 31,673	$ 32,418
Issuances of debt				$ 9,058	$ 5,959	$ 3,888
Exchange rate \| $ / €				1.0705	1.1370
Debt Fair Value Adjustments				$ 115	$ 902
Capital Trust I
Debt Instrument [Line Items]
Ownership percentage				100.00%
Senior Notes
Debt Instrument [Line Items]
Redemption Price				100.00%
Issuances of debt		$ 1,484
1.50%, due March 2022(a)(b) \| Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage					1.50%
Aggregate principal amount				$ 0	$ 853
Change to debt as a result of changes in exchange rate					38
2.250% Senior Notes due March 2027 \| Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage				2.25%
Aggregate principal amount				$ 535	569
Change to debt as a result of changes in exchange rate				$ (8)	26
KMI EP Capital Trust I 4.75%, due 2028 \| Capital Trust I
Debt Instrument [Line Items]
Interest rate, stated percentage				4.75%
Aggregate principal amount				$ 220	221
Trust Convertible Preferred Securities Outstanding \| shares				4.4
Liquidation preference \| $ / shares				$ 50
Conversion price \| $ / shares				$ 25.18
KMI EP Capital Trust I 4.75%, due 2028 \| Capital Trust I \| Class P
Debt Instrument [Line Items]
Conversion rate				0.7197
3.50% , Due February 15, 2032 \| Senior Notes \| EPNG
Debt Instrument [Line Items]
Interest rate, stated percentage			3.50%
Aggregate principal amount			$ 300
Issuances of debt			$ 298
4.80% due February 2033 \| Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage		4.80%		4.80%
Aggregate principal amount		$ 750		$ 750	0
5.45% due August 2052 \| Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage		5.45%		5.45%
Aggregate principal amount		$ 750		$ 750	$ 0
5.20%, due November 2033 \| Senior Notes \| Subsequent Event
Debt Instrument [Line Items]
Interest rate, stated percentage	5.20%
Aggregate principal amount	$ 1,500
Issuances of debt	$ 1,485

Debt - Schedule of Current Portion of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Current portion of debt	$ 3,385	$ 2,646
$3.5 billion credit facility due August 20, 2027
Debt Instrument [Line Items]
Current portion of debt	0	0
Line of Credit Facility, Current borrowing capacity	3,500
$500 million credit facility due November 16, 2023
Debt Instrument [Line Items]
Current portion of debt	0	0
Line of Credit Facility, Current borrowing capacity	500
Commercial paper notes
Debt Instrument [Line Items]
Current portion of debt	0	0
Maximum borrowing capacity	3,500	4,000
8.625%, due January 2022(a) \| EPNG \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 260
Interest rate, stated percentage		8.625%
4.15%, due March 2022(a) \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 375
Interest rate, stated percentage		4.15%
1.50%, due March 2022(a)(b) \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 853
Interest rate, stated percentage		1.50%
3.95% due September 2022(c) \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 1,000
Interest rate, stated percentage		3.95%
Senior Notes, 3.15%, due January 15, 2023 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 1,000	$ 0
Interest rate, stated percentage	3.15%
Senior Notes, floating rate, due January 15, 2023 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 250	0
3.45% due February 2023 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 625	0
Interest rate, stated percentage	3.45%
3.50% due September 2023 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 600	0
Interest rate, stated percentage	3.50%
5.625%, due November 2023 \| Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 750	0
Interest rate, stated percentage	5.625%
KMI EP Capital Trust I 4.75%, due 2028 \| 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	$ 47

Debt - Credit Facilities and Restrictive Covenants (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Line of Credit Facility [Line Items]
Current portion of debt	$ 3,385	$ 2,646
$3.5 billion credit facility due August 20, 2027
Line of Credit Facility [Line Items]
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
Line of Credit Facility, Current borrowing capacity	$ 3,500
$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	1.00%
$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	1.00%
$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]
Current portion of debt	$ 0	0
Line of Credit Facility, Current borrowing capacity	$ 500
$500 million credit facility due November 16, 2023 \| Minimum
Line of Credit Facility [Line Items]
Standby fee rate	0.10%
$500 million credit facility due November 16, 2023 \| Maximum
Line of Credit Facility [Line Items]
Standby fee rate	0.30%
$500 million credit facility due November 16, 2023 \| Secured Overnight Financing Rate (SOFR) \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
$500 million credit facility due November 16, 2023 \| Secured Overnight Financing Rate (SOFR) \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.00%
$500 million credit facility due November 16, 2023 \| SOFR Alternative Base Rate \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.10%
$500 million credit facility due November 16, 2023 \| SOFR Alternative Base Rate \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Commercial paper notes
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 3,500	4,000
Debt term	270 days
Current portion of debt	$ 0	$ 0
Credit Facilities
Line of Credit Facility [Line Items]
Remaining borrowing capacity	3,900
Current portion of debt	0
Letters of credit outstanding	$ 81

Debt - Schedule of Maturities of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
2023	$ 3,385
2024	1,925
2025	1,566
2026	1,102
2027	890
Thereafter	22,805
Total debt – KMI and Subsidiaries	$ 31,673	$ 32,418

Debt - Schedule of Debt Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Purchase accounting debt fair value adjustments	$ 472	$ 498
Carrying value adjustment to hedged debt	(367)	376
Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a)	204	223
Unamortized debt discounts, net	(68)	(71)
Unamortized debt issuance costs	(126)	(124)
Total debt fair value adjustments	$ 115	$ 902
Weighted-average amortization period of the unamortized premium from the termination of interest rate swaps	12 years

Debt - Schedule of Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	$ 31,788	$ 33,320
Estimated fair value(a)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	30,070	37,775
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	$ 195	$ 218

Debt - Interest Rates, Interest Rate Swaps and Contingent Debt (Details)	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Debt, weighted average interest rate	4.76%	4.67%

Share-based Compensation and Employee Benefits - Summary of Stock Compensation Plans (Details) - Restricted Stock Awards - Class P	12 Months Ended
	Dec. 31, 2022 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)	34,820
LTIP
Share-based Compensation
Total number of shares of Class P common stock authorized	63,000,000
Grants during the period (shares)	4,110,000
LTIP \| Minimum
Share-based Compensation
Vesting period	1 year
LTIP \| Maximum
Share-based Compensation
Vesting period	10 years

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Shares
Outstanding at end of period (shares)	13,000
LTIP
Shares
Outstanding at beginning of period (shares)	12,617
Granted (shares)	4,110
Vested (shares)	(2,744)
Forfeited (shares)	(695)
Outstanding at end of period (shares)	13,288	12,617
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (dollars per share)	$ 17.63
Granted (dollars per share)	17.31	$ 17.44	$ 15.10
Vested (dollars per share)	20.94
Forfeited (dollars per share)	17.17
Outstanding at end of period (dollars per share)	$ 16.87	$ 17.63

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value per share	$ 17.31	$ 17.44	$ 15.10
Intrinsic value of awards vested during the year	$ 47	$ 77	$ 59
Restricted stock awards expense	60	59	73
Restricted stock awards capitalized	9	$ 9	$ 11
Unrecognized restricted stock awards compensation costs, less estimated forfeitures	$ 104
Weighted average remaining amortization period	1 year 11 months 26 days

Share-based Compensation and Employee Benefits - Pensions and Other Postretirement Benefit Plans - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Savings plan - defined contribution plan
Pension and Other Postretirement Benefit Plans
Percentage of eligible compensation contributed	5.00%
Plan vesting period	2 years
Plan cost	$ 51	$ 48	$ 53
Pension Benefits
Pension and Other Postretirement Benefit Plans
Percentage of employees covered	100.00%
Vesting period	3 years
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	5.87%
Ultimate health care cost trend rate	4.00%

Share-based Compensation and Employee Benefits - Benefit Obligation, Plan Assets and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$ 2,658	$ 2,844
Service cost	55	53	$ 59
Interest cost	57	45	71
Actuarial gain	(503)	(80)
Benefits paid	(190)	(204)
Participant contributions	0	0
Other	0	0
Benefit obligation at end of period	2,077	2,658	2,844
Change in plan assets:
Fair value of plan assets at beginning of period	2,231	2,199
Actual return on plan assets	(350)	180
Employer contributions	50	56
Participant contributions	0	0
Other	0	0
Benefits paid	(190)	(204)
Fair value of plan assets at end of period	1,741	2,231	2,199
Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)	0	0
Current benefit liability	0	0
Non-current benefit liability	(336)	(427)
Funded status - net (liability) asset at December 31,	(336)	(427)
Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:
Unrecognized net actuarial (loss) gain	(455)	(495)
Unrecognized prior service (cost) credit	(1)	(2)
Accumulated other comprehensive (loss) income	(456)	(497)
Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:
Accumulated benefit obligation	2,047	2,608
Fair value of plan assets	1,741	2,231
OPEB
Change in benefit obligation:
Benefit obligation at beginning of period	257	299
Service cost	1	1	1
Interest cost	5	4	8
Actuarial gain	(44)	(21)
Benefits paid	(26)	(28)
Participant contributions	1	1
Other	1	1
Benefit obligation at end of period	195	257	299
Change in plan assets:
Fair value of plan assets at beginning of period	382	361
Actual return on plan assets	(63)	40
Employer contributions	7	7
Participant contributions	1	1
Other	1	1
Benefits paid	(26)	(28)
Fair value of plan assets at end of period	302	382	$ 361
Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)	239	302
Current benefit liability	(15)	(18)
Non-current benefit liability	(117)	(159)
Funded status - net (liability) asset at December 31,	107	125
Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:
Unrecognized net actuarial (loss) gain	135	176
Unrecognized prior service (cost) credit	4	6
Accumulated other comprehensive (loss) income	139	182
Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:
Accumulated benefit obligation	167	219
Fair value of plan assets	34	42
OPEB \| Other Affiliates
Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)	$ 45	$ 54

Share-based Compensation and Employee Benefits - Target Asset Allocation (Details)	Dec. 31, 2022
Pension Benefits \| Equities \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	42.00%
Pension Benefits \| Equities \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	52.00%
Pension Benefits \| Fixed Income Securities \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	37.00%
Pension Benefits \| Fixed Income Securities \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	47.00%
Pension Benefits \| Real Estate \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	2.00%
Pension Benefits \| Real Estate \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	12.00%
Pension Benefits \| Company Securities \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	0.00%
Pension Benefits \| Company Securities \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	10.00%
OPEB \| Cash \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	0.00%
OPEB \| Cash \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	23.00%
OPEB \| Equities \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	42.00%
OPEB \| Equities \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	72.00%
OPEB \| Fixed Income Securities \| Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	25.00%
OPEB \| Fixed Income Securities \| Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocation percentage	50.00%

Share-based Compensation and Employee Benefits - Fair Value of Pension and OPEB Assets by Level of Assets (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 1,741	$ 2,231	$ 2,199
Pension Benefits \| Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	600	755
Pension Benefits \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	152	164
Pension Benefits \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	448	591
Pension Benefits \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	1,141	1,476
Pension Benefits \| Cash \| Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	11
Pension Benefits \| Cash \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	11
Pension Benefits \| Cash \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits \| Short-term Investment Funds \| Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	27	25
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	27	25
Pension Benefits \| Equities \| Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	152	153
Pension Benefits \| Equities \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	152	153
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	421	566
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	421	566
Pension Benefits \| Common/Collective Trusts \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 1,138	$ 1,389
Pension Benefits \| Common/Collective Trusts Invested in Equity Securities \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	66.00%	83.00%
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	22.00%	17.00%
Pension Benefits \| Common/Collective Trusts Invested in Real Estate \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	12.00%
Pension Benefits \| Private Investment Funds \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 0	$ 39
Pension Benefits \| Private Investment Funds Invested in Fixed Income Securities \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments		100.00%
Pension Benefits \| Private Limited Partnerships \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	3	$ 48
OPEB
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	302	382	$ 361
OPEB \| Short-term Investment Funds \| Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	3	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	3	3
OPEB \| Common/Collective Trusts \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 299	$ 379
OPEB \| Common/Collective Trusts Invested in Equity Securities \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	61.00%	63.00%
OPEB \| Common/Collective Trusts Invested in Fixed Income Securities \| Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	39.00%	37.00%
Class P \| Pension Benefits \| Equities \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Amount of KMI securities invested in	$ 110	$ 97

Share-based Compensation and Employee Benefits - Schedule of Expected Payment of Future Benefits and Employer Contributions (Details) $ in Millions	Dec. 31, 2022 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Contributions expected in 2023	$ 50
Benefit payments expected in:
2023	210
2024	206
2025	202
2026	199
2027	191
2028 - 2032	861
OPEB
Defined Benefit Plan Disclosure [Line Items]
Contributions expected in 2023	0
Benefit payments expected in:
2023	26
2024	24
2025	23
2026	21
2027	20
2028 - 2032	$ 76

Share-based Compensation and Employee Benefits - Schedule of Weighted-Average Actuarial Assumptions (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Assumptions related to benefit obligations:
Discount rate	5.41%	2.74%
Rate of compensation increase	3.50%	3.50%
Interest crediting rate	3.50%	3.01%
Assumptions related to benefit costs:
Discount rate	2.74%	2.27%	3.17%
Expected return on plan assets	6.50%	6.25%	6.75%
Rate of compensation increase	3.50%	3.50%	3.50%
Interest crediting rate	3.01%	2.57%	3.71%
OPEB
Assumptions related to benefit obligations:
Discount rate	5.38%	2.56%
Assumptions related to benefit costs:
Discount rate	2.56%	2.08%	3.03%
Expected return on plan assets	5.75%	5.75%	6.50%

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Components of net benefit cost (credit):
Service cost	$ 55	$ 53	$ 59
Interest cost	57	45	71
Expected return on assets	(142)	(133)	(137)
Amortization of prior service cost (credit)	1	0	1
Amortization of net actuarial loss (gain)	29	52	40
Net benefit cost (credit)	0	17	34
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net (gain) loss arising during period	(11)	(127)	157
Amortization or settlement recognition of net actuarial (loss) gain	(29)	(52)	(40)
Amortization of prior service (cost) credit	(1)	0	(1)
Total recognized in total other comprehensive (income) loss(a)	(41)	(179)	116
Total recognized in net benefit cost (credit) and other comprehensive (income) loss	(41)	(162)	150
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	2
OPEB
Components of net benefit cost (credit):
Service cost	1	1	1
Interest cost	5	4	8
Expected return on assets	(17)	(16)	(16)
Amortization of prior service cost (credit)	(3)	(5)	(5)
Amortization of net actuarial loss (gain)	(18)	(17)	(13)
Net benefit cost (credit)	(32)	(33)	(25)
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net (gain) loss arising during period	24	(40)	(43)
Amortization or settlement recognition of net actuarial (loss) gain	17	17	13
Amortization of prior service (cost) credit	2	3	3
Total recognized in total other comprehensive (income) loss(a)	43	(20)	(27)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss	$ 11	$ (53)	$ (52)

Stockholders' Equity - Common Equity (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		12 Months Ended			62 Months Ended
	Jan. 18, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Feb. 07, 2023	Jul. 19, 2017	Dec. 19, 2014
Class of Stock [Line Items]
Common share buy-back program, amount						$ 2,000
Total value of shares repurchased		$ 368	$ 0	$ 50
Average repurchase price per share		$ 16.94	$ 0	$ 13.93
Per share cash dividend declared for the period		1.11	1.08	1.05
Per share cash dividend paid in the period		$ 1.1025	$ 1.0725	$ 1.0375
Subsequent Event
Class of Stock [Line Items]
Common share buy-back program, amount	$ 3,000
Total value of shares repurchased					$ 943
Average repurchase price per share					$ 17.40
Remaining repurchase authorization amount					$ 2,100
Per share cash dividend declared for the period	$ 0.2775
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		21	0	4
Common stock \| Subsequent Event
Class of Stock [Line Items]
Total number of shares repurchased					54

Stockholders' Equity - New Accounting Pronouncements (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity	$ 32,114	$ 31,921	$ 31,838	$ 34,086
Additional paid-in capital
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity	$ 41,673	41,806	$ 41,756	$ 41,745
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)

- Definition

Amount of stockholders' equity (deficit), net of receivables from officers, directors, owners, and affiliates of the entity, attributable to both the parent and noncontrolling interests. Amount excludes temporary equity. Alternate caption for the concept is permanent equity.

+ References

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+ Details

Stockholders' Equity - Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	$ 31,921	$ 31,838	$ 34,086
Balance	32,114	31,921	31,838
Net unrealized gains/(losses) on cash flow hedge derivatives
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(172)	(13)	(7)
Other comprehensive (loss) gain before reclassifications	(312)	(432)	249
Losses (gains) reclassified from accumulated other comprehensive loss	320	273	(255)
Net current-period change in accumulated other comprehensive loss	8	(159)	(6)
Balance	(164)	(172)	(13)
Pension and other postretirement liability adjustments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(239)	(394)	(326)
Other comprehensive (loss) gain before reclassifications	1	155	(68)
Losses (gains) reclassified from accumulated other comprehensive loss	0	0	0
Net current-period change in accumulated other comprehensive loss	1	155	(68)
Balance	(238)	(239)	(394)
Total Accumulated other comprehensive loss
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(411)	(407)	(333)
Other comprehensive (loss) gain before reclassifications	(311)	(277)	181
Losses (gains) reclassified from accumulated other comprehensive loss	320	273	(255)
Net current-period change in accumulated other comprehensive loss	9	(4)	(74)
Balance	$ (402)	$ (411)	$ (407)

- Definition

Amount of stockholders' equity (deficit), net of receivables from officers, directors, owners, and affiliates of the entity, attributable to both the parent and noncontrolling interests. Amount excludes temporary equity. Alternate caption for the concept is permanent equity.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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+ Details

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
RELATED PARTY ASSETS
Accounts receivable	$ 39	$ 38
Other current assets	3	4
Total Assets	42	42
RELATED PARTY LIABILITIES
Current portion of debt	6	6
Accounts payable	19	21
Other current liabilities	8	4
Long-term debt	142	148
Other long-term liabilities and deferred credits	47	56
Total Liabilities	222	235
RELATED PARTY REVENUES
Revenues	19,200	16,610	$ 11,700
RELATED PARTY OPERATING COSTS, EXPENSES AND OTHER
Costs of sales	9,255	6,493	2,545
Other operating expenses	(7)	(7)	(2)
Affiliated Entity
RELATED PARTY REVENUES
Revenues	172	164	206
RELATED PARTY OPERATING COSTS, EXPENSES AND OTHER
Costs of sales	134	145	116
Other operating expenses	$ 50	$ 52	$ 119

Commitments and Contingent Liabilities Rights-of-way obligations (Details) $ in Millions	Dec. 31, 2022 USD ($)
ROW
Other Commitments [Line Items]
Contractual Obligation	$ 120

Commitments and Contingent Liabilities Contingent Debt (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) investees	Dec. 31, 2021 USD ($) investees
Indirect Guarantee of Indebtedness
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 163	$ 170
Indirect Guarantee of Indebtedness \| Cortez Pipeline Company
Guarantor Obligations [Line Items]
Number of equity investees subject to contingent obligation \| investees	1	1
Cortez Pipeline Company
Guarantor Obligations [Line Items]
Percentage of Debt Guaranteed	100.00%	100.00%
Long-term Debt \| Indirect Guarantee of Indebtedness \| Cortez Pipeline Company
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 120	$ 120

Risk Management - Energy Commodity Price Risk Management (Details) - Short - Energy commodity derivative contracts	12 Months Ended
	Dec. 31, 2022 MMBbls Bcf
Designated as Hedging Instrument \| Crude Oil Fixed Price
Derivative [Line Items]
Net open position	(18.4)
Designated as Hedging Instrument \| Crude Oil Basis
Derivative [Line Items]
Net open position	(4.2)
Designated as Hedging Instrument \| Natural Gas Fixed Price
Derivative [Line Items]
Net open position \| Bcf	(62.6)
Designated as Hedging Instrument \| Natural Gas Basis
Derivative [Line Items]
Net open position \| Bcf	(40.1)
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	(1.0)
Not Designated as Hedging Instrument \| Crude Oil Basis
Derivative [Line Items]
Net open position	(9.2)
Not Designated as Hedging Instrument \| Natural Gas Fixed Price
Derivative [Line Items]
Net open position \| Bcf	(7.1)
Not Designated as Hedging Instrument \| Natural Gas Basis
Derivative [Line Items]
Net open position \| Bcf	(44.7)
Not Designated as Hedging Instrument \| NGL Fixed Price
Derivative [Line Items]
Net open position	(0.8)

Risk Management - Interest Rate Risk Management (Details) $ in Millions	Dec. 31, 2022 USD ($)
Fair Value Hedging \| Fixed-To-Variable Interest Rate Contracts \| Designated as Hedging Instrument
Derivative [Line Items]
Notional amount	$ 7,500
Fair Value Hedging \| Variable-to-Fixed Interest Rate Contracts \| Not Designated as Hedging Instrument
Derivative [Line Items]
Notional amount	1,250
Cash Flow Hedging \| Variable-to-Fixed Interest Rate Contracts \| Designated as Hedging Instrument
Derivative [Line Items]
Notional amount	250
Current Portion of Debt \| Fixed-To-Variable Interest Rate Contracts
Derivative [Line Items]
Principal amount of hedged senior notes	1,300
Long-term Debt \| Fixed-To-Variable Interest Rate Contracts
Derivative [Line Items]
Principal amount of hedged senior notes	$ 6,200

Risk Management - Foreign Currency Risk Management (Details) $ in Millions	Dec. 31, 2022 USD ($)
Cash Flow Hedging \| Cross Currency Interest Rate Contract
Derivative [Line Items]
Notional amount	$ 543

Risk Management - Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Asset derivatives	$ 299	$ 514
Liability derivatives	(868)	(293)
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	259	76
Liability derivatives	(428)	(272)
Interest rate contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	40	397
Liability derivatives	(405)	(18)
Foreign currency contracts
Derivatives, Fair Value [Line Items]
Asset derivatives		41
Liability derivatives	(35)	(3)
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Asset derivatives	195	490
Liability derivatives	(687)	(256)
Designated as Hedging Instrument \| Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	156	64
Liability derivatives	(247)	(235)
Designated as Hedging Instrument \| Energy commodity derivative contracts \| Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	150	61
Designated as Hedging Instrument \| Energy commodity derivative contracts \| (Fair Value of Derivative Contracts)
Derivatives, Fair Value [Line Items]
Liability derivatives	(156)	(141)
Designated as Hedging Instrument \| Energy commodity derivative contracts \| Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	6	3
Designated as Hedging Instrument \| Energy commodity derivative contracts \| (Other Long-Term Liabilities and Deferred Credits)
Derivatives, Fair Value [Line Items]
Liability derivatives	(91)	(94)
Designated as Hedging Instrument \| Interest rate contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	39	385
Liability derivatives	(405)	(18)
Designated as Hedging Instrument \| Interest rate contracts \| Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	0	101
Designated as Hedging Instrument \| Interest rate contracts \| (Fair Value of Derivative Contracts)
Derivatives, Fair Value [Line Items]
Liability derivatives	(144)	(3)
Designated as Hedging Instrument \| Interest rate contracts \| Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	39	284
Designated as Hedging Instrument \| Interest rate contracts \| (Other Long-Term Liabilities and Deferred Credits)
Derivatives, Fair Value [Line Items]
Liability derivatives	(261)	(15)
Designated as Hedging Instrument \| Foreign currency contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	0	41
Liability derivatives	(35)	(3)
Designated as Hedging Instrument \| Foreign currency contracts \| Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	0	35
Designated as Hedging Instrument \| Foreign currency contracts \| (Fair Value of Derivative Contracts)
Derivatives, Fair Value [Line Items]
Liability derivatives	(3)	(3)
Designated as Hedging Instrument \| Foreign currency contracts \| Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	0	6
Designated as Hedging Instrument \| Foreign currency contracts \| (Other Long-Term Liabilities and Deferred Credits)
Derivatives, Fair Value [Line Items]
Liability derivatives	(32)	0
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Asset derivatives	104	24
Liability derivatives	(181)	(37)
Not Designated as Hedging Instrument \| Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	103	12
Liability derivatives	(181)	(37)
Not Designated as Hedging Instrument \| Energy commodity derivative contracts \| Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	80	11
Not Designated as Hedging Instrument \| Energy commodity derivative contracts \| (Fair Value of Derivative Contracts)
Derivatives, Fair Value [Line Items]
Liability derivatives	(162)	(31)
Not Designated as Hedging Instrument \| Energy commodity derivative contracts \| Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	23	1
Not Designated as Hedging Instrument \| Energy commodity derivative contracts \| (Other Long-Term Liabilities and Deferred Credits)
Derivatives, Fair Value [Line Items]
Liability derivatives	(19)	(6)
Not Designated as Hedging Instrument \| Interest rate contracts \| Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	1	12
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 Level - Assets (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Gross amount	$ 299	$ 514
Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	259	76
Contracts available for netting	(186)	(53)
Cash collateral held(b)	0	(20)
Net amount	73	3
Interest rate contracts
Derivative [Line Items]
Gross amount	40	397
Contracts available for netting	0	(9)
Cash collateral held(b)	0	0
Net amount	40	388
Foreign currency contracts
Derivative [Line Items]
Gross amount		41
Contracts available for netting		(3)
Cash collateral held(b)		0
Net amount		38
Level 1 \| Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	115	56
Level 1 \| Interest rate contracts
Derivative [Line Items]
Gross amount	0	0
Level 1 \| Foreign currency contracts
Derivative [Line Items]
Gross amount		0
Level 2 \| Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	144	20
Level 2 \| Interest rate contracts
Derivative [Line Items]
Gross amount	40	397
Level 2 \| Foreign currency contracts
Derivative [Line Items]
Gross amount		41
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

Risk Management - FV Input Level - Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Gross amount	$ (868)	$ (293)
Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	(428)	(272)
Contracts available for netting	186	53
Collateral posted(b)	(30)	0
Net amount	(272)	(219)
Interest rate contracts
Derivative [Line Items]
Gross amount	(405)	(18)
Contracts available for netting	0	9
Collateral posted(b)	0	0
Net amount	(405)	(9)
Foreign currency contracts
Derivative [Line Items]
Gross amount	(35)	(3)
Contracts available for netting	0	3
Collateral posted(b)	0	0
Net amount	(35)	0
Level 1 \| Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	(23)	(15)
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	(405)	(257)
Level 2 \| Interest rate contracts
Derivative [Line Items]
Gross amount	(405)	(18)
Level 2 \| Foreign currency contracts
Derivative [Line Items]
Gross amount	(35)	(3)
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 Effect on Income Statements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Cumulative amount of fair value hedging adjustments included in "Debt fair value adjustments"	$ (367)	$ 376
Designated as Hedging Instrument \| Fair Value Hedging \| Interest Rate Contract
Derivative [Line Items]
Location	Interest, net	Interest, net	Interest, net
Gain/(loss) recognized in income on derivatives and related hedged item	$ (738)	$ (322)	$ 335
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	$ 743	$ 326	$ (343)
Cumulative amount of fair value hedging adjustments included in "Debt fair value adjustments"	$ (367)

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	$ (404)	$ (563)	$ 324
Gain/(loss) reclassified from Accumulated OCI into income	(415)	(356)	333
Loss to be reclassified within twelve months	92
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	(338)	(475)	240
Energy commodity derivative contracts \| Revenues—Commodity sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	(491)	(271)	222
Energy commodity derivative contracts \| Costs of sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	144	20	(14)
Energy commodity derivative contracts \| Write-down of hedged inventory
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	121	41	0
Interest rate contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	7	5	(8)
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	(73)	(93)	92
Foreign currency contracts \| Other, net
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	$ (68)	$ (105)	$ 125

Risk Management - Not Designated as Hedges Effect on Income Statements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ (74)	$ (493)	$ 24
Energy commodity derivative contracts
Derivative [Line Items]
Loss on Derivative Instruments	11	479	11
Revenues—Commodity sales \| Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	137	(652)	(1)
Costs of sales \| Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	(190)	152	25
Earnings from equity investments \| Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	(11)	(5)	0
Interest, net \| Interest rate contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ (10)	$ 12	$ 0

Risk Management - Credit Risks (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	$ 144
Energy commodity derivative contracts
Credit Derivatives [Line Items]
Letters of credit outstanding	0	$ 0
Initial Margin Requirements	29
Variation Margin Requirements	30
Derivative, Collateral, Obligation to Return Cash, Variation Margin	0	20
Other Current Liabilities \| Contract and Over the Counter \| Energy commodity derivative contracts
Credit Derivatives [Line Items]
Derivative, Collateral, Obligation to Return Cash, Variation Margin	$ 1	$ 14

Revenue Recognition - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 18,128	$ 16,154	$ 10,097
Leasing services(d)	1,302	1,266	1,236
Derivatives adjustments on commodity sales	(354)	(923)	221
Other	124	113	146
Total other revenues	1,072	456	1,603
Total revenues	19,200	16,610	11,700
Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,515	4,411	4,370
Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,360	2,114	2,056
Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,875	6,525	6,426
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,340	6,480	2,032
Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,913	3,149	1,639
Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	11,253	9,629	3,671
Total revenues	10,897	8,714	3,891
Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	12,659	11,644	7,222
Products Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	3,418	2,245	1,721
Terminals
Disaggregation of Revenue [Line Items]
Total revenues	1,789	1,712	1,719
CO2
Disaggregation of Revenue [Line Items]
Total revenues	1,334	1,009	1,038
Operating Segments \| Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	12,172	11,871	6,659
Leasing services(d)	474	473	466
Derivatives adjustments on commodity sales	(26)	(700)	18
Other	66	65	116
Total other revenues	514	(162)	600
Total revenues	12,686	11,709	7,259
Operating Segments \| Natural Gas Pipelines \| Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,547	3,402	3,345
Operating Segments \| Natural Gas Pipelines \| Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	926	746	714
Operating Segments \| Natural Gas Pipelines \| Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,473	4,148	4,059
Operating Segments \| Natural Gas Pipelines \| Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,266	6,463	2,038
Operating Segments \| Natural Gas Pipelines \| Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,433	1,260	562
Operating Segments \| Natural Gas Pipelines \| Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	7,699	7,723	2,600
Operating Segments \| Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,201	2,053	1,534
Leasing services(d)	194	172	166
Derivatives adjustments on commodity sales	(3)	(1)	0
Other	26	21	21
Total other revenues	217	192	187
Total revenues	3,418	2,245	1,721
Operating Segments \| Products Pipelines \| Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	207	259	271
Operating Segments \| Products Pipelines \| Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	962	949	905
Operating Segments \| Products Pipelines \| Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,169	1,208	1,176
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	2,032	845	358
Operating Segments \| Products Pipelines \| Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,032	845	358
Operating Segments \| Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,218	1,150	1,165
Leasing services(d)	574	565	557
Derivatives adjustments on commodity sales	0	0	0
Other	0	0	0
Total other revenues	574	565	557
Total revenues	1,792	1,715	1,722
Operating Segments \| Terminals \| Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	763	751	756
Operating Segments \| Terminals \| Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	426	375	395
Operating Segments \| Terminals \| Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,189	1,126	1,151
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	29	24	14
Operating Segments \| Terminals \| Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	29	24	14
Operating Segments \| CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,567	1,148	779
Leasing services(d)	60	56	47
Derivatives adjustments on commodity sales	(325)	(222)	203
Other	32	27	9
Total other revenues	(233)	(139)	259
Total revenues	1,334	1,009	1,038
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	46	45	42
Operating Segments \| CO2 \| Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	47	46	43
Operating Segments \| CO2 \| Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	94	32	1
Operating Segments \| CO2 \| Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,426	1,070	735
Operating Segments \| CO2 \| Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,520	1,102	736
Corporate and Eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(30)	(68)	(40)
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	(30)	(68)	(40)
Corporate and Eliminations \| Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(3)	(2)	(3)
Corporate and Eliminations \| Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	(1)	0
Corporate and Eliminations \| Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(3)	(3)	(3)
Corporate and Eliminations \| Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(20)	(15)	(7)
Corporate and Eliminations \| Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(7)	(50)	(30)
Corporate and Eliminations \| Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ (27)	$ (65)	$ (37)

Revenue Recognition - Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Contract Assets
Contract assets balances	$ 33	$ 39
Transfer to accounts receivable	14
Contract Liabilities
Contract liability balances	204	$ 212
Transfer to revenues	$ 90

Revenue Recognition - Revenue Allocated to Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2022 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated Revenue	$ 27,451
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Estimated Revenue	$ 4,312
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	$ 3,401
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	$ 2,800
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	$ 2,466
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	$ 2,132
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
Estimated Revenue	$ 12,340

Reportable Segments Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Revenues	$ 19,200	$ 16,610	$ 11,700
Other
Segment Reporting Information [Line Items]
Revenues	(30)	(68)	(40)
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(30)	(68)	(40)
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Revenues	12,659	11,644	7,222
Natural Gas Pipelines \| Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(27)	(65)	(37)
Products Pipelines
Segment Reporting Information [Line Items]
Revenues	3,418	2,245	1,721
Terminals
Segment Reporting Information [Line Items]
Revenues	1,789	1,712	1,719
Terminals \| Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(3)	(3)	(3)
CO2
Segment Reporting Information [Line Items]
Revenues	$ 1,334	$ 1,009	$ 1,038
Revenue Benchmark \| Customer Concentration Risk
Segment Reporting Information [Line Items]
Concentration Risk, Percentage Meet Certain Threshold	10.00%	10.00%	10.00%

Reportable Segments Operating expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Operating expenses	$ 12,351	$ 9,287	$ 5,398
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Operating expenses	8,562	7,000	3,457
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Operating expenses	2,391	1,239	779
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Operating expenses	853	793	762
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Operating expenses	554	289	404
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating expenses	$ (9)	$ (34)	$ (4)

Reportable Segments Other expense (income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Other expense (income)	$ (39)	$ 1,617	$ 1,930
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other expense (income)	(13)	1,597	1,009
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Other expense (income)	(12)	0	21
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Other expense (income)	(14)	32	(50)
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Other expense (income)	(1)	(8)	950
Other
Segment Reporting Information [Line Items]
Other expense (income)	$ 1	$ (4)	$ 0

Reportable Segments Depreciation, depletion and amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
DD&A	$ 2,186	$ 2,135	$ 2,164
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
DD&A	1,096	1,099	1,062
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
DD&A	336	335	347
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
DD&A	458	440	438
Operating Segments \| CO2
Segment Reporting Information [Line Items]
DD&A	272	236	291
Other
Segment Reporting Information [Line Items]
DD&A	$ 24	$ 25	$ 26

Reportable Segments Earnings (loss) from equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments	$ 728	$ 513	$ 640
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments	650	435	551
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments	33	34	45
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments	14	15	22
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments	$ 31	$ 29	$ 22

Reportable Segments Other, net-income(expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Other, net-income (expense)	$ 55	$ 282	$ 56
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other, net-income (expense)	(19)	216	11
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Other, net-income (expense)	0	1	1
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Other, net-income (expense)	8	3	13
Other
Segment Reporting Information [Line Items]
Other, net-income (expense)	$ 66	$ 62	$ 31

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
DD&A	$ (2,186)	$ (2,135)	$ (2,164)
Amortization of excess cost of equity investments	(75)	(78)	(140)
General and administrative and corporate charges	(637)	(655)	(648)
Interest, net	(1,513)	(1,492)	(1,595)
Income tax expense	(710)	(369)	(481)
Net Income	2,625	1,850	180
Total Segments EBDA(e)
Segment Reporting Information [Line Items]
Segment EBDA(c)	7,702	6,547	5,213
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(c)	4,801	3,815	3,483
DD&A	(1,096)	(1,099)	(1,062)
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(c)	1,107	1,064	977
DD&A	(336)	(335)	(347)
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Segment EBDA(c)	975	908	1,045
DD&A	(458)	(440)	(438)
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Segment EBDA(c)	819	760	(292)
DD&A	(272)	(236)	(291)
Other
Segment Reporting Information [Line Items]
DD&A	(24)	(25)	(26)
General and administrative and corporate charges	$ (593)	$ (623)	$ (653)

Reportable Segments Capital expenditures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Capital expenditures	$ 1,621	$ 1,281	$ 1,707
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	666	570	945
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	0	122	122
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Capital expenditures	552	332	433
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Capital expenditures	371	230	186
Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 32	$ 27	$ 21

Reportable Segments Investments (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Investments	$ 7,653	$ 7,578
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments	6,993	6,887
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Investments	445	465
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Investments	128	137
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Investments	$ 87	$ 89

Reportable Segments Other Intangibles, Net (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Other intangible, net	$ 1,809	$ 1,678
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other intangible, net	439	557
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Other intangible, net	777	868
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Other intangible, net	38	51
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Other intangible, net	$ 555	$ 202

Reportable Segments Assets (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Assets	$ 70,078	$ 70,416
Operating Segments \| Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets	47,978	47,746
Operating Segments \| Products Pipelines
Segment Reporting Information [Line Items]
Assets	8,985	9,088
Operating Segments \| Terminals
Segment Reporting Information [Line Items]
Assets	8,357	8,513
Operating Segments \| CO2
Segment Reporting Information [Line Items]
Assets	3,449	2,843
Other
Segment Reporting Information [Line Items]
Assets	$ 1,309	$ 2,226

- Definition

Sum of the carrying amounts as of the balance sheet date of all assets that are recognized. Assets are probable future economic benefits obtained or controlled by an entity as a result of past transactions or events.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
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+ Details

Reportable Segments Geographical information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Revenues	$ 19,200	$ 16,610	$ 11,700
Long-term assets, excluding goodwill and other intangibles	44,501	44,995	46,466
U.S.
Segment Reporting Information [Line Items]
Revenues	19,036	16,479	11,625
Long-term assets, excluding goodwill and other intangibles	44,425	44,916	46,384
Canada
Segment Reporting Information [Line Items]
Long-term assets, excluding goodwill and other intangibles	1	1	1
Mexico and other foreign
Segment Reporting Information [Line Items]
Revenues	164	131	75
Long-term assets, excluding goodwill and other intangibles	$ 75	$ 78	$ 81

- Definition

Amount of revenue recognized from goods sold, services rendered, insurance premiums, or other activities that constitute an earning process. Includes, but is not limited to, investment and interest income before deduction of interest expense when recognized as a component of revenue, and sales and trading gain (loss).

+ References

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+ Details

Leases - Lessee (Details) - USD ($) $ in Millions	12 Months Ended
Leases - Lessee (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lease, Cost [Abstract]
Operating leases	$ 62	$ 60	$ 55
Short-term and variable leases	101	109	101
Total lease cost	163	169	156
Lessee, Operating Lease, Description [Abstract]
Operating cash flows from operating leases	(132)	(137)	(131)
Investing cash flows from operating leases	(31)	(32)	(25)
ROU assets obtained in exchange for operating lease obligations, net of retirements	22	59	20
Amortization of ROU assets	$ 50	$ 47	$ 46
Weighted average remaining lease term	9 years 9 months 18 days	10 years 4 months 20 days	11 years 6 months 21 days
Weighted average discount rate	4.26%	3.95%	4.27%
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	$ 287	$ 315
Short-term lease liability	47	45
Long-term lease liability	240	$ 270
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2023	58
2024	50
2025	40
2026	32
2027	29
Thereafter	166
Total lease payments	375
Less: Interest	(88)
Present value of lease liabilities	$ 287

Litigation and Environmental - Other Commercial Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) individual claims	Dec. 31, 2021 USD ($)
FERC \| EPNG FERC Proceeding
Loss Contingencies [Line Items]
Proposed Base Rate Reduction	16.00%
Proposed Phase in Rate Reduction Period	3 years
Freeport LNG Marketing, LLC Case \| Pending Litigation
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 104
Pension Plan Litigation \| Pending Litigation
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number \| claims	6
Purported Class \| individual	10,000
Hiland Partners Holdings, LLC \| Settled Litigation
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value		$ 276

Litigation and Environmental - General (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Loss Contingency, Information about Litigation Matters [Abstract]
Estimated Litigation Liability	$ 70	$ 231

Litigation and Environmental - PHMSA Enforcement Matter (Details)	Dec. 31, 2022 USD ($)
Pipeline and Hazardous Materials Safety Administration \| KMLT
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 455,000

Litigation and Environmental - Portland (Details) - Portland Harbor Superfund Site, Willamette River, Portland, Oregon $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) Terminals Parties
Environmental Protection Agency \| KMLT
Site Contingency [Line Items]
Number of Parties Involved In Site Cleanup Allocation Negotiations \| Parties	90
Number of Liquid Terminals \| Terminals	2
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
Pro Forma \| Environmental Protection Agency \| KMLT
Site Contingency [Line Items]
Environmental Remediation Expense \| $	$ 2,800
Estimated Remedy Implementation Period	10 years

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, 2022	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
Site Contingency [Line Items]
Number of Parties Included in Complaint \| Parties				85
Lower Passaic River Study Area \| Pending Litigation \| EPA preferred alternative estimate \| Pro Forma
Site Contingency [Line Items]
Environmental Remediation Expense		$ 1,700
Lower Passaic River Study Area \| Pending Litigation \| Clean Up Implementation
Site Contingency [Line Items]
Estimated Remedy Implementation Period			6 years
Upper Passaic River Study Area, Upper Portion \| Pending Litigation \| Pro Forma
Site Contingency [Line Items]
Environmental Remediation Expense	$ 440

Litigation and Environmental - Louisiana Governmental (Details) - Coastal Zone	Mar. 29, 2019 Parties	Nov. 08, 2013 Parties	Dec. 31, 2022 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 - Walnut Creek (Details) $ in Millions		12 Months Ended
	Dec. 16, 2021 USD ($)	Dec. 31, 2022	Dec. 08, 2020 bbl	Nov. 24, 2020 bbl
Environmental Remediation Expense, Statement of Income or Comprehensive Income [Extensible Enumeration]	Operations and maintenance
State of California \| SFPP
Environmental Remediation Estimated Spill Volume \| bbl			1,000	8.1
Environmental Remediation Expense \| $	$ 2.5
Unsupervised Probation Period		18 months

Litigation and Environmental - Environmental Matters - General (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Loss Contingency, Information about Litigation Matters [Abstract]
Accrual for Environmental Loss Contingencies	$ 221	$ 243
Recorded Third-Party Environmental Recoveries Receivable	$ 12	$ 12
Environmental Loss Contingency, Statement Of Financial Position [Extensible Enumeration], Not Disclosed Flag	true	true

Recent Accounting Pronoucements (Details) - Fixed-To-Variable Interest Rate Contracts - Fair Value Hedging - Designated as Hedging Instrument $ in Millions	Dec. 31, 2022 USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Notional amount	$ 7,500
Secured Overnight Financing Rate (SOFR)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Notional amount	$ 4,425