Kinder Morgan (KMI) 10-K 7 Feb 22 2021 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2021	Feb. 04, 2022	Jun. 30, 2021
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
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			$ 36,152,128,132
Entity Common Stock, Shares Outstanding		2,267,484,557
Entity Central Index Key	0001506307
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
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
1.50%, due March 2022(d)
Entity Information [Line Items]
Title of 12(b) Security	1.500% Senior Notes due 2022
Trading Symbol	KMI 22
Security Exchange Name	NYSE
2.25%, due March 2027(d)
Entity Information [Line Items]
Title of 12(b) Security	2.250% Senior Notes due 2027
Trading Symbol	KMI 27 A
Security Exchange Name	NYSE

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Auditor [Abstract]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Houston, Texas
Auditor Firm ID	238

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues
Total Revenues	$ 16,610	$ 11,700	$ 13,209
Operating Costs, Expenses and Other
Costs of sales	6,493	2,545	3,263
Operations and maintenance	2,368	2,475	2,591
Depreciation, depletion and amortization	2,135	2,164	2,411
General and administrative	655	648	590
Taxes, other than income taxes	426	378	426
Loss (gain) on impairments and divestitures, net (Note 4)	1,624	1,932	(942)
Other income, net	(7)	(2)	(3)
Total Operating Costs, Expenses and Other	13,694	10,140	8,336
Operating Income	2,916	1,560	4,873
Other Income (Expense)
Earnings from equity investments	591	780	101
Amortization of excess cost of equity investments	(78)	(140)	(83)
Interest, net	(1,492)	(1,595)	(1,801)
Other, net (Note 3)	282	56	75
Total Other Expense	(697)	(899)	(1,708)
Income Before Income Taxes	2,219	661	3,165
Income Tax Expense	(369)	(481)	(926)
Net Income	1,850	180	2,239
Net Income Attributable to Noncontrolling Interests	(66)	(61)	(49)
Net Income Attributable to Kinder Morgan, Inc.	$ 1,784	$ 119	$ 2,190
Class P Common Stock
Basic Earnings Per Share	$ 0.78	$ 0.05	$ 0.96
Diluted Earnings Per Share	$ 0.78	$ 0.05	$ 0.96
Basic Weighted Average Shares Outstanding	2,266	2,263	2,264
Diluted Weighted Average Shares Outstanding	2,266	2,263	2,264
Services
Revenues
Total Revenues	$ 7,757	$ 7,618	$ 8,198
Commodity sales
Revenues
Total Revenues	8,714	3,891	4,811
Other
Revenues
Total Revenues	$ 139	$ 191	$ 200

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net income	$ 1,850	$ 180	$ 2,239
Other comprehensive (loss) income, net of tax
Net unrealized (loss) gain from derivative instruments (net of taxes of $131, $(75), and $52, respectively)	(432)	249	(177)
Reclassification into earnings of net derivative instruments loss (gain) to net income (net of taxes of $(83), $78, and $(2), respectively)	273	(255)	6
Foreign currency translation adjustments (net of taxes of $—, $—, and $(27), respectively)	0	0	108
Benefit plan adjustments (net of taxes of $(47), $19, and $(23), respectively)	155	(68)	77
Total other comprehensive (loss) income	(4)	(74)	14
Comprehensive income	1,846	106	2,253
Comprehensive income attributable to noncontrolling interests	(66)	(61)	(66)
Comprehensive income attributable to KMI	$ 1,780	$ 45	$ 2,187

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Change in fair value of hedge derivatives, tax	$ 131	$ (75)	$ 52
Reclassification of change in fair value of derivatives to net income, tax	(83)	78	(2)
Foreign currency translation adjustments, tax	0	0	(27)
Benefit plan adjustments, tax	$ (47)	$ 19	$ (23)

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current assets
Cash and cash equivalents	$ 1,140	$ 1,184
Restricted deposits	7	25
Accounts receivable	1,611	1,293
Fair value of derivative contracts	220	185
Inventories	562	348
Other current assets	289	168
Total current assets	3,829	3,203
Property, plant and equipment, net	35,653	35,836
Investments	7,578	7,917
Goodwill	19,914	19,851
Other intangibles, net	1,678	2,453
Deferred income taxes	115	536
Deferred charges and other assets	1,649	2,177
Total Assets	70,416	71,973
Current liabilities
Current portion of debt	2,646	2,558
Accounts payable	1,259	837
Accrued interest	504	525
Accrued taxes	270	267
Accrued contingencies	284	307
Other current liabilities	858	580
Total current liabilities	5,821	5,074
Long-term debt
Outstanding	29,772	30,838
Debt fair value adjustments	902	1,293
Total long-term debt	30,674	32,131
Other long-term liabilities and deferred credits	2,000	2,202
Total long-term liabilities and deferred credits	32,674	34,333
Total Liabilities	38,495	39,407
Commitments and contingencies (Notes 9, 13, 17 and 18)
Redeemable Noncontrolling Interest (Note 2)	0	728
Stockholders’ Equity
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,267,391,527 and 2,264,257,336 shares, respectively, issued and outstanding	23	23
Additional paid-in capital	41,806	41,756
Accumulated deficit	(10,595)	(9,936)
Accumulated other comprehensive loss	(411)	(407)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,823	31,436
Noncontrolling interests	1,098	402
Total Stockholders’ Equity	31,921	31,838
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$ 70,416	$ 71,973

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2021	Dec. 31, 2020
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)	2,267,391,527	2,264,257,336
Common stock, shares outstanding (in shares)	2,267,391,527	2,264,257,336

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Cash Flows From Operating Activities
Net income	$ 1,850	$ 180	$ 2,239
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	2,135	2,164	2,411
Deferred income taxes	355	345	717
Amortization of excess cost of equity investments	78	140	83
Loss (gain) on impairments and divestitures, net (Note 4)	1,624	1,932	(942)
Gain on sale of interest in equity investment (Note 3)	(206)	0	0
Earnings from equity investments	(591)	(780)	(101)
Distributions of equity investment earnings	720	633	590
Pension (contributions) net of noncash pension benefit expenses	(39)	(90)	14
Changes in components of working capital, net of the effects of acquisitions and dispositions
Accounts receivable	(265)	88	98
Inventories	(202)	16	4
Other current assets	(109)	49	100
Accounts payable	387	(19)	(198)
Accrued interest, net of interest rate swaps	(17)	(51)	(43)
Accrued taxes	2	(93)	(142)
Other current liabilities	146	(81)	(46)
Rate reparations, refunds and other litigation reserve adjustments	(57)	40	(4)
Other, net	(103)	77	(32)
Net Cash Provided by Operating Activities	5,708	4,550	4,748
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired	(1,547)	(16)	(79)
Capital expenditures	(1,281)	(1,707)	(2,270)
Sales of property, plant and equipment, investments, and other net assets, net of removal costs	406	1,069	82
Proceeds from the KML and U.S. Cochin Sale, net of cash disposed (Note 3)	0	0	1,527
Contributions to investments	(38)	(386)	(1,299)
Distributions from equity investments in excess of cumulative earnings	163	154	333
Other, net	(8)	(25)	(8)
Net Cash Used in Investing Activities	(2,305)	(911)	(1,714)
Cash Flows From Financing Activities
Issuances of debt	5,959	3,888	8,036
Payments of debt	(6,831)	(3,996)	(11,224)
Debt issue costs	(27)	(25)	(10)
Cash dividends - common shares (Note 11)	(2,443)	(2,362)	(2,163)
Repurchases of common shares	0	(50)	(2)
Contributions from investment partner and noncontrolling interests	4	14	151
Distributions to investment partner	(82)	(79)	(11)
Distribution to noncontrolling interests - KML distribution of the TMPL Sale proceeds	0	0	(879)
Distributions to noncontrolling interests - other	(20)	(15)	(55)
Other, net	(25)	(13)	(28)
Net Cash Used in Financing Activities	(3,465)	(2,638)	(6,185)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	0	(1)	29
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Deposits	(62)	1,000	(3,122)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,209	209	3,331
Cash, Cash Equivalents, and Restricted Deposits, end of period	1,147	1,209	209
Cash and Cash Equivalents, beginning of period	1,184	185	3,280
Restricted Deposits, beginning of period	25	24	51
Cash and Cash Equivalents, end of period	1,140	1,184	185
Restricted Deposits, end of period	7	25	24
Noncash Investing and Financing Activities
Increase in property, plant and equipment from both accruals and contractor retainage	74
ROU assets and operating lease obligations recognized (Note 17)	59	20	399
Marketable securities obtained as consideration for divestiture (Note 3)	0	0	892
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,529	1,661	1,860
Cash paid during the period for income taxes, net	$ 10	$ 227	$ 372

CONSOLIDATED STATEMENTS OF STOC

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 ASUAccumulated deficit	Impact of Adoption of ASUStockholders’ equity attributable to KMI	Adjusted Balance	Adjusted BalanceCommon stock	Adjusted BalanceAdditional paid-in capital	Adjusted BalanceAccumulated deficit	Adjusted BalanceAccumulated other comprehensive loss	Adjusted BalanceStockholders’ equity attributable to KMI	Adjusted BalanceNon-controlling interests
Balance at Dec. 31, 2018	$ 34,531	$ 23	$ 41,701	$ (7,716)	$ (330)	$ 33,678	$ 853	$ (4)	$ (4)	$ (4)	$ 34,527	$ 23	$ 41,701	$ (7,720)	$ (330)	$ 33,674	$ 853
Balance (shares) at Dec. 31, 2018		2,262										2,262
Repurchases of shares	(2)		(2)			(2)
Repurchases of shares (shares)		(0.1)
Restricted shares	46		46			46
Restricted shares (shares)		3
Net income	2,239			2,190		2,190	49
Distributions	(55)					0	(55)
Contributions	3					0	3
Dividends	(2,163)			(2,163)		(2,163)
Sale of interest in KML	(435)				68	68	(503)
Other	1					0	1
Other comprehensive (loss) income	14
Other comprehensive loss	(75)				(71)	(71)	(4)
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
Distributions	(15)					0	(15)
Contributions	11					0	11
Dividends	(2,362)			(2,362)		(2,362)
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
Distributions	(20)					0	(20)
Contributions	4					0	4
Dividends	(2,443)			(2,443)		(2,443)
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
Balance (shares) at Dec. 31, 2021		2,267

General (Notes)

General (Notes)	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	1. General We are one of the largest energy infrastructure companies in North America and unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO 2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, metals and petroleum coke.

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2021
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 and cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions. 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 certain equity investees. 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 includes an evaluation of estimated impacts resulting from the economic effects of COVID-19, which we estimate could have a more significant impact to certain subset or pools of customers. Our allowance for credit losses as of December 31, 2021 and 2020 was $1 million and $26 million, respectively, 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 NGL, crude oil, condensate, refined petroleum products, transmix and natural gas. 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. For the majority of our assets, we compute depreciation using either the straight-line method based on estimated economic lives or the composite depreciation method, which applies a single depreciation rate for a group of assets. We apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 0.092% to 33.3% excluding certain short-lived assets such as vehicles. For FERC-regulated entities, the FERC-accepted composite depreciation rate is applied to the total cost of the composite group until the net book value equals the salvage value. For other entities, depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract term for assets on leased or customer property and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When these assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. Subsequent events could 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. Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method, 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. We engage in enhanced recovery techniques in which CO 2 is injected into certain producing oil reservoirs. In some cases, the cost of the CO 2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. The cost of CO 2 associated with pressure maintenance operations for reservoir management is expensed when it is injected. When CO 2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our liquids and bulk terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A 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 sales proceeds received or the market value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset. For our pipeline system assets under the composite method of depreciation, we charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. Gains and losses are booked for FERC-approved operating unit sales and land sales and are recorded to income or expense accounts in accordance with regulatory accounting guidelines. Asset Retirement Obligations We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. 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. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to 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. We have various other obligations throughout our businesses to remove facilities and equipment on rights-of-way and other leased facilities. We currently cannot reasonably estimate the fair value of these obligations because the associated assets have indeterminate lives. These assets include pipelines, certain processing plants and distribution facilities, and certain liquids and bulk terminal facilities. 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. We recognize impairment losses when the estimated fair value is less than its carrying amount. In addition to our annual goodwill impairment test, 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 (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 an impairment exists and is recorded for the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. We evaluate goodwill for impairment on May 31 of each year. For purposes of our May 31, 2021 evaluation, we grouped our businesses into six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO 2 ; and (vi) Terminals. With our August 20, 2021 acquisition of Kinetrex Energy, we expanded our reporting units to include the Energy Transition Ventures reporting unit (see Note 3). We also evaluate goodwill for impairment to the extent events or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. 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, relationships and agreements, and technology-based assets. As of December 31, 2021 and 2020, the gross carrying amounts of these intangible assets was $3,036 million and $4,074 million, respectively, and the accumulated amortization was $1,358 million and $1,621 million, respectively, resulting in net carrying amounts of $1,678 million and $2,453 million, respectively. 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 effect of obsolescence, new technology, and competition. For the years ended December 31, 2021, 2020 and 2019, the amortization expense on our intangibles totaled $237 million, $212 million and $214 million, respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2022 – 2026) is approximately $242 million, $177 million, $153 million, $147 million, and $144 million, respectively. As of December 31, 2021, the weighted average amortization period for our intangible assets was approximately ten years. Revenue Recognition The majority of our revenues are accounted for under ASC 606, Revenue from Contracts with Customers ; however, to a limited extent, some revenues are accounted for under other guidance such as ASC 842, Leases or ASC 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 natural gas sales, NGL sales, crude oil sales, CO 2 sales, and transmix sales contracts, as described below. Generally, for the majority of these contracts: (i) each unit (Mcf, 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 primarily include transportation service, storage service, gathering and processing service, and terminaling service contracts, 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 CO 2 producing activities, such as those in our CO 2 business segment, are not accounted for as costs of sales. Operations and Maintenance Operations and maintenance include costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our crude oil, gas and CO 2 producing activities included within operations and maintenance totaled $180 million, $319 million and $382 million for the years ended December 31, 2021, 2020 and 2019, 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 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, were reflected based on contractual lease payments as outlined within the lease agreement and exclude CPI adjustments. 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, while for the remainder of our agreements we have elected the practical expedient to account for lease and non-lease components as a single lease component. 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 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 t

Acquisitions and Divestitures (

Acquisitions and Divestitures (Notes)	12 Months Ended
	Dec. 31, 2021
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, 2021, our allocation of the purchase price for significant acquisitions completed during the year ended December 31, 2021 are detailed below: Assignment of Purchase Price Ref Date Acquisition Purchase price Current assets Property, plant & equipment Deferred charges & other Goodwill Current liabilities Long-term liabilities (In millions) (1) 8/21 Kinetrex $ 318 $ 18 $ 49 $ 262 $ 63 $ (6) $ (68) (2) 7/21 Stagecoach Gas Services LLC 1,258 53 1,187 24 — (6) — (1) Kinetrex 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 preliminary 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 CO 2 business segment. (2) Stagecoach Gas Services LLC On July 9, 2021 and November 24, 2021, we completed the acquisitions of Stagecoach Gas Services LLC and its subsidiaries (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,258 million, including a preliminary purchase price adjustment for working capital. Deferred charges and other within the preliminary 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 operations. 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 operations for the year ended December 31, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings. Sale of U.S. Portion of Cochin Pipeline System and KML On December 16, 2019, we closed on two cross-conditional transactions resulting in the sale of the U.S. portion of the Cochin Pipeline system and all the outstanding equity of KML, including our 70% interest, to Pembina Pipeline Corporation (Pembina) (together, the “KML and U.S. Cochin Sale”). We recognized a pre-tax net gain of $1,296 million from these transactions within “Loss (gain) on impairments and divestitures, net” on our accompanying consolidated statement of income during the year ended December 31, 2019. We received cash proceeds of $1,553 million net of a working capital adjustment, for the U.S. portion of the Cochin Pipeline system which was used to pay down debt. KML common shareholders received 0.3068 shares of Pembina common equity for each share of KML common equity. For our 70% interest in KML, we received approximately 25 million shares of Pembina common equity, with a pre-tax fair value on the transaction date of approximately $892 million. The Pembina common shares were sold on January 9, 2020, and we received proceeds of approximately $907 million ($764 million after tax). Sale of Trans Mountain Pipeline System and Its Expansion Project On January 3, 2019, KML distributed the net proceeds from the sale of TMPL, the TMEP, and the Puget Sound pipeline system in 2018 to its shareholders as a return of capital. Public owners of KML’s restricted voting shares, reflected as noncontrolling interests by us, received approximately $0.9 billion (C$1.2 billion), and most of our approximate 70% portion of the net proceeds of $1.9 billion (C$2.5 billion) (after Canadian tax) were used to repay our outstanding commercial paper borrowings of $0.4 billion and in February 2019, to pay down approximately $1.3 billion of maturing long-term debt.

Losses and Gains on Impairments

Losses and Gains on Impairments, Divestitures and Other Write-downs (Notes)	12 Months Ended
	Dec. 31, 2021
Impairments [Abstract]
Impairment of Goodwill, Long-lived assets and equity investments [Text Block]	4. Losses and Gains on Impairments, Divestitures and Other Write-downs During the years ended December 31, 2021, 2020, and 2019, we recorded net pre-tax losses of $1,535 million, losses of $1,922 million and gains of $285 million, respectively, reflecting net losses on impairments of goodwill, long-lived assets, intangible and other assets and certain equity investments, and net losses and gains on divestitures of assets and equity investments. 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, and the year ended December 31, 2019 amount primarily includes a net pre-tax gain of $1,296 million related to the KML and U.S. Cochin Sale (see Note 3) and impairment losses of $1,014 million as further described below. We recognized the following non-cash pre-tax losses (gains) on impairments and divestitures on assets and equity investments during the years ended December 31, 2021, 2020, and 2019: Year Ended December 31, 2021 2020 2019 (In millions) Natural Gas Pipelines Impairments of long-lived assets(a) $ 1,600 $ — $ 290 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 and other write-downs(e) (1) 10 (967) Impairment of equity investments(f) — — 650 Products Pipelines Impairments of long-lived assets — 21 — Terminals Impairments of long-lived assets 34 5 — Losses (gains) on divestitures of long-lived assets(g) 2 (54) (335) Gain on sale of equity investment interests — (10) — CO 2 Impairment of goodwill(b) — 600 — Impairments of long-lived assets(h) — 350 74 (Gains) losses on divestitures of long-lived assets (8) — 2 Other (gains) losses on divestitures of long-lived assets (3) — 1 Pre-tax losses on impairments, divestitures and other write-downs, net $ 1,535 $ 1,922 $ (285) (a) 2021 amount represents non-cash impairments associated with our South Texas gathering and processing assets. 2019 amount represents non-cash impairments associated with certain gathering and processing assets in Oklahoma and northern Texas. (b) 2020 amount represent non-cash goodwill impairments associated with our Natural Gas Pipelines Non-Regulated and CO 2 reporting units (see “— Impairments — Goodwill ” below). (c) See Note 3. (d) See “— Other Write-downs ” below for a further discussion. (e) 2019 amount includes a $957 million gain related to the sale of the Cochin Pipeline system. (f) 2019 amount represents the non-cash impairment of our investment in Ruby which is included in “Earnings from equity investments” on our accompanying consolidated statements of income for the year ended December 31, 2019. (g) 2020 amount includes a $55 million gain related to the sale of our Staten Island terminal. 2019 amount includes a $339 million gain related to the sale of KML. (h) 2020 and 2019 amounts represent impairments of oil and gas properties. Impairments Long-lived Assets During the second quarter 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 CO 2 business segment which resulted in a non-cash impairment of long-lived assets within our CO 2 business segment shown in the above table during the year ended December 31, 2020. As of March 31, 2020, for our CO 2 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 CO 2 source and transportation assets, throughput and production volume forecasts were developed based on projected demand for our CO 2 services based upon management’s projections of the availability of CO 2 supply and the future demand for CO 2 for use in enhanced oil recovery projects. The CO 2 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 CO 2 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. Our largest impairment for the year ended December 31, 2019 was a $650 million non-cash impairment to our investment in Ruby in our Natural Gas Pipelines business segment. The impairment of our investment was considered from our subordinated ownership position and driven by reduced cash flow estimates identified during the period which resulted from (i) increased Canadian gas supplies and competition from other natural gas pipelines and (ii) upcoming contract expirations. These conditions were determined to be other than temporary. We utilized a discounted cash flow analysis. Additional impairments totaling $290 million were recognized during the year ended December 31, 2019 on long-lived assets within our Natural Gas Pipelines business segment and were driven by continued reduced drilling activity in Oklahoma and northern Texas demonstrated in the fourth quarter. The reduced estimate triggered an impairment analysis as we determined that our carrying value may no longer be recoverable. The assets failed step 1 of our evaluation. Step 2 involved using the income approach to calculate the fair value of the asset group and comparing it to the carrying value. The impairment that we recorded represented the difference between the fair and carrying values. 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. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value of our assets. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular reporting unit. The results of our May 31, 2021 annual impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value. During the first quarter of 2020, we conducted interim impairment tests of goodwill for our CO 2 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 CO 2 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 CO 2 reporting units indicated that their fair values exceeded their carrying values. The results of our impairment analyses for our Products Pipelines, Terminals and CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 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. Other Write-downs 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, driven by the recent impairment by Ruby of its assets, which is included within “Earnings from equity investments” in our accompanying consolidated statement of operations for the year ended December 31, 2021. The impairment at Ruby was the result of upcoming contract expirations and additional uncertainty identified in late February 2021 regarding the proposed development of a third party LNG exporting facility that could significantly increase the demand for its services.

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income Taxes	5. Income Taxes The components of “Income Before Income Taxes” are as follows: Year Ended December 31, 2021 2020 2019 (In millions) U.S. $ 2,217 $ 663 $ 2,482 Foreign 2 (2) 683 Total Income Before Income Taxes $ 2,219 $ 661 $ 3,165 Components of the income tax provision applicable for federal, foreign and state taxes are as follows: Year Ended December 31, 2021 2020 2019 (In millions) Current tax expense (benefit) Federal $ — $ (20) $ (2) State 11 9 10 Foreign(a) 3 147 201 Total 14 136 209 Deferred tax expense (benefit) Federal 334 440 682 State 21 49 66 Foreign(a) — (144) (31) Total 355 345 717 Total tax provision $ 369 $ 481 $ 926 (a) Our Canadian income tax (benefit) expense was $(1) million, $(4) million and $165 million for the years ended December 31, 2021, 2020 and 2019, respectively. The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows: Year Ended December 31, 2021 2020 2019 (In millions, except percentages) Federal income tax $ 466 21.0 % $ 139 21.0 % $ 665 21.0 % Increase (decrease) as a result of: Taxes on foreign earnings, net of federal benefit 2 0.1 % 2 0.3 % 139 4.4 % Net effects of noncontrolling interests (14) (0.6) % (13) (2.0) % (10) (0.3) % State income tax, net of federal benefit 50 2.2 % 52 7.9 % 68 2.1 % Dividend received deduction (46) (2.1) % (27) (4.1) % (39) (1.1) % Release of valuation allowance (38) (1.7) % — — % — — % Nondeductible goodwill — — % 336 50.8 % 108 3.4 % General business credit (36) (1.6) % — — % — — % Federal refunds — — % (20.0) (3.0) % — — % Other (15) (0.7) % 12 1.9 % (5) (0.2) % Total $ 369 16.6 % $ 481 72.8 % $ 926 29.3 % Deferred tax assets and liabilities result from the following: December 31, 2021 2020 (In millions) Deferred tax assets Employee benefits $ 154 $ 224 Net operating loss carryforwards 1,476 1,484 Tax credit carryforwards 301 257 Other 229 242 Valuation allowances (93) (138) Total deferred tax assets 2,067 2,069 Deferred tax liabilities Property, plant and equipment 166 414 Investments 1,769 1,084 Other 17 35 Total deferred tax liabilities 1,952 1,533 Net deferred tax assets $ 115 $ 536 Deferred Tax Assets and Valuation Allowances We have deferred tax assets of $1,476 million related to net operating loss carryovers, $301 million related to general business and foreign tax credits, and $93 million of valuation allowances related to these deferred tax assets as of December 31, 2021. As of December 31, 2020, we had deferred tax assets of $1,484 million related to net operating loss carryovers, $257 million related to general business and foreign tax credits, and $100 million of valuation allowances related to these deferred tax assets. We expect to generate taxable income and begin to utilize federal net operating loss carryforwards and tax credits in 2024. We decreased our valuation allowances related to net operating loss and tax credits in 2021 by $7 million, primarily due to $5 million of statute expirations for federal and state net operating losses and foreign tax credits and $2 million of currency fluctuations on foreign net operating losses. We also released the $38 million of valuation allowances related to our investment in NGPL upon the sale of a partial interest in NGPL. Expiration Periods for Deferred Tax Assets: As of December 31, 2021, we have U.S. federal net operating loss carryforwards of $2.7 billion that will be carried forward indefinitely and $3.2 billion that will expire from 2022 - 2037; state losses of $4 billion which will expire from 2022 - 2040; and foreign losses of $77 million which will be carried forward indefinitely. We also have $287 million of general business credits which will expire from 2026 - 2031; and approximately $14 million of foreign tax credits, which will expire from 2022 - 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. Our gross unrecognized tax benefit balances, excluding immaterial amounts of interest and penalties, were $21 million, $18 million and $16 million as of December 31, 2021, 2020 and 2019, respectively. Reductions based on settlements with taxing authorities were $0 million for each of the years ended December 31, 2021 and 2020 and $21 million for the year ended December 31, 2019, respectively. All of the $21 million of unrecognized tax benefits, if recognized, would affect our effective tax rate in future periods. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will not have any material change during the next year, primarily due to releases from statute expirations, offset by additions for state filing positions taken in prior years.

Property, Plant and Equipment (

Property, Plant and Equipment (Notes)	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, net	6. Property, Plant and Equipment, net Classes and Depreciation As of December 31, 2021 and 2020, our property, plant and equipment, net consisted of the following: December 31, 2021 2020 (In millions) Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 20,254 $ 20,339 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 26,511 26,142 Other(a) 5,356 5,188 Accumulated depreciation, depletion and amortization (18,792) (17,818) 33,329 33,851 Land and land rights-of-way 1,718 1,403 Construction work in process 606 582 Property, plant and equipment, net $ 35,653 $ 35,836 (a) Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and miscellaneous property, plant and equipment. As of December 31, 2021 and 2020, property, plant and equipment, net included $12,277 million and $12,160 million, respectively, of assets which were regulated by the FERC. Depreciation, depletion, and amortization expense charged against property, plant and equipment was $1,873 million, $1,928 million and $2,176 million for the years ended December 31, 2021, 2020 and 2019, respectively. Asset Retirement Obligations As of December 31, 2021 and 2020, we recognized asset retirement obligations in the aggregate amount of $196 million and $214 million, respectively, of which $4 million were classified as current for both periods. The majority of our asset retirement obligations are associated with our CO 2 business segment, 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.

Investments Investments (Notes)

Investments Investments (Notes)	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020, and our earnings (loss) from these respective investments for the years ended December 31, 2021, 2020 and 2019: Ownership Interest Equity Investments Earnings (Loss) from December 31, December 31, Year Ended December 31, 2021 2021 2020 2021 2020 2019 (In millions) Citrus Corporation 50% $ 1,768 $ 1,849 $ 151 $ 165 $ 157 SNG 50% 1,514 1,532 128 129 140 PHP 26.67% 647 632 63 — — Gulf Coast Express Pipeline LLC 34% 618 638 86 90 37 NGPL Holdings(a) 37.5% 604 803 94 116 81 MEP 50% 388 416 (17) (6) 15 Gulf LNG 50% 347 361 22 19 17 Products (SE) Pipe Line Corporation 51.17% 346 357 48 43 58 Utopia Holding LLC 50% 328 329 20 20 20 EagleHawk 25% 266 275 8 17 17 Watco Companies, LLC (b) 75 70 9 16 19 Cortez Pipeline Company 52.98% 28 25 29 24 35 FEP 50% — 16 — 70 59 Ruby(c) (d) — 1 (116) 15 (609) All others 649 613 66 62 55 Total investments $ 7,578 $ 7,917 $ 591 $ 780 $ 101 Amortization of excess cost $ (78) $ (140) $ (83) (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 December 31, 2021 and 2020 was $375 million and $500 million, respectively. For the years ended December 31, 2021, 2020 and 2019, we recognized $27 million, $34 million and $8 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, and the year ended December 31, 2019 loss includes a non-cash impairment charge of $650 million (pre-tax) related to our investment (see Note 4). (d) We operate Ruby and own the common interest in Ruby, the sole owner of the Ruby Pipeline natural gas transmission system. Pembina Pipeline Corporation (Pembina) owns the remaining interest in Ruby in the form of a convertible preferred interest. If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby. Summarized combined financial information for our significant equity investments (listed or described above) is reported below (amounts represent 100% of investee financial information): Year Ended December 31, Income Statement 2021(a) 2020 2019 (In millions) Revenues $ 5,426 $ 5,076 $ 4,906 Costs and expenses 6,083 4,249 3,508 Net (loss) income $ (657) $ 827 $ 1,398 December 31, Balance Sheet 2021 2020 (In millions) Current assets $ 1,235 $ 1,013 Non-current assets 22,749 25,069 Current liabilities 1,778 1,787 Non-current liabilities 9,931 9,734 Partners’/owners’ equity 12,275 14,561

Goodwill (Notes)

Goodwill (Notes)	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020 are summarized by reporting unit as follows: Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated CO 2 Products Pipelines Products Pipelines Terminals Terminals Energy Transition Ventures Total (In millions) Gross goodwill $ 15,892 $ 4,940 $ 1,528 $ 2,575 $ 221 $ 1,481 $ — $ 26,637 Accumulated impairment losses (1,643) (1,597) — (1,197) (70) (679) — (5,186) December 31, 2019 14,249 3,343 1,528 1,378 151 802 — 21,451 Impairments(a) — (1,000) (600) — — — — (1,600) December 31, 2020 14,249 2,343 928 1,378 151 802 — 19,851 Acquisition of Kinetrex — — — — — — 63 63 December 31, 2021 14,249 2,343 928 1,378 151 802 63 19,914 Gross goodwill 15,892 4,940 1,528 2,575 221 1,481 63 26,700 Accumulated impairment losses (1,643) (2,597) (600) (1,197) (70) (679) — (6,786) December 31, 2021 $ 14,249 $ 2,343 $ 928 $ 1,378 $ 151 $ 802 $ 63 $ 19,914 (a) See Note 4 “ Losses and Gains on Impairments, Divestitures and Other Write-downs—Goodwill Impairments ” for further information regarding our goodwill impairments.

Debt (Notes)

Debt (Notes)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Debt	9. Debt The following table provides detail on the principal amount of our outstanding debt balances: December 31, 2021 2020 (In millions) Credit facility and commercial paper borrowings(a) $ — $ — Corporate senior notes(b) 5.00%, due February 2021 — 750 3.50%, due March 2021(c) — 750 5.80%, due March 2021 — 400 5.00%, due October 2021 — 500 4.15%, due March 2022 375 375 1.50%, due March 2022(d) 853 917 3.95%, due September 2022 1,000 1,000 3.15%, due January 2023 1,000 1,000 Floating rate, due January 2023(e) 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(f) 500 — 6.70%, due February 2027 7 7 2.25%, due March 2027(d) 569 611 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 7.30%, due August 2033 500 500 5.30%, due December 2034 750 750 5.80%, due March 2035 500 500 7.75%, due October 2035 1 1 6.40%, due January 2036 36 36 6.50%, due February 2037 400 400 7.42%, due February 2037 47 47 6.95%, due January 2038 1,175 1,175 6.50%, due September 2039 600 600 6.55%, due September 2040 400 400 7.50%, due November 2040 375 375 6.375%, due March 2041 600 600 5.625%, due September 2041 375 375 5.00%, due August 2042 625 625 4.70%, due November 2042 475 475 5.00%, due March 2043 700 700 5.50%, due March 2044 750 750 5.40%, due September 2044 550 550 5.55%, due June 2045 1,750 1,750 5.05%, due February 2046 800 800 5.20%, due March 2048 750 750 3.25%, due August 2050 500 500 3.60%, due February 2051(f)(g) 1,050 — 7.45%, due March 2098 26 26 (continued) December 31, 2021 2020 TGP senior notes(b) 7.00%, due March 2027 300 300 7.00%, due October 2028 400 400 2.90%, due March 2030 1,000 1,000 8.375%, due June 2032 240 240 7.625%, due April 2037 300 300 EPNG senior notes(b) 8.625%, due January 2022(h) 260 260 7.50%, due November 2026 200 200 8.375%, due June 2032 300 300 CIG senior notes(b) 4.15%, due August 2026 375 375 6.85%, due June 2037 100 100 EPC Building, LLC, promissory note, 3.967%, due January 2021 through December 2035 364 380 Trust I Preferred Securities, 4.75%, due March 2028(i) 221 221 Other miscellaneous debt(j) 248 254 Total debt – KMI and Subsidiaries 32,418 33,396 Less: Current portion of debt(k) 2,646 2,558 Total long-term debt – KMI and Subsidiaries(l) $ 29,772 $ 30,838 (a) See “—Current portion of debt” below for further details regarding our outstanding credit facilities and commercial paper borrowings. (b) Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. (c) On January 4, 2021, we repaid our $750 million senior corporate notes. (d) Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2021 exchange rate of 1.1370 U.S. dollars per Euro and at the December 31, 2020 exchange rate of 1.2216 U.S. dollars per Euro. As of December 31, 2021 and 2020, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in increases to our debt balance of $38 million and $102 million, respectively, related to the 1.50% series and increases of $26 million and $68 million, respectively, related to the 2.25% series. The cumulative increase in debt due to the changes in exchange rates is offset by a corresponding change in the value of cross-currency swaps reflected in “Deferred charges and other assets” and “Other long-term liabilities and deferred credits” on our accompanying consolidated balance sheets. At the time of issuance, we entered into foreign currency contracts associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 14 “ Risk Management—Foreign Currency Risk Management ”). (e) As of December 31, 2021, we had outstanding, an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge. (f) On October 26, 2021, we issued in a registered offering two series of senior notes consisting of $500 million aggregate principal amount of 1.75% senior notes due 2026 and $300 million aggregate principal amount of 3.60% senior notes due 2051 as a reopening of the 3.60% series (see (g) following) and received combined net proceeds of $796 million. These notes are guaranteed through the cross guarantee agreement discussed below. (g) On February 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million These notes are guaranteed through the cross guarantee agreement discussed below. (h) On January 18, 2022, we repaid these senior notes. (i) Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2021, 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, 2021 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. (j) Includes finance lease obligations with monthly installments. The lease terms expire between 2026 and 2061. (k) Amounts include KMI outstanding credit facility borrowings, commercial paper borrowings and other debt maturing within 12 months. See “—Current Portion of Debt” below. (l) Excludes our “Debt fair value adjustments” which, as of December 31, 2021 and 2020, increased our combined debt balances by $902 million and $1,293 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. Current Portion of Debt The following table details the components of our “Current portion of debt” reported on our consolidated balance sheets: December 31, 2021 2020 (In millions) $3.5 billion credit facility due August 20, 2026(a) $ — $ — $500 million credit facility due November 16, 2023(a) — — Commercial paper notes(a) — — Current portion of senior notes 5.00%, due February 2021 — 750 3.50%, due March 2021 — 750 5.80%, due March 2021 — 400 5.00%, due October 2021 — 500 8.625%, due January 2022(b) 260 — 4.15%, due March 2022 375 — 1.50%, due March 2022(c) 853 — 3.95% due September 2022 1,000 — Trust I Preferred Securities, 4.75% due March 2028(d) 111 111 Current portion of other debt 47 47 Total current portion of debt $ 2,646 $ 2,558 (a) On August 20, 2021, we entered into an agreement for a new five-year credit facility and amended our existing credit facility discussed further in “—Credit Facilities and Restrictive Covenants” following. (b) On January 18, 2022, we repaid these senior notes. (c) Denominated in Euros. (d) Reflects the portion of cash consideration payable if all the outstanding securities as of the end of the reporting period were converted by the holders. We and substantially all of our wholly owned domestic subsidiaries are a 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. Credit Facility and Restrictive Covenants On August 20, 2021, we entered into a new $3.5 billion revolving credit facility (the “New Credit Facility”) due August 2026 with a syndicate of lenders, which can be increased by up to $1.0 billion if certain conditions, including the receipt of additional lender commitments, are met. Borrowings under the New Credit Facility may be used for working capital and other general corporate purposes. On the same date, we also entered into a first amendment (the “Amendment”) to our existing Revolving Credit Agreement, dated as of November 16, 2018 (as amended prior to the Amendment, the “Existing Credit Facility”). The Amendment provides for certain amendments to the Existing Credit Facility to, among other things, reduce the Existing Credit Facility’s borrowing capacity to $500 million and terminate the letter of credit commitments and the swing line capacity thereunder. The combined credit facilities continue to support our $4 billion commercial paper program. As of December 31, 2021, we had borrowing capacity of approximately $3.9 billion under our credit facilities. We also continue to maintain a $4 billion commercial paper program through the private placement of short-term notes. 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 revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility. Depending on the type of loan request, our credit facility borrowings under our credit facilities bear interest at either (i) LIBOR adjusted for a eurocurrency funding reserve plus an applicable margin ranging from 1.000% to 1.750% (for our New Credit Facility) or to 2.000% (for our Existing 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) LIBOR for a one-month eurodollar loan adjusted for a eurocurrency funding reserve, plus 1%, plus, in each case, an applicable margin ranging from 0.100% to 0.750% (for our New Credit Facility) or to 1.000% (for our Existing 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 New Credit Facility) or to 0.300% (for our Existing Credit Facility). The New Credit Facility also includes customary provisions to provide for replacement of LIBOR with an alternative benchmark rate when LIBOR ceases to be available. Our credit facility contains financial and various other covenants that apply to us and our subsidiaries and are common in such agreements, including a maximum ratio of Consolidated Net Indebtedness to Consolidated EBITDA (as defined in the credit facility) of 5.50 to 1.00, for any four-fiscal-quarter period. Other negative covenants include restrictions on our and certain of our subsidiaries’ ability to incur debt, grant liens, make fundamental changes or engage in certain transactions with affiliates, or in the case of certain material subsidiaries, permit restrictions on dividends, distributions or making or prepayments of loans to us or any guarantor. Our credit facility also restricts our ability to make certain restricted payments if an event of default (as defined in the credit facility) has occurred and is continuing or would occur and be continuing. As of December 31, 2021, we had no borrowings outstanding under our credit facility, 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, 2021 was approximately $3.9 billion. As of December 31, 2021, we were in compliance with all required covenants. Maturities of Debt The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2021, are summarized as follows: Year Total (In millions) 2022 $ 2,646 2023 3,250 2024 1,925 2025 1,567 2026 1,102 Thereafter 21,928 Total $ 32,418 Debt Fair Value Adjustments The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets: December 31, 2021 2020 (In millions) Purchase accounting debt fair value adjustments $ 498 $ 546 Carrying value adjustment to hedged debt 376 702 Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a) 223 240 Unamortized debt discounts, net (71) (76) Unamortized debt issuance costs (124) (119) Total debt fair value adjustments $ 902 $ 1,293 (a) As of December 31, 2021, the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 13 years. Fair Value of Financial Instruments The carrying value and estimated fair value of our outstanding debt balances is disclosed below: December 31, 2021 December 31, 2020 Carrying Estimated Carrying Estimated (In millions) Total debt $ 33,320 $ 37,775 $ 34,689 $ 39,622 We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2021 and 2020. Interest Rates, Interest Rate Swaps and Contingent Debt The weighted average interest rate on all of our borrowings was 4.67% during 2021 and 4.86% during 2020. Information on our interest rate swaps is contained in Note 14. For information about our contingent debt agreements, see Note 13 “ Commitments and Contingent Liabilities—Contingent Debt ”).

Share-based Compensation and Em

Share-based Compensation and Employee Benefits (Notes)	12 Months Ended
	Dec. 31, 2021
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 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, in which our eligible non-employee directors participate. 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 to receive shares of Class P common stock. Each election will be generally at or around the first board of directors meeting in January of each calendar year and will be effective for the entire calendar year. An eligible director may make a new election each calendar year. The total number of shares of Class P common stock authorized under the plan is 1,190,000. During 2021, 2020 and 2019, we made restricted Class P common stock grants to our non-employee directors of 49,890, 14,570 and 23,100, respectively. These grants were valued at time of issuance at $0.8 million, $0.3 million and $0.4 million, respectively. All of the restricted stock awards made to non-employee directors vest during a 6-month period. Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan The Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan is an equity awards plan available to eligible employees. The total number of shares of Class P common stock authorized under the plan is 63,000,000. The following table sets forth a summary of activity and related balances of our restricted stock awards excluding that issued to non-employee directors: Shares Weighted Average Grant Date Fair Value per Share (In thousands, except per share amounts) Outstanding at December 31, 2020 12,682 $ 17.79 Granted 4,705 17.44 Vested (4,463) 17.89 Forfeited (307) 17.47 Outstanding at December 31, 2021 12,617 $ 17.63 The following table sets forth additional information related to our restricted stock awards excluding that issued to non-employee directors: Year Ended December 31, 2021 2020 2019 (In millions, except per share amounts) Weighted average grant date fair value per share $ 17.44 $ 15.10 $ 20.46 Intrinsic value of awards vested during the year 77 59 87 Restricted stock awards made to employees have vesting periods ranging from 1 year up to 10 years. Following is a summary of the future vesting of our outstanding restricted stock awards: Year Vesting of Restricted Shares (In thousands) 2022 2,832 2023 5,552 2024 3,662 2025 513 2026 58 Total Outstanding 12,617 During 2021, 2020 and 2019, we recorded $59 million, $73 million and $62 million, respectively, in expense related to restricted stock awards and capitalized approximately $9 million, $11 million and $12 million, respectively. We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements. At December 31, 2021, unrecognized restricted stock awards compensation costs, less estimated forfeitures, was approximately $112 million with a weighted average remaining amortization period of 1.98 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 $48 million, $53 million, and $50 million for the years ended December 31, 2021, 2020 and 2019, 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, 2021 and 2020: Pension Benefits OPEB 2021 2020 2021 2020 (In millions) Change in benefit obligation: Benefit obligation at beginning of period $ 2,844 $ 2,696 $ 299 $ 333 Service cost 53 59 1 1 Interest cost 45 71 4 8 Actuarial (gain) loss (80) 198 (21) (17) Benefits paid (204) (180) (28) (29) Participant contributions — — 1 2 Medicare Part D subsidy receipts — — 1 1 Benefit obligation at end of period 2,658 2,844 257 299 Change in plan assets: Fair value of plan assets at beginning of period 2,199 2,076 361 333 Actual return on plan assets 180 178 40 47 Employer contributions 56 125 7 7 Participant contributions — — 1 2 Medicare Part D subsidy receipts — — 1 1 Benefits paid (204) (180) (28) (29) Fair value of plan assets at end of period 2,231 2,199 382 361 Funded status - net (liability) asset at December 31, $ (427) $ (645) $ 125 $ 62 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. The 2020 net actuarial loss for the pension plans was primarily due to a decrease in the weighted average discount rate used to determine the benefit obligation as of December 31, 2020. The 2020 net actuarial gain for the OPEB plans was primarily due to changes in the claims cost and trend assumptions, partially offset by a decrease in the weighted average discount rate used to determine the benefit obligations as of December 31, 2020. Components of Funded Status . The following table details the amounts recognized in our balance sheets at December 31, 2021 and 2020 related to our pension and OPEB plans: Pension Benefits OPEB 2021 2020 2021 2020 (In millions) Non-current benefit asset(a) $ — $ — $ 302 $ 269 Current benefit liability — — (18) (19) Non-current benefit liability (427) (645) (159) (188) Funded status - net (liability) asset at December 31, $ (427) $ (645) $ 125 $ 62 (a) 2021 and 2020 OPEB amounts include $54 million and $46 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. Components of Accumulated Other Comprehensive (Loss) Income . The following table details the amounts of pre-tax accumulated other comprehensive (loss) income at December 31, 2021 and 2020 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets: Pension Benefits OPEB 2021 2020 2021 2020 (In millions) Unrecognized net actuarial (loss) gain $ (495) $ (674) $ 176 $ 153 Unrecognized prior service (cost) credit (2) (2) 6 9 Accumulated other comprehensive (loss) income $ (497) $ (676) $ 182 $ 162 Our accumulated benefit obligation for our pension plans was $2,608 million and $2,804 million at December 31, 2021 and 2020, respectively. Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $219 million and $255 million at December 31, 2021 and 2020, respectively. The fair value of these plans’ assets was approximately $42 million and $48 million at December 31, 2021 and 2020, respectively. 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. As of December 31, 2021, the allowable range for asset allocations in effect for our pension plan were 42% to 52% equities, 37% to 47% fixed income securities, 2% to 12% real estate and 0% to 10% company securities (KMI Class P common stock and/or debt securities). As of December 31, 2021, the allowable range for asset allocations in effect for our OPEB plans were 0% to 22% cash, 46% to 68% equities and 25% to 50% fixed income securities. 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 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, 2021 and 2020: Pension Assets 2021 2020 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Cash $ 11 $ — $ 11 $ — $ — $ — Short-term investment funds — 25 25 — 77 77 Equities(a) 153 — 153 249 — 249 Fixed income securities(b) — 566 566 — 425 425 Derivatives — — — — 11 11 Subtotal $ 164 $ 591 755 $ 249 $ 513 762 Measured at NAV(c) Common/collective trusts(d) 1,389 1,184 Private investment funds(e) 39 208 Private limited partnerships(f) 48 45 Subtotal 1,476 1,437 Total plan assets fair value $ 2,231 $ 2,199 (a) Plan assets include $97 million and $83 million of KMI Class P common stock for 2021 and 2020, respectively. (b) Plan assets include $1 million of KMI debt securities for 2020. (c) Plan assets which used NAV as a practical expedient to measure fair value. (d) Common/collective trust funds were invested in approximately 83% equities and 17% fixed income securities in 2021 and 71% equities and 29% fixed income securities in 2020. (e) Private investment funds were invested in 100% fixed income securities in 2021 and approximately 29% equities and 71% fixed income securities in 2020. (f) Includes assets invested in real estate, venture and buyout funds. OPEB Assets 2021 2020 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Short-term investment funds $ — $ 3 $ 3 $ — $ 5 $ 5 Measured at NAV(a) Common/collective trusts(b) 379 356 Total plan assets fair value $ 382 $ 361 (a) Plan assets which used NAV as a practical expedient to measure fair value. (b) Common/collective trust funds were invested in approximately 63% equities and 37% fixed income securities for 2021 and 65% equities and 35% fixed income securities for 2020. Expected Payment of Future Benefits and Employer Contributions . As of December 31, 2021, we expect to make the following benefit payments under our plans: Fiscal year Pension Benefits OPEB(a) (In millions) 2022 $ 212 $ 28 2023 210 26 2024 204 24 2025 199 22 2026 194 21 2027 - 2031 864 84 (a) Includes a reduction of approximately $1 million in each of the years 2022 through 2026 and approximately $4 million in aggregate for the period 2027 - 2031 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. In 2022, we expect to contribute approximately $50 million to our pension plans and $7 million, net of anticipated subsidies, to our OPEB plans. 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 and net benefit costs of our pension and OPEB plans for 2021, 2020 and 2019: Pension Benefits OPEB 2021 2020 2019 2021 2020 2019 (In millions) Assumptions related to benefit obligations: Discount rate 2.74 % 2.27 % 3.17 % 2.56 % 2.08 % 3.03 % 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 Assumptions related to benefit costs: Discount rate for benefit obligations 2.27 % 3.17 % 4.26 % 2.08 % 3.03 % 4.16 % Discount rate for interest on benefit obligations 1.60 % 2.71 % 3.89 % 1.46 % 2.63 % 3.83 % Discount rate for service cost 2.33 % 3.24 % 4.28 % 2.70 % 3.48 % 4.51 % Discount rate for interest on service cost 1.70 % 2.80 % 3.93 % 2.63 % 3.39 % 4.46 % Expected return on plan assets(a) 6.25 % 6.75 % 7.25 % 5.75 % 6.50 % 6.50 % Rate of compensation increase 3.50 % 3.50 % 3.50 % n/a n/a n/a Interest crediting rate 2.57 % 3.71 % 3.90 % n/a n/a n/a (a) 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 (UBIT), we utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on UBIT rates of 27% for each of 2021, 2020 and 2019. We utilize a full yield curve approach in the estimation of 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. 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 5.63% which gradually decreases to 4.00% by the year 2046. 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 2021 2020 2019 2021 2020 2019 (In millions) Components of net benefit cost (credit): Service cost $ 53 $ 59 $ 53 $ 1 $ 1 $ 1 Interest cost 45 71 96 4 8 12 Expected return on assets (133) (137) (129) (16) (16) (16) Amortization of prior service cost (credit) — 1 — (5) (5) (4) Amortization of net actuarial loss (gain) 52 40 54 (17) (13) (11) Net benefit cost (credit) 17 34 74 (33) (25) (18) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net (gain) loss arising during period (127) 157 (42) (40) (43) (17) Amortization or settlement recognition of net actuarial (loss) gain (52) (40) (54) 17 13 11 Amortization of prior service (cost) credit — (1) — 3 3 2 Total recognized in total other comprehensive (income) loss(a) (179) 116 (96) (20) (27) (4) Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ (162) $ 150 $ (22) $ (53) $ (52) $ (22) (a) Excludes $3 million and $2 million for the years ended December 31, 2021 and 2020, respectively, associated with other plans. Multiemployer Plans We participate in several multi-employer pension plans for the benefit of employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs. Amounts charged to expense for these plans were approximately $8 million, $6 million and $8 million for the years ended December 31, 2021, 2020 and 2019, respectively. We consider the overall multi-employer pension plan liability exposure to be immaterial in relation to the value of its total consolidated assets and net income.

Stockholders' Equity (Notes)

Stockholders' Equity (Notes)	12 Months Ended
	Dec. 31, 2021
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. During the year ended December 31, 2021, we did not repurchase any shares. During the years ended December 31, 2020 and 2019, we repurchased approximately 4.0 million and 0.1 million, respectively, of our shares for approximately $50 million and $2 million, respectively. Since December 2017, in total, we have repurchased approximately 32 million of our shares under the program at an average price of approximately $17.71 per share for approximately $575 million. 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 $5.0 billion from time to time during the term of this agreement. During the years ended December 31, 2021, 2020 and 2019 we did not issue any shares under this agreement. Dividends The following table provides information about our per share dividends: Year Ended December 31, 2021 2020 2019 Per share cash dividend declared for the period $ 1.08 $ 1.05 $ 1.00 Per share cash dividend paid in the period 1.0725 1.0375 0.95 On January 19, 2022, our board of directors declared a cash dividend of $0.27 per share for the quarterly period ended December 31, 2021, which is payable on February 15, 2022 to shareholders of record as of January 31, 2022. Accumulated Other Comprehensive Loss Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows: Net unrealized Foreign Pension and Total (In millions) Balance at December 31, 2018 $ 164 $ (91) $ (403) $ (330) Other comprehensive (loss) gain before reclassifications (177) — 77 (100) Losses reclassified from accumulated other comprehensive loss(a) 6 91 — 97 Net current-period change in accumulated other comprehensive income (loss) (171) 91 77 (3) 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) (a) Amount for foreign currency translation adjustments reflect the deferred losses recognized in income during the year ended December 31, 2019 related to the sale of KML. Noncontrolling Interests KML Distributions In accordance with its dividend policy, KML, our former indirect subsidiary, paid cash dividends to the public during the year ended December 31, 2019 of $17 million and $22 million, on its restricted voting shares and preferred shares, respectively. On January 3, 2019, KML distributed approximately $0.9 billion of the net proceeds from the TMPL Sale to its public held restricted voting shareholders as a return of capital.

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2021
Related Party Transactions [Abstract]
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, and for periods prior to the sale of KML, our proportional method joint ventures, for which we include our proportionate share of activity in our financial statements. 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, 2021 2020 (In millions) Balance sheet location Accounts receivable $ 38 $ 41 Other current assets 4 6 Deferred charges and other assets — 109 $ 42 $ 156 Current portion of debt $ 6 $ 6 Accounts payable 21 25 Other current liabilities 4 4 Long-term debt 148 154 Other long-term liabilities and deferred credits 56 48 $ 235 $ 237 Year Ended December 31, 2021 2020 2019 (In millions) Income statement location Revenues $ 164 $ 206 $ 269 Operating Costs, Expenses and Other Costs of sales $ 145 $ 116 $ 75 Other operating expenses 52 119 132

Commitments and Contingent Liab

Commitments and Contingent Liabilities (Notes)	12 Months Ended
	Dec. 31, 2021
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 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 $149 million as of December 31, 2021. 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, 2021 and 2020, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $170 million and $217 million, respectively. December 31, 2021 and 2020 amounts are represented by our proportional share of the debt obligations of one and three equity investees, respectively. Under such guarantees we are severally liable for our percentage ownership share of these equity investees’ debt issued in the event of their non-performance. The contingent debt obligations balances as of December 31, 2021 and 2020 included $120 million and $122 million, respectively, for 100% guaranteed debt obligations for a subsidiary of our equity investee, Cortez Pipeline Company. 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. Currently, we are not subject to any material requirements to perform under quantifiable arrangements other than as described above. We are unable to estimate a maximum exposure for our other guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures. See Note 18 for a description of matters that we have identified as contingencies requiring accrual of liabilities and/or disclosure, including any such matters arising under guarantee or indemnification agreements.

Risk Management (Notes)

Risk Management (Notes)	12 Months Ended
	Dec. 31, 2021
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, 2021, 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 (6.5) MMBbl Natural gas fixed price (54.2) Bcf Natural gas basis (43.9) Bcf NGL fixed price (0.7) MMBbl Derivatives not designated as hedging contracts Crude oil fixed price (1.0) MMBbl Crude oil basis (9.1) MMBbl Natural gas fixed price (13.2) Bcf Natural gas basis (38.5) Bcf NGL fixed price (1.4) MMBbl As of December 31, 2021, 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 2025. 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, 2021: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments Fixed-to-variable interest rate contracts(a) $ 7,100 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(b) 5,100 Mark-to-Market December 2022 (a) The principal amount of hedged senior notes consisted of $750 million included in “Current portion of debt” and $6,350 million included in “Long-term debt” on our accompanying consolidated balance sheet. (b) Of this notional amount, $4,860 million became effective January 4, 2022. During the year ended December 31, 2021, we entered into fixed-to-variable interest rate swap agreements with a combined notional principal amount of $375 million. These agreements were designated as accounting hedges and convert a portion of our fixed rate debt to variable rates through February 2028. In addition, we entered into variable-to-fixed interest rate swap agreements with a combined notional principal amount of $5,100 million. These agreements were not designated as accounting hedges and effectively fixed our LIBOR exposure for a portion of our fixed-to-variable interest rate swaps for 2022. 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, 2021: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments EUR-to-USD cross currency swap contracts(a) $ 1,358 Cash flow hedge March 2027 (a) These s waps eliminate the foreign currency risk associated with all of 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 Derivatives December 31, December 31, 2021 2020 2021 2020 Location Fair value Fair value (In millions) Derivatives designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 61 $ 42 $ (141) $ (33) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 3 33 (94) (8) Subtotal 64 75 (235) (41) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 101 119 (3) (3) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 284 575 (15) (7) Subtotal 385 694 (18) (10) Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) 35 — (3) (6) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 6 138 — — Subtotal 41 138 (3) (6) Total 490 907 (256) (57) Derivatives not designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 11 24 (31) (21) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 1 — (6) — Subtotal 12 24 (37) (21) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 12 — — — Total 24 24 (37) (21) Total derivatives $ 514 $ 931 $ (293) $ (78) 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(b) Net amount (In millions) As of December 31, 2021 Energy commodity derivative contracts(a) $ 56 $ 20 $ — $ 76 $ (53) $ (20) $ 3 Interest rate contracts — 397 — 397 (9) — 388 Foreign currency contracts — 41 — 41 (3) — 38 As of December 31, 2020 Energy commodity derivative contracts(a) $ 6 $ 93 $ — $ 99 $ (35) $ — $ 64 Interest rate contracts — 694 — 694 (2) — 692 Foreign currency contracts — 138 — 138 (6) — 132 Balance sheet liability Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral posted(b) Net amount (In millions) As of December 31, 2021 Energy commodity derivative contracts(a) $ (15) $ (257) $ — $ (272) $ 53 $ — $ (219) Interest rate contracts — (18) — (18) 9 — (9) Foreign currency contracts — (3) — (3) 3 — — As of December 31, 2020 Energy commodity derivative contracts(a) (7) (56) — (63) 35 (8) (36) Interest rate contracts — (10) — (10) 2 — (8) Foreign currency contracts — (6) — (6) 6 — — (a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps. (b) 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. 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, 2021 2020 2019 (In millions) Interest rate contracts Interest, net $ (322) $ 335 $ 340 Hedged fixed rate debt(a) Interest, net $ 326 $ (343) $ (353) (a) As of December 31, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $376 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, 2021 2020 2019 2021 2020 2019 (In millions) (In millions) Energy commodity derivative contracts $ (475) $ 240 $ (168) Revenues—Commodity sales $ (271) $ 222 $ 16 Costs of sales 20 (14) 5 Interest rate contracts(c) 5 (8) (1) Earnings from equity investments(c) — — 2 Foreign currency contracts (93) 92 (60) Other, net (105) 125 (31) Total $ (563) $ 324 $ (229) Total $ (356) $ 333 $ (8) (a) We expect to reclassify an approximately $58 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2021 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, 2021, 2020 and 2019, we recognized gains of $41 million, no gains and gains of $12 million, respectively, associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred). (c) Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss). Derivatives in net investment hedging relationships Gain/(loss) recognized in OCI on derivative Location Gain/(loss) reclassified from Accumulated OCI into income(a) Year Ended Year Ended December 31, December 31, 2021 2020 2019 2021 2020 2019 (In millions) (In millions) Foreign currency contracts $ — $ — $ (8) Loss (gain) on impairments and divestitures, net $ — $ — $ 83 Total $ — $ — $ (8) Total $ — $ — $ 83 (a) During the year ended December 31, 2019, we recognized an $83 million gain related to the KML and U.S. Cochin Sale. See Note 3. Derivatives not designated as accounting hedges Location Gain/(Loss) recognized in income on derivatives Year Ended December 31, 2021 2020 2019 (In millions) Energy commodity derivative contracts Revenues—Commodity sales $ (652) $ (1) $ 33 Costs of sales 152 25 (7) Earnings from equity investments(b) (5) — 3 Interest rate contracts Interest, net 12 — — Total(a) $ (493) $ 24 $ 29 (a) The years ended December 31, 2021, 2020 and 2019 include approximate losses of $479 million, $11 million and $8 million, respectively, associated with natural gas, crude and NGL derivative contract settlements. (b) Amounts represent our share of an equity investee’s income (loss). 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, 2021 and 2020, we had no outstanding letters of credit supporting our commodity price risk management program. 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. As of December 31, 2020 we had cash margins of $3 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The balance at December 31, 2021 represents the initial margin requirements of $6 million, offset by counterparty variation margin requirements of $20 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, 2021, 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 $155 million of additional collateral.

Revenue Recognition (Notes)

Revenue Recognition (Notes)	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Revenue Recognition	15. Revenue Recognition Nature of Revenue by Segment Natural Gas Pipelines Segment We provide various types of natural gas transportation and storage services, natural gas and NGL sales contracts, and various types of gathering and processing services for producers, including receiving, compressing, transporting and re-delivering quantities of natural gas and/or NGLs made available to us by producers to a specified delivery location. Natural Gas Transportation and Storage Contracts The natural gas we receive under our transportation and storage contracts remains under the control of our customers. Under firm service contracts, the customer generally pays a two-part transaction price that includes (i) a fixed take-or-pay reservation fee and (ii) a fee-based per-unit rate for quantities of natural gas actually transported or injected into/withdrawn from storage. Under non-firm service contracts, generally described as interruptible service, the customer pays a transaction price on a fee-based per-unit rate for the quantities actually transported or injected into/withdrawn from storage. Natural Gas and NGL Sales Contracts Our sales and purchases of natural gas and NGL are primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales. These customer contracts generally provide for the customer to nominate a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold. Gathering and Processing Contracts We provide various types of gathering and processing services for producers, including receiving, processing, compressing, transporting and re-delivering quantities of natural gas made available to us by producers to a specified delivery location. This integrated service can be firm if subject to a minimum volume commitment or acreage dedication or non-firm when offered on an as requested, non-guaranteed basis. In our gathering contracts we generally promise to provide the contracted integrated services each day over the life of the contract. The customer pays a transaction price typically based on a per-unit rate for the quantities actually gathered and/or processed, including amounts attributable to deficiency quantities associated with minimum volume contracts. Products Pipelines Segment We provide crude oil and refined petroleum transportation and storage services on a firm or non-firm basis. For our firm transportation service, the customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it flows volumes into our pipeline. The customer pays a transaction price typically based on a per-unit rate for quantities transported, including amounts attributable to deficiency quantities. Our firm storage service generally includes a fixed take-or-pay monthly reservation fee for the portion of storage capacity reserved by the customer and a per-unit rate for actual quantities injected into/withdrawn from storage. Under the non-firm transportation and storage service the customer typically pays a per-unit rate for actual quantities of product injected into/withdrawn from storage and/or transported. We sell transmix, crude oil or other commodity products. The customer’s contracts generally include a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold. Terminals Segment We provide various types of liquid tank and bulk terminal services. These services are generally comprised of inbound, storage and outbound handling of customer products. Liquids Tank Services Firm Storage and Handling Contracts: We have liquids tank storage and handling service contracts that include a promised tank storage capacity provision and prepaid volume throughput of the stored product. In these contracts, the customers have fixed take-or-pay monthly obligation which generally include a per-unit rate for any quantities we handle at the request of the customer in excess of the prepaid volume throughput amount and also typically include per-unit rates for additional, ancillary services that may be periodically requested by the customer. Firm Handling Contracts: For our firm handling service contracts, we typically promise to handle on a stand-ready basis throughput volumes up to the customer’s minimum volume commitment amount. The customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it used the handling service. The customer pays a transaction price typically based on a per-unit rate for volumes handled, including amounts attributable to deficiency quantities. Bulk Services Our bulk storage and handling contracts generally include inbound handling of our customers’ dry bulk material product (e.g. petcoke, metals, ores) into our storage facility and outbound handling of these products from our storage facility. These services are provided on both a firm basis, including amounts attributable to deficiency quantities, and non-firm basis where the customer pays a transaction price typically based on a per-unit rate for quantities handled on an as requested, non-guaranteed basis. CO 2 Segment Our crude oil, NGL, CO 2 and natural gas production customer sales contracts typically include a specified quantity and quality of commodity product to be delivered and sold to the customer at a specified delivery point. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold. Disaggregation of Revenues The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source: Year Ended December 31, 2021 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,402 $ 259 $ 751 $ 1 $ (2) $ 4,411 Fee-based services 746 949 375 45 (1) 2,114 Total services 4,148 1,208 1,126 46 (3) 6,525 Commodity sales Natural gas sales 6,463 — — 32 (15) 6,480 Product sales 1,260 845 24 1,070 (50) 3,149 Total commodity sales 7,723 845 24 1,102 (65) 9,629 Total revenues from contracts with customers 11,871 2,053 1,150 1,148 (68) 16,154 Other revenues(c) Leasing services(d) 473 172 565 56 — 1,266 Derivatives adjustments on commodity sales (700) (1) — (222) — (923) Other 65 21 — 27 — 113 Total other revenues (162) 192 565 (139) — 456 Total revenues $ 11,709 $ 2,245 $ 1,715 $ 1,009 $ (68) $ 16,610 Year Ended December 31, 2020 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,345 $ 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 Year Ended December 31, 2019 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,549 $ 319 $ 1,012 $ 1 $ (4) $ 4,877 Fee-based services 780 1,016 560 60 — 2,416 Total services 4,329 1,335 1,572 61 (4) 7,293 Commodity sales Natural gas sales 2,603 — — 1 (9) 2,595 Product sales 805 289 20 1,111 (33) 2,192 Total commodity sales 3,408 289 20 1,112 (42) 4,787 Total revenues from contracts with customers 7,737 1,624 1,592 1,173 (46) 12,080 Other revenues(c) Leasing services(d) 273 182 442 54 — 951 Derivatives adjustments on commodity sales 70 — — (21) — 49 Other 90 25 — 13 1 129 Total other revenues 433 207 442 46 1 1,129 Total revenues $ 8,170 $ 1,831 $ 2,034 $ 1,219 $ (45) $ 13,209 (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, 2021 and 2020, our contract asset balances were $39 million and $20 million, respectively. Of the contract asset balance at December 31, 2020, $18 million was transferred to accounts receivable during the year ended December 31. 2021. As of December 31, 2021 and 2020, our contract liability balances were $212 million and $239 million, respectively. Of the contract liability balance at December 31, 2020, $83 million was recognized as revenue during the year ended December 31, 2021. 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, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods: Year Estimated Revenue (In millions) 2022 $ 4,324 2023 3,418 2024 2,857 2025 2,382 2026 2,108 Thereafter 12,618 Total $ 27,707 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.

Reportable Segments (Notes)

Reportable Segments (Notes)	12 Months Ended
	Dec. 31, 2021
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. and portions of Canada (prior to the sale of KML in December 2019) that store and handle various commodities including gasoline, diesel fuel, chemicals, renewable fuels, metals and petroleum coke; and (ii) Jones Act-qualified tankers; • CO 2 —(i) the production, transportation and marketing of CO 2 to oil fields that use CO 2 as a flooding medium to increase recovery and production of crude oil from mature oil fields; (ii) ownership interests in and/or operation of oil fields and gasoline processing plants in West Texas; (iii) the ownership and operation of a crude oil pipeline system in West Texas; and (iv) the ownership and operation of RNG and LNG facilities in Indiana associated with our acquisition of Kinetrex (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 2021, 2020 and 2019, 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, 2021 2020 2019 (In millions) Revenues Natural Gas Pipelines Revenues from external customers $ 11,644 $ 7,222 $ 8,128 Intersegment revenues 65 37 42 Products Pipelines 2,245 1,721 1,831 Terminals Revenues from external customers 1,712 1,719 2,031 Intersegment revenues 3 3 3 CO 2 1,009 1,038 1,219 Corporate and intersegment eliminations (68) (40) (45) Total consolidated revenues $ 16,610 $ 11,700 $ 13,209 Year Ended December 31, 2021 2020 2019 (In millions) Operating expenses(a) Natural Gas Pipelines $ 7,000 $ 3,457 $ 4,213 Products Pipelines 1,239 779 684 Terminals 793 762 888 CO 2 289 404 496 Corporate and intersegment eliminations (34) (4) (1) Total consolidated operating expenses $ 9,287 $ 5,398 $ 6,280 Year Ended December 31, 2021 2020 2019 (In millions) Other expense (income)(b) Natural Gas Pipelines $ 1,597 $ 1,009 $ (680) Products Pipelines — 21 — Terminals 32 (50) (342) CO 2 (8) 950 77 Kinder Morgan Canada — — 2 Corporate (4) — (2) Total consolidated other expense (income) $ 1,617 $ 1,930 $ (945) Year Ended December 31, 2021 2020 2019 (In millions) DD&A Natural Gas Pipelines $ 1,099 $ 1,062 $ 1,005 Products Pipelines 335 347 338 Terminals 440 438 494 CO 2 236 291 548 Corporate 25 26 26 Total consolidated DD&A $ 2,135 $ 2,164 $ 2,411 Year Ended December 31, 2021 2020 2019 (In millions) Earnings (loss) from equity investments and amortization of excess cost of equity investments, including loss on impairments of equity investments Natural Gas Pipelines $ 435 $ 551 $ (101) Products Pipelines 34 45 63 Terminals 15 22 23 CO 2 29 22 33 Total consolidated equity earnings $ 513 $ 640 $ 18 Year Ended December 31, 2021 2020 2019 (In millions) Other, net-income (expense) Natural Gas Pipelines $ 216 $ 11 $ 53 Products Pipelines 1 1 6 Terminals 3 13 (5) Corporate 62 31 21 Total consolidated other, net-income (expense) $ 282 $ 56 $ 75 Year Ended December 31, 2021 2020 2019 (In millions) Segment EBDA(c) Natural Gas Pipelines $ 3,815 $ 3,483 $ 4,661 Products Pipelines 1,064 977 1,225 Terminals 908 1,045 1,506 CO 2 760 (292) 681 Kinder Morgan Canada — — (2) Total Segment EBDA 6,547 5,213 8,071 DD&A (2,135) (2,164) (2,411) Amortization of excess cost of equity investments (78) (140) (83) General and administrative and corporate charges (623) (653) (611) Interest, net (1,492) (1,595) (1,801) Income tax expense (369) (481) (926) Total consolidated net income $ 1,850 $ 180 $ 2,239 Year Ended December 31, 2021 2020 2019 (In millions) Capital expenditures Natural Gas Pipelines $ 570 $ 945 $ 1,377 Products Pipelines 122 122 175 Terminals 332 433 347 CO 2 230 186 349 Corporate 27 21 22 Total consolidated capital expenditures $ 1,281 $ 1,707 $ 2,270 December 31, 2021 2020 (In millions) Investments Natural Gas Pipelines $ 6,887 $ 7,262 Products Pipelines 465 494 Terminals 137 136 CO 2 89 25 Total consolidated investments $ 7,578 $ 7,917 December 31, 2021 2020 (In millions) Other intangibles, net Natural Gas Pipelines $ 557 $ 1,418 Products Pipelines 868 961 Terminals 51 64 CO 2 202 10 Total consolidated other intangibles, net $ 1,678 $ 2,453 December 31, 2021 2020 (In millions) Assets Natural Gas Pipelines $ 47,746 $ 48,597 Products Pipelines 9,088 9,182 Terminals 8,513 8,639 CO 2 2,843 2,478 Corporate assets(d) 2,226 3,077 Total consolidated assets $ 70,416 $ 71,973 (a) Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes. (b) Includes loss (gain) on impairments and divestitures, net and other income, net. (c) Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss (gain) on impairments and divestitures, 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, 2021 2020 2019 (In millions) Revenues from external customers U.S. $ 16,479 $ 11,625 $ 12,833 Canada — — 300 Mexico and other foreign 131 75 76 Total consolidated revenues from external customers $ 16,610 $ 11,700 $ 13,209 December 31, 2021 2020 2019 (In millions) Long-term assets, excluding goodwill and other intangibles U.S. $ 44,916 $ 46,384 $ 46,709 Canada 1 1 1 Mexico and other foreign 78 81 82 Total consolidated long-lived assets $ 44,995 $ 46,466 $ 46,792

Leases (Notes)

Leases (Notes)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Leases: Lessee	17. Leases Following are components of our lease cost: Year Ended December 31, 2021 2020 2019 (In millions) Operating leases $ 60 $ 55 $ 136 Short-term and variable leases 109 101 92 Total lease cost(a) $ 169 $ 156 $ 228 (a) 2021, 2020 and 2019 amounts include $32 million, $25 million and $46 million of capitalized lease costs, respectively. Other information related to our operating leases are as follows: Year Ended December 31, 2021 2020 2019 (In millions, Operating cash flows from operating leases $ (137) $ (131) $ (182) Investing cash flows from operating leases (32) (25) (46) ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion 59 20 102 Amortization of ROU assets 47 46 75 Removal of ROU assets and liabilities associated with the KML and U.S. Cochin Sale (394) Weighted average remaining lease term 10.39 years 11.56 years 13.40 years Weighted average discount rate 3.95 % 4.27 % 4.31 % Amounts recognized in the accompanying consolidated balance sheet are as follows: December 31, Lease Activity Balance sheet location 2021 2020 (In millions) ROU assets Deferred charges and other assets $ 315 $ 303 Short-term lease liability Other current liabilities 45 40 Long-term lease liability Other long-term liabilities and deferred credits 270 263 Finance lease assets Property, plant and equipment, net 1 1 Finance lease liabilities Long-term debt—Outstanding 1 1 Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2021 are as follows: Year Commitment (In millions) 2022 $ 57 2023 51 2024 43 2025 36 2026 31 Thereafter 193 Total lease payments 411 Less: Interest (96) Present value of lease liabilities $ 315 Short-term lease costs are not material to us and are anticipated to be similar to the current year short-term lease expense outlined in this disclosure.

Litigation and Environmental (N

Litigation and Environmental (Notes)	12 Months Ended
	Dec. 31, 2021
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 contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed. SFPP FERC Proceedings The FERC approved the SFPP North, Oregon, and West Line Settlement in Docket No. IS22-100 (NOW Settlement) on January 14, 2022. The NOW Settlement will become final and effective on the date it is no longer subject to rehearing at the FERC, which is expected to be February 14, 2022. The amounts SFPP agreed to pay pursuant to the NOW Settlement were fully accrued on or before December 31, 2021. Together with the East Line Settlement (which the FERC approved previously on December 31, 2020 in Docket No. IS21-138), the NOW Settlement resolves all remaining disputes before the FERC (including Docket Nos. OR11-13, OR11-16, OR11-18, OR14-35, OR14-36, OR19-21, OR19-33, and OR19-37) and establishes a moratorium with settling shippers that prohibits the filing of a protest or complaint against SFPP’s FERC rates until February 1, 2025. Gulf LNG Facility Disputes On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that was not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy. Pursuant to its Notice of Arbitration, Eni USA sought declaratory and monetary relief based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement. On June 29, 2018, the arbitration tribunal delivered an Award that called for the termination of the agreement and Eni USA’s payment of compensation to GLNG. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019. 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 entered into by Eni S.p.A. in connection with the terminal use agreement. In response to the foregoing lawsuit, Eni S.p.A. filed counterclaims under the terminal use agreement and claims under a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing claims asserted by Eni S.p.A seek unspecified damages. 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 under the Guarantee Agreement. GLNG will file an interlocutory appeal of the decision. Pending resolution of GLNG’s appeal, the foregoing counterclaims and other claims asserted by Eni S.p.A under the terminal use agreement and parent direct agreement remain pending in the trial court. On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. Eni USA’s second arbitration sought to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the second arbitration. On cross-appeals from an Order and Final Judgment of the Court of Chancery, the Delaware Supreme Court ruled in favor of GLNG on November 17, 2020 and a permanent injunction was entered prohibiting Eni USA from pursuing the second arbitration, including the breach of contract and negligent misrepresentation claims therein. On October 4, 2021, the U.S. Supreme Court denied Eni USA’s petition for writ of certiorari. Consequently, Eni USA remains permanently enjoined from pursuing the second arbitration and the claims asserted therein. On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including Eni S.p.A., filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. ALSS also sought a declaration on substantially the same allegations asserted previously by Eni USA in arbitration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project gave rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also sought a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. On July 15, 2021, the arbitration tribunal delivered an Award on the merits of all claims submitted to the tribunal and denied all of ALSS’s claims with prejudice. On November 23, 2021, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award. Continental Resources, Inc. v. Hiland Partners Holdings, LLC On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging 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 North Dakota counties). CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of $276 million. We deny and are vigorously defending against these claims. Freeport LNG Winter Storm Litigation On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed suit 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. We believe that our declaration of force majeure is valid and are vigorously defending against these claims. 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. General As of December 31, 2021 and 2020, our total reserve for legal matters was $231 million and $273 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 CO 2 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, NGL, natural gas or CO 2 . 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 October 2023. 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, natural resource damage (NRD) claims in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the PHSS. Uranium Mines in Vicinity of Cameron, Arizona In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately 20 uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a PRP within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work pursuant to which EPNG is conducting environmental assessments of the mines and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines. The U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the U.S. The decision does not provide or establish the scope of a remedial plan with respect to the sites, nor does it establish the total cost for addressing the sites, all of which remain to be determined in subsequent proceedings and adversarial actions, if necessary, with the EPA. Until such issues are determined, we are unable to reasonably estimate the extent of our potential liability. Because costs associated with any remedial plan approved by the EPA 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. 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. EPEC entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. EPEC is part of a joint defense group of approximately 44 cooperating parties which is directing and funding the AOC work required by the EPA. We have established a reserve for the anticipated cost of compliance with these two AOCs. 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, are engaged in discussions with the EPA as a result thereof. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the lower eight mile ROD. On October 4, 2021, the EPA issued a ROD for the upper nine miles of the Site. The cleanup plan in the ROD is estimated to cost $440 million. No timeline for the cleanup has been established. Certain PRPs, including EPEC, are engaged in discussions with the EPA concerning the upper nine miles. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the upper nine mile ROD. Until the ongoing discussions with the EPA conclude, we are unable to reasonably estimate the extent of our potential liability. We do not anticipate that our share of the costs to resolve this matter, including the costs of any remediation of the Site, will 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 May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the U.S. District Court ordered the case to be remanded to the state district court for Plaquemines Parish. The defendants appealed that decision. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing. On August 5, 2021, the Fifth Circuit remanded the case to the U.S. District Court to determine whether there is federal officer jurisdiction. The case remains effectively stayed pending a ruling by the U.S. District Court on the federal officer issue. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue 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. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case. Louisiana Landowner Coastal Erosion Litigation Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including four cases against TGP, three cases against SNG, and one case against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The Plaintiffs allege the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. We will continue to vigorously defend these cases. 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 U.S. 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 agreed to plead no-contest to two misdemeanors and to pay approximately $2.5 million in fines, penalties, restitution, environmental improvement project funding, and for enforcement training in the State of California, and to be 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

Recent Accounting Pronoucements

Recent Accounting Pronoucements (Notes)	12 Months Ended
	Dec. 31, 2021
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 Accounting Standards Update (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 ASC 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. The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of Topic 848 to our financial statements. ASU No. 2020-06 On August 5, 2020, the FASB issued 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 ASC 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted EPS 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. ASU No. 2020-06 was effective January 1, 2022. We adopted ASU No. 2020-06 with no material impact to our financial statements. On July 19, 2021, the FASB issued ASU No. 2021-05, “ Leases (Topic 842); Lessors - Certain Leases with Variable Lease Payments

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.
Use of Estimates	Use of Estimates Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including those related to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.
Cash Equivalents and Restricted Deposits	Cash Equivalents and Restricted Deposits We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less. Amounts included in the restricted deposits in the accompanying consolidated financial statements represent a combination of restricted cash amounts required to be set aside by regulatory agencies to cover obligations for our captive insurance subsidiary and cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions.
Allowance for Credit Losses	Allowance for Credit Losses We evaluate our financial assets measured at amortized cost and off-balance sheet credit exposures for expected credit losses over the contractual term of the asset or exposure. We consider available information relevant to assessing the collectability of cash flows including the expected risk of credit loss even if that risk is remote. We measure expected credit losses on a collective (pool) basis when similar risk characteristics exist, and we reflect the expected credit losses on the amortized cost basis of the financial asset as of the reporting date. Our financial instruments primarily consist of our accounts receivable from customers, notes receivable from affiliates, and contingent liabilities such as proportional guarantees of debt obligations of certain equity investees. 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 includes
Inventories	Inventories Our inventories consist of materials and supplies and products such as NGL, crude oil, condensate, refined petroleum products, transmix and natural gas. We report products inventory at the lower of weighted-average cost or net realizable value. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.
Property, Plant and Equipment, net	Property, Plant and Equipment, net Capitalization, Depreciation and Depletion and Disposals We report property, plant and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in the period incurred. For the majority of our assets, we compute depreciation using either the straight-line method based on estimated economic lives or the composite depreciation method, which applies a single depreciation rate for a group of assets. We apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 0.092% to 33.3% excluding certain short-lived assets such as vehicles. For FERC-regulated entities, the FERC-accepted composite depreciation rate is applied to the total cost of the composite group until the net book value equals the salvage value. For other entities, depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract term for assets on leased or customer property and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When these assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. Subsequent events could 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. Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method, 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. We engage in enhanced recovery techniques in which CO 2 is injected into certain producing oil reservoirs. In some cases, the cost of the CO 2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. The cost of CO 2 associated with pressure maintenance operations for reservoir management is expensed when it is injected. When CO 2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our liquids and bulk terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A 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 sales proceeds received or the market value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset. For our pipeline system assets under the composite method of depreciation, we charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. Gains and losses are booked for FERC-approved operating unit sales and land sales and are recorded to income or expense accounts in accordance with regulatory accounting guidelines.
Asset Retirement Obligations	Asset Retirement Obligations We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. 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. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to 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. We have various other obligations throughout our businesses to remove facilities and equipment on rights-of-way and other leased facilities. We currently cannot reasonably estimate the fair value of these obligations because the associated assets have indeterminate lives. These assets include pipelines, certain processing plants and distribution facilities, and certain liquids and bulk terminal facilities. An asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.
Long-lived Asset Impairments	Long-lived Asset Impairments We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable. We recognize impairment losses when the estimated fair value is less than its carrying amount. In addition to our annual goodwill impairment test, 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 (step 2). We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on estimated future oil and gas production volumes. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on estimated future oil and gas production volumes. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment. Refer to Note 4 for further information.
Equity Method of Accounting and Basis Difference	Equity Method of Accounting and Basis Differences We use the equity method of accounting for investments which we do not control, but for which we have the ability to exercise significant influence. The carrying values of these investments are impacted by our share of investee income or loss, distributions, amortization or accretion of basis differences and other-than-temporary impairments. The difference between the carrying value of an investment and our share of the investment’s underlying equity in net assets is referred to as a basis difference. If the basis difference is assigned to depreciable or amortizable assets and liabilities, the basis difference is amortized or accreted as part of our share of investee earnings. To the extent that the basis difference relates to goodwill, referred to as equity method goodwill, the amount is not amortized. We evaluate our equity method investments for other-than-temporary impairment. When an other-than-temporary impairment is recognized the loss is recorded as a reduction in equity earnings.
Goodwill	Goodwill Goodwill is the cost of an acquisition of a business in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually and in interim periods if indicators of impairment exist. This test requires us to assign goodwill to an appropriate reporting unit, and an impairment exists and is recorded for the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. We evaluate goodwill for impairment on May 31 of each year. For purposes of our May 31, 2021 evaluation, we grouped our businesses into six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO 2 ; and (vi) Terminals. With our August 20, 2021 acquisition of Kinetrex Energy, we expanded our reporting units to include the Energy Transition Ventures reporting unit (see Note 3). We also evaluate goodwill for impairment to the extent events or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. 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	Other Intangibles Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, and technology-based assets. As of December 31, 2021 and 2020, the gross carrying amounts of these intangible assets was $3,036 million and $4,074 million, respectively, and the accumulated amortization was $1,358 million and $1,621 million, respectively, resulting in net carrying amounts of $1,678 million and $2,453 million, respectively. 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 effect of obsolescence, new technology, and competition.
Revenue Recognition	Revenue Recognition The majority of our revenues are accounted for under ASC 606, Revenue from Contracts with Customers ; however, to a limited extent, some revenues are accounted for under other guidance such as ASC 842, Leases or ASC 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 natural gas sales, NGL sales, crude oil sales, CO 2 sales, and transmix sales contracts, as described below. Generally, for the majority of these contracts: (i) each unit (Mcf, 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 primarily include transportation service, storage service, gathering and processing service, and terminaling service contracts, 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 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 CO 2 producing activities, such as those in our CO 2 business segment, are not accounted for as costs of sales.
Operations and Maintenance	Operations and Maintenance Operations and maintenance include costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our crude oil, gas and CO 2 producing activities included within operations and maintenance totaled $180 million, $319 million and $382 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Environmental Matters	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.
Lessee	We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one Our operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, were reflected based on contractual lease payments as outlined within the lease agreement and exclude CPI adjustments. 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, while for the remainder of our agreements we have elected the practical expedient to account for lease and non-lease components as a single lease component. 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 agreements are modified. Refer to Note 17 for further information.
Share-based Compensation	Share-based Compensation We recognize compensation expense ratably over the vesting period of the restricted stock award based on the grant-date fair value, which is determined based on the market price of our Class P common stock on the grant date, less estimated forfeitures. Forfeiture rates are estimated based on historical forfeitures under our restricted stock award plans. Upon vesting, the restricted stock award will be paid in shares of our Class P common stock.
Pensions and Other Postretirement Benefits	Pensions and Other Postretirement Benefits We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheets. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—net of income taxes in “Accumulated other comprehensive loss,” with the proportionate share associated with less than wholly owned consolidated subsidiaries allocated and included within “Noncontrolling interests,” or as a regulatory asset or liability for certain of our regulated operations, until they are amortized as a component of benefit expense.
Deferred Financing Costs	Deferred Financing Costs We capitalize financing costs incurred with new borrowings and amortize the costs over the contractual term of the related obligations.
Redeemable Noncontrolling Interest and Noncontrolling Interests	Redeemable Noncontrolling Interest Through December 14, 2021, redeemable noncontrolling interest represented the interest in one of our consolidated subsidiaries, ELC, that was not owned by us, 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 . On December 14, 2021, the ownership agreement was modified such that EIG’s interest is no longer contingently redeemable, and the balance was reclassified to “Noncontrolling Interests.” Net income attributable to redeemable noncontrolling interest was $58 million, $54 million and $11 million for the years ended December 31, 2021, 2020 and 2019, 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 income statements, the noncontrolling interest in the net income of our less than wholly owned consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net Income Attributable to Noncontrolling Interests.” In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”
Income Taxes	Income Taxes Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective 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 for the amount that is, more likely than not, to 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	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 hedging the interest rate risk associated with our debt obligations. We also enter into cross-currency swap agreements to manage our foreign currency risk 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 entire change in fair value of the derivative is recorded as an adjustment to the item being hedged. The gain or loss from any mismatch in the hedging relationship is recognized currently in earnings. When we designate a derivative contract as a net investment accounting hedge, the entire change in fair value of the derivative is reflected in the Foreign currency translation adjustments section of Other comprehensive (loss) income on our consolidated statements of comprehensive income. 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	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
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or returned to customers through the ratemaking process. In instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount. We include the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets.
Earnings per Share	Earnings per Share We calculate earnings per share using the two-class method. Earnings were allocated to Class P common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.

Acquisitions and Divestitures_2

Acquisitions and Divestitures (Policies)	12 Months Ended
	Dec. 31, 2021
Business Combination and Asset Acquisition [Abstract]
Business Combinations	For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of these items requires management’s judgment and the utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions.

Income Taxes (Policies)

Income Taxes (Policies)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits	Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority.  The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Schedule of Regulatory Assets and Liabilities Table [Table Text Block]	The following table summarizes our regulatory asset and liability balances as of December 31, 2021 and 2020: December 31, 2021 2020 (In millions) Current regulatory assets $ 66 $ 25 Non-current regulatory assets 220 231 Total regulatory assets(a) $ 286 $ 256 Current regulatory liabilities $ 32 $ 26 Non-current regulatory liabilities 163 169 Total regulatory liabilities(b) $ 195 $ 195 (a) Regulatory assets as of December 31, 2021 include (i) $121 million of unamortized losses on disposal of assets; (ii) $47 million income tax gross up on equity AFUDC; and (iii) $118 million of other assets including amounts related to fuel tracker arrangements. Approximately $155 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, 2021 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 $107 million of the $163 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 16 years, while the remaining $56 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, 2021 2020 2019 (In millions, except per share amounts) Net Income Available to Stockholders $ 1,784 $ 119 $ 2,190 Participating securities: Less: Net Income Allocated to Restricted stock awards(a) (14) (13) (12) Net Income Allocated to Class P Stockholders $ 1,770 $ 106 $ 2,178 Basic Weighted Average Shares Outstanding 2,266 2,263 2,264 Basic Earnings Per Share $ 0.78 $ 0.05 $ 0.96 (a) As of December 31, 2021, 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: Year Ended December 31, 2021 2020 2019 (In millions on a weighted average basis) Unvested restricted stock awards 13 13 13 Convertible trust preferred securities 3 3 3

Acquisitions and Divestitures_3

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2021
Business Combination and Asset Acquisition [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	As of December 31, 2021, our allocation of the purchase price for significant acquisitions completed during the year ended December 31, 2021 are detailed below: Assignment of Purchase Price Ref Date Acquisition Purchase price Current assets Property, plant & equipment Deferred charges & other Goodwill Current liabilities Long-term liabilities (In millions) (1) 8/21 Kinetrex $ 318 $ 18 $ 49 $ 262 $ 63 $ (6) $ (68) (2) 7/21 Stagecoach Gas Services LLC 1,258 53 1,187 24 — (6) —

Losses and Gains on Impairmen_2

Losses and Gains on Impairments, Divestitures and Other Write-downs (Tables)	12 Months Ended
	Dec. 31, 2021
Impairments [Abstract]
Impairment of Goodwill, Long-lived assets and equity investments [Table Text Block]	We recognized the following non-cash pre-tax losses (gains) on impairments and divestitures on assets and equity investments during the years ended December 31, 2021, 2020, and 2019: Year Ended December 31, 2021 2020 2019 (In millions) Natural Gas Pipelines Impairments of long-lived assets(a) $ 1,600 $ — $ 290 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 and other write-downs(e) (1) 10 (967) Impairment of equity investments(f) — — 650 Products Pipelines Impairments of long-lived assets — 21 — Terminals Impairments of long-lived assets 34 5 — Losses (gains) on divestitures of long-lived assets(g) 2 (54) (335) Gain on sale of equity investment interests — (10) — CO 2 Impairment of goodwill(b) — 600 — Impairments of long-lived assets(h) — 350 74 (Gains) losses on divestitures of long-lived assets (8) — 2 Other (gains) losses on divestitures of long-lived assets (3) — 1 Pre-tax losses on impairments, divestitures and other write-downs, net $ 1,535 $ 1,922 $ (285) (a) 2021 amount represents non-cash impairments associated with our South Texas gathering and processing assets. 2019 amount represents non-cash impairments associated with certain gathering and processing assets in Oklahoma and northern Texas. (b) 2020 amount represent non-cash goodwill impairments associated with our Natural Gas Pipelines Non-Regulated and CO 2 reporting units (see “— Impairments — Goodwill ” below). (c) See Note 3. (d) See “— Other Write-downs ” below for a further discussion. (e) 2019 amount includes a $957 million gain related to the sale of the Cochin Pipeline system. (f) 2019 amount represents the non-cash impairment of our investment in Ruby which is included in “Earnings from equity investments” on our accompanying consolidated statements of income for the year ended December 31, 2019. (g) 2020 amount includes a $55 million gain related to the sale of our Staten Island terminal. 2019 amount includes a $339 million gain related to the sale of KML. (h) 2020 and 2019 amounts represent impairments of oil and gas properties.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Schedule of Income Before Income Taxes	The components of “Income Before Income Taxes” are as follows: Year Ended December 31, 2021 2020 2019 (In millions) U.S. $ 2,217 $ 663 $ 2,482 Foreign 2 (2) 683 Total Income Before Income Taxes $ 2,219 $ 661 $ 3,165
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, 2021 2020 2019 (In millions) Current tax expense (benefit) Federal $ — $ (20) $ (2) State 11 9 10 Foreign(a) 3 147 201 Total 14 136 209 Deferred tax expense (benefit) Federal 334 440 682 State 21 49 66 Foreign(a) — (144) (31) Total 355 345 717 Total tax provision $ 369 $ 481 $ 926 (a) Our Canadian income tax (benefit) expense was $(1) million, $(4) million and $165 million for the years ended December 31, 2021, 2020 and 2019, respectively.
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, 2021 2020 2019 (In millions, except percentages) Federal income tax $ 466 21.0 % $ 139 21.0 % $ 665 21.0 % Increase (decrease) as a result of: Taxes on foreign earnings, net of federal benefit 2 0.1 % 2 0.3 % 139 4.4 % Net effects of noncontrolling interests (14) (0.6) % (13) (2.0) % (10) (0.3) % State income tax, net of federal benefit 50 2.2 % 52 7.9 % 68 2.1 % Dividend received deduction (46) (2.1) % (27) (4.1) % (39) (1.1) % Release of valuation allowance (38) (1.7) % — — % — — % Nondeductible goodwill — — % 336 50.8 % 108 3.4 % General business credit (36) (1.6) % — — % — — % Federal refunds — — % (20.0) (3.0) % — — % Other (15) (0.7) % 12 1.9 % (5) (0.2) % Total $ 369 16.6 % $ 481 72.8 % $ 926 29.3 %
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities result from the following: December 31, 2021 2020 (In millions) Deferred tax assets Employee benefits $ 154 $ 224 Net operating loss carryforwards 1,476 1,484 Tax credit carryforwards 301 257 Other 229 242 Valuation allowances (93) (138) Total deferred tax assets 2,067 2,069 Deferred tax liabilities Property, plant and equipment 166 414 Investments 1,769 1,084 Other 17 35 Total deferred tax liabilities 1,952 1,533 Net deferred tax assets $ 115 $ 536

Property, Plant and Equipment_2

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	As of December 31, 2021 and 2020, our property, plant and equipment, net consisted of the following: December 31, 2021 2020 (In millions) Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 20,254 $ 20,339 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 26,511 26,142 Other(a) 5,356 5,188 Accumulated depreciation, depletion and amortization (18,792) (17,818) 33,329 33,851 Land and land rights-of-way 1,718 1,403 Construction work in process 606 582 Property, plant and equipment, net $ 35,653 $ 35,836 (a) Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and miscellaneous property, plant and equipment.

Investments Investments (Tables

Investments Investments (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020, and our earnings (loss) from these respective investments for the years ended December 31, 2021, 2020 and 2019: Ownership Interest Equity Investments Earnings (Loss) from December 31, December 31, Year Ended December 31, 2021 2021 2020 2021 2020 2019 (In millions) Citrus Corporation 50% $ 1,768 $ 1,849 $ 151 $ 165 $ 157 SNG 50% 1,514 1,532 128 129 140 PHP 26.67% 647 632 63 — — Gulf Coast Express Pipeline LLC 34% 618 638 86 90 37 NGPL Holdings(a) 37.5% 604 803 94 116 81 MEP 50% 388 416 (17) (6) 15 Gulf LNG 50% 347 361 22 19 17 Products (SE) Pipe Line Corporation 51.17% 346 357 48 43 58 Utopia Holding LLC 50% 328 329 20 20 20 EagleHawk 25% 266 275 8 17 17 Watco Companies, LLC (b) 75 70 9 16 19 Cortez Pipeline Company 52.98% 28 25 29 24 35 FEP 50% — 16 — 70 59 Ruby(c) (d) — 1 (116) 15 (609) All others 649 613 66 62 55 Total investments $ 7,578 $ 7,917 $ 591 $ 780 $ 101 Amortization of excess cost $ (78) $ (140) $ (83) (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 December 31, 2021 and 2020 was $375 million and $500 million, respectively. For the years ended December 31, 2021, 2020 and 2019, we recognized $27 million, $34 million and $8 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, and the year ended December 31, 2019 loss includes a non-cash impairment charge of $650 million (pre-tax) related to our investment (see Note 4). (d) We operate Ruby and own the common interest in Ruby, the sole owner of the Ruby Pipeline natural gas transmission system. Pembina Pipeline Corporation (Pembina) owns the remaining interest in Ruby in the form of a convertible preferred interest. If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby.
Summarized financial info of significant equity investment [Table Text Block]	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 2021(a) 2020 2019 (In millions) Revenues $ 5,426 $ 5,076 $ 4,906 Costs and expenses 6,083 4,249 3,508 Net (loss) income $ (657) $ 827 $ 1,398 December 31, Balance Sheet 2021 2020 (In millions) Current assets $ 1,235 $ 1,013 Non-current assets 22,749 25,069 Current liabilities 1,778 1,787 Non-current liabilities 9,931 9,734 Partners’/owners’ equity 12,275 14,561

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	Changes in the amounts of our goodwill for each of the years ended December 31, 2021 and 2020 are summarized by reporting unit as follows: Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated CO 2 Products Pipelines Products Pipelines Terminals Terminals Energy Transition Ventures Total (In millions) Gross goodwill $ 15,892 $ 4,940 $ 1,528 $ 2,575 $ 221 $ 1,481 $ — $ 26,637 Accumulated impairment losses (1,643) (1,597) — (1,197) (70) (679) — (5,186) December 31, 2019 14,249 3,343 1,528 1,378 151 802 — 21,451 Impairments(a) — (1,000) (600) — — — — (1,600) December 31, 2020 14,249 2,343 928 1,378 151 802 — 19,851 Acquisition of Kinetrex — — — — — — 63 63 December 31, 2021 14,249 2,343 928 1,378 151 802 63 19,914 Gross goodwill 15,892 4,940 1,528 2,575 221 1,481 63 26,700 Accumulated impairment losses (1,643) (2,597) (600) (1,197) (70) (679) — (6,786) December 31, 2021 $ 14,249 $ 2,343 $ 928 $ 1,378 $ 151 $ 802 $ 63 $ 19,914 (a) See Note 4 “ Losses and Gains on Impairments, Divestitures and Other Write-downs—Goodwill Impairments ” for further information regarding our goodwill impairments.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Schedule of Debt	The following table provides detail on the principal amount of our outstanding debt balances: December 31, 2021 2020 (In millions) Credit facility and commercial paper borrowings(a) $ — $ — Corporate senior notes(b) 5.00%, due February 2021 — 750 3.50%, due March 2021(c) — 750 5.80%, due March 2021 — 400 5.00%, due October 2021 — 500 4.15%, due March 2022 375 375 1.50%, due March 2022(d) 853 917 3.95%, due September 2022 1,000 1,000 3.15%, due January 2023 1,000 1,000 Floating rate, due January 2023(e) 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(f) 500 — 6.70%, due February 2027 7 7 2.25%, due March 2027(d) 569 611 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 7.30%, due August 2033 500 500 5.30%, due December 2034 750 750 5.80%, due March 2035 500 500 7.75%, due October 2035 1 1 6.40%, due January 2036 36 36 6.50%, due February 2037 400 400 7.42%, due February 2037 47 47 6.95%, due January 2038 1,175 1,175 6.50%, due September 2039 600 600 6.55%, due September 2040 400 400 7.50%, due November 2040 375 375 6.375%, due March 2041 600 600 5.625%, due September 2041 375 375 5.00%, due August 2042 625 625 4.70%, due November 2042 475 475 5.00%, due March 2043 700 700 5.50%, due March 2044 750 750 5.40%, due September 2044 550 550 5.55%, due June 2045 1,750 1,750 5.05%, due February 2046 800 800 5.20%, due March 2048 750 750 3.25%, due August 2050 500 500 3.60%, due February 2051(f)(g) 1,050 — 7.45%, due March 2098 26 26 (continued) December 31, 2021 2020 TGP senior notes(b) 7.00%, due March 2027 300 300 7.00%, due October 2028 400 400 2.90%, due March 2030 1,000 1,000 8.375%, due June 2032 240 240 7.625%, due April 2037 300 300 EPNG senior notes(b) 8.625%, due January 2022(h) 260 260 7.50%, due November 2026 200 200 8.375%, due June 2032 300 300 CIG senior notes(b) 4.15%, due August 2026 375 375 6.85%, due June 2037 100 100 EPC Building, LLC, promissory note, 3.967%, due January 2021 through December 2035 364 380 Trust I Preferred Securities, 4.75%, due March 2028(i) 221 221 Other miscellaneous debt(j) 248 254 Total debt – KMI and Subsidiaries 32,418 33,396 Less: Current portion of debt(k) 2,646 2,558 Total long-term debt – KMI and Subsidiaries(l) $ 29,772 $ 30,838 (a) See “—Current portion of debt” below for further details regarding our outstanding credit facilities and commercial paper borrowings. (b) Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. (c) On January 4, 2021, we repaid our $750 million senior corporate notes. (d) Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2021 exchange rate of 1.1370 U.S. dollars per Euro and at the December 31, 2020 exchange rate of 1.2216 U.S. dollars per Euro. As of December 31, 2021 and 2020, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in increases to our debt balance of $38 million and $102 million, respectively, related to the 1.50% series and increases of $26 million and $68 million, respectively, related to the 2.25% series. The cumulative increase in debt due to the changes in exchange rates is offset by a corresponding change in the value of cross-currency swaps reflected in “Deferred charges and other assets” and “Other long-term liabilities and deferred credits” on our accompanying consolidated balance sheets. At the time of issuance, we entered into foreign currency contracts associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 14 “ Risk Management—Foreign Currency Risk Management ”). (e) As of December 31, 2021, we had outstanding, an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge. (f) On October 26, 2021, we issued in a registered offering two series of senior notes consisting of $500 million aggregate principal amount of 1.75% senior notes due 2026 and $300 million aggregate principal amount of 3.60% senior notes due 2051 as a reopening of the 3.60% series (see (g) following) and received combined net proceeds of $796 million. These notes are guaranteed through the cross guarantee agreement discussed below. (g) On February 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million These notes are guaranteed through the cross guarantee agreement discussed below. (h) On January 18, 2022, we repaid these senior notes. (i) Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2021, 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, 2021 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. (j) Includes finance lease obligations with monthly installments. The lease terms expire between 2026 and 2061. (k) Amounts include KMI outstanding credit facility borrowings, commercial paper borrowings and other debt maturing within 12 months. See “—Current Portion of Debt” below. (l) Excludes our “Debt fair value adjustments” which, as of December 31, 2021 and 2020, increased our combined debt balances by $902 million and $1,293 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, 2021 2020 (In millions) $3.5 billion credit facility due August 20, 2026(a) $ — $ — $500 million credit facility due November 16, 2023(a) — — Commercial paper notes(a) — — Current portion of senior notes 5.00%, due February 2021 — 750 3.50%, due March 2021 — 750 5.80%, due March 2021 — 400 5.00%, due October 2021 — 500 8.625%, due January 2022(b) 260 — 4.15%, due March 2022 375 — 1.50%, due March 2022(c) 853 — 3.95% due September 2022 1,000 — Trust I Preferred Securities, 4.75% due March 2028(d) 111 111 Current portion of other debt 47 47 Total current portion of debt $ 2,646 $ 2,558 (a) On August 20, 2021, we entered into an agreement for a new five-year credit facility and amended our existing credit facility discussed further in “—Credit Facilities and Restrictive Covenants” following. (b) On January 18, 2022, we repaid these senior notes. (c) Denominated in Euros. (d) Reflects the portion of cash consideration payable if all the outstanding securities as of the end of the reporting period were converted by the holders.
Schedule of Maturities of Long-term Debt	The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2021, are summarized as follows: Year Total (In millions) 2022 $ 2,646 2023 3,250 2024 1,925 2025 1,567 2026 1,102 Thereafter 21,928 Total $ 32,418
Schedule of Debt Fair Value Adjustments	The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets: December 31, 2021 2020 (In millions) Purchase accounting debt fair value adjustments $ 498 $ 546 Carrying value adjustment to hedged debt 376 702 Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a) 223 240 Unamortized debt discounts, net (71) (76) Unamortized debt issuance costs (124) (119) Total debt fair value adjustments $ 902 $ 1,293
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, 2021 December 31, 2020 Carrying Estimated Carrying Estimated (In millions) Total debt $ 33,320 $ 37,775 $ 34,689 $ 39,622

Share-based Compensation and _2

Share-based Compensation and Employee Benefits (Tables)	12 Months Ended
	Dec. 31, 2021
Employee Benefit and Share-based Payment Arrangement, Noncash Expense [Abstract]
Summary of Activity and Related Balances of Restricted Stock Awards	The following table sets forth a summary of activity and related balances of our restricted stock awards excluding that issued to non-employee directors: Shares Weighted Average Grant Date Fair Value per Share (In thousands, except per share amounts) Outstanding at December 31, 2020 12,682 $ 17.79 Granted 4,705 17.44 Vested (4,463) 17.89 Forfeited (307) 17.47 Outstanding at December 31, 2021 12,617 $ 17.63
Schedule of Grant Date Fair Value, Awards Vested and Future Vesting of Restricted Stock Awards	The following table sets forth additional information related to our restricted stock awards excluding that issued to non-employee directors: Year Ended December 31, 2021 2020 2019 (In millions, except per share amounts) Weighted average grant date fair value per share $ 17.44 $ 15.10 $ 20.46 Intrinsic value of awards vested during the year 77 59 87 Restricted stock awards made to employees have vesting periods ranging from 1 year up to 10 years. Following is a summary of the future vesting of our outstanding restricted stock awards: Year Vesting of Restricted Shares (In thousands) 2022 2,832 2023 5,552 2024 3,662 2025 513 2026 58 Total Outstanding 12,617
Schedule of Benefit Obligation, Plan Assets and Funded Status	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, 2021 and 2020: Pension Benefits OPEB 2021 2020 2021 2020 (In millions) Change in benefit obligation: Benefit obligation at beginning of period $ 2,844 $ 2,696 $ 299 $ 333 Service cost 53 59 1 1 Interest cost 45 71 4 8 Actuarial (gain) loss (80) 198 (21) (17) Benefits paid (204) (180) (28) (29) Participant contributions — — 1 2 Medicare Part D subsidy receipts — — 1 1 Benefit obligation at end of period 2,658 2,844 257 299 Change in plan assets: Fair value of plan assets at beginning of period 2,199 2,076 361 333 Actual return on plan assets 180 178 40 47 Employer contributions 56 125 7 7 Participant contributions — — 1 2 Medicare Part D subsidy receipts — — 1 1 Benefits paid (204) (180) (28) (29) Fair value of plan assets at end of period 2,231 2,199 382 361 Funded status - net (liability) asset at December 31, $ (427) $ (645) $ 125 $ 62
Components of Funded Status	Components of Funded Status . The following table details the amounts recognized in our balance sheets at December 31, 2021 and 2020 related to our pension and OPEB plans: Pension Benefits OPEB 2021 2020 2021 2020 (In millions) Non-current benefit asset(a) $ — $ — $ 302 $ 269 Current benefit liability — — (18) (19) Non-current benefit liability (427) (645) (159) (188) Funded status - net (liability) asset at December 31, $ (427) $ (645) $ 125 $ 62 (a) 2021 and 2020 OPEB amounts include $54 million and $46 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.
Schedule of Components of Accumulated Other Comprehensive (Loss) Income	Components of Accumulated Other Comprehensive (Loss) Income . The following table details the amounts of pre-tax accumulated other comprehensive (loss) income at December 31, 2021 and 2020 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets: Pension Benefits OPEB 2021 2020 2021 2020 (In millions) Unrecognized net actuarial (loss) gain $ (495) $ (674) $ 176 $ 153 Unrecognized prior service (cost) credit (2) (2) 6 9 Accumulated other comprehensive (loss) income $ (497) $ (676) $ 182 $ 162
Fair Value of Pension and OPEB Assets by Level of Assets	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, 2021 and 2020: Pension Assets 2021 2020 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Cash $ 11 $ — $ 11 $ — $ — $ — Short-term investment funds — 25 25 — 77 77 Equities(a) 153 — 153 249 — 249 Fixed income securities(b) — 566 566 — 425 425 Derivatives — — — — 11 11 Subtotal $ 164 $ 591 755 $ 249 $ 513 762 Measured at NAV(c) Common/collective trusts(d) 1,389 1,184 Private investment funds(e) 39 208 Private limited partnerships(f) 48 45 Subtotal 1,476 1,437 Total plan assets fair value $ 2,231 $ 2,199 (a) Plan assets include $97 million and $83 million of KMI Class P common stock for 2021 and 2020, respectively. (b) Plan assets include $1 million of KMI debt securities for 2020. (c) Plan assets which used NAV as a practical expedient to measure fair value. (d) Common/collective trust funds were invested in approximately 83% equities and 17% fixed income securities in 2021 and 71% equities and 29% fixed income securities in 2020. (e) Private investment funds were invested in 100% fixed income securities in 2021 and approximately 29% equities and 71% fixed income securities in 2020. (f) Includes assets invested in real estate, venture and buyout funds. OPEB Assets 2021 2020 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Short-term investment funds $ — $ 3 $ 3 $ — $ 5 $ 5 Measured at NAV(a) Common/collective trusts(b) 379 356 Total plan assets fair value $ 382 $ 361 (a) Plan assets which used NAV as a practical expedient to measure fair value.
Schedule of Expected Payment of Future Benefits and Employer Contributions	Expected Payment of Future Benefits and Employer Contributions . As of December 31, 2021, we expect to make the following benefit payments under our plans: Fiscal year Pension Benefits OPEB(a) (In millions) 2022 $ 212 $ 28 2023 210 26 2024 204 24 2025 199 22 2026 194 21 2027 - 2031 864 84 (a) Includes a reduction of approximately $1 million in each of the years 2022 through 2026 and approximately $4 million in aggregate for the period 2027 - 2031 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
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 and net benefit costs of our pension and OPEB plans for 2021, 2020 and 2019: Pension Benefits OPEB 2021 2020 2019 2021 2020 2019 (In millions) Assumptions related to benefit obligations: Discount rate 2.74 % 2.27 % 3.17 % 2.56 % 2.08 % 3.03 % 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 Assumptions related to benefit costs: Discount rate for benefit obligations 2.27 % 3.17 % 4.26 % 2.08 % 3.03 % 4.16 % Discount rate for interest on benefit obligations 1.60 % 2.71 % 3.89 % 1.46 % 2.63 % 3.83 % Discount rate for service cost 2.33 % 3.24 % 4.28 % 2.70 % 3.48 % 4.51 % Discount rate for interest on service cost 1.70 % 2.80 % 3.93 % 2.63 % 3.39 % 4.46 % Expected return on plan assets(a) 6.25 % 6.75 % 7.25 % 5.75 % 6.50 % 6.50 % Rate of compensation increase 3.50 % 3.50 % 3.50 % n/a n/a n/a Interest crediting rate 2.57 % 3.71 % 3.90 % n/a n/a n/a (a) 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 (UBIT), we utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on UBIT rates of 27% for each of 2021, 2020 and 2019.
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 2021 2020 2019 2021 2020 2019 (In millions) Components of net benefit cost (credit): Service cost $ 53 $ 59 $ 53 $ 1 $ 1 $ 1 Interest cost 45 71 96 4 8 12 Expected return on assets (133) (137) (129) (16) (16) (16) Amortization of prior service cost (credit) — 1 — (5) (5) (4) Amortization of net actuarial loss (gain) 52 40 54 (17) (13) (11) Net benefit cost (credit) 17 34 74 (33) (25) (18) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net (gain) loss arising during period (127) 157 (42) (40) (43) (17) Amortization or settlement recognition of net actuarial (loss) gain (52) (40) (54) 17 13 11 Amortization of prior service (cost) credit — (1) — 3 3 2 Total recognized in total other comprehensive (income) loss(a) (179) 116 (96) (20) (27) (4) Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ (162) $ 150 $ (22) $ (53) $ (52) $ (22) (a) Excludes $3 million and $2 million for the years ended December 31, 2021 and 2020, respectively, associated with other plans.

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2021
Stockholders' Equity Note [Abstract]
Schedule of Dividends Paid and Payable	The following table provides information about our per share dividends: Year Ended December 31, 2021 2020 2019 Per share cash dividend declared for the period $ 1.08 $ 1.05 $ 1.00 Per share cash dividend paid in the period 1.0725 1.0375 0.95
Schedule of Changes in Accumulated Other Comprehensive Income (Loss)	Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows: Net unrealized Foreign Pension and Total (In millions) Balance at December 31, 2018 $ 164 $ (91) $ (403) $ (330) Other comprehensive (loss) gain before reclassifications (177) — 77 (100) Losses reclassified from accumulated other comprehensive loss(a) 6 91 — 97 Net current-period change in accumulated other comprehensive income (loss) (171) 91 77 (3) 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) (a) Amount for foreign currency translation adjustments reflect the deferred losses recognized in income during the year ended December 31, 2019 related to the sale of KML.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2021
Related Party Transactions [Abstract]
Schedule of Related Party Transactions [Table Text Block]	The following tables summarize our affiliate balance sheet balances and income statement activity, other than amounts reported within our “Investments” balances and “Earnings from equity investments” activity: December 31, 2021 2020 (In millions) Balance sheet location Accounts receivable $ 38 $ 41 Other current assets 4 6 Deferred charges and other assets — 109 $ 42 $ 156 Current portion of debt $ 6 $ 6 Accounts payable 21 25 Other current liabilities 4 4 Long-term debt 148 154 Other long-term liabilities and deferred credits 56 48 $ 235 $ 237 Year Ended December 31, 2021 2020 2019 (In millions) Income statement location Revenues $ 164 $ 206 $ 269 Operating Costs, Expenses and Other Costs of sales $ 145 $ 116 $ 75 Other operating expenses 52 119 132

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	As of December 31, 2021, 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 (6.5) MMBbl Natural gas fixed price (54.2) Bcf Natural gas basis (43.9) Bcf NGL fixed price (0.7) MMBbl Derivatives not designated as hedging contracts Crude oil fixed price (1.0) MMBbl Crude oil basis (9.1) MMBbl Natural gas fixed price (13.2) Bcf Natural gas basis (38.5) Bcf NGL fixed price (1.4) MMBbl
Schedule of Interest Rate Derivatives [Table Text Block]	The following table summarizes our outstanding interest rate contracts as of December 31, 2021: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments Fixed-to-variable interest rate contracts(a) $ 7,100 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(b) 5,100 Mark-to-Market December 2022 (a) The principal amount of hedged senior notes consisted of $750 million included in “Current portion of debt” and $6,350 million included in “Long-term debt” on our accompanying consolidated balance sheet. (b) Of this notional amount, $4,860 million became effective January 4, 2022.
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, 2021: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments EUR-to-USD cross currency swap contracts(a) $ 1,358 Cash flow hedge March 2027 (a) These s waps eliminate the foreign currency risk associated with all of 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 Derivatives December 31, December 31, 2021 2020 2021 2020 Location Fair value Fair value (In millions) Derivatives designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 61 $ 42 $ (141) $ (33) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 3 33 (94) (8) Subtotal 64 75 (235) (41) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 101 119 (3) (3) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 284 575 (15) (7) Subtotal 385 694 (18) (10) Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) 35 — (3) (6) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 6 138 — — Subtotal 41 138 (3) (6) Total 490 907 (256) (57) Derivatives not designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 11 24 (31) (21) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 1 — (6) — Subtotal 12 24 (37) (21) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 12 — — — Total 24 24 (37) (21) Total derivatives $ 514 $ 931 $ (293) $ (78)
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(b) Net amount (In millions) As of December 31, 2021 Energy commodity derivative contracts(a) $ 56 $ 20 $ — $ 76 $ (53) $ (20) $ 3 Interest rate contracts — 397 — 397 (9) — 388 Foreign currency contracts — 41 — 41 (3) — 38 As of December 31, 2020 Energy commodity derivative contracts(a) $ 6 $ 93 $ — $ 99 $ (35) $ — $ 64 Interest rate contracts — 694 — 694 (2) — 692 Foreign currency contracts — 138 — 138 (6) — 132 Balance sheet liability Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral posted(b) Net amount (In millions) As of December 31, 2021 Energy commodity derivative contracts(a) $ (15) $ (257) $ — $ (272) $ 53 $ — $ (219) Interest rate contracts — (18) — (18) 9 — (9) Foreign currency contracts — (3) — (3) 3 — — As of December 31, 2020 Energy commodity derivative contracts(a) (7) (56) — (63) 35 (8) (36) Interest rate contracts — (10) — (10) 2 — (8) Foreign currency contracts — (6) — (6) 6 — — (a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps. (b) 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.
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, 2021 2020 2019 (In millions) Interest rate contracts Interest, net $ (322) $ 335 $ 340 Hedged fixed rate debt(a) Interest, net $ 326 $ (343) $ (353) (a) As of December 31, 2021, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $376 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, 2021 2020 2019 2021 2020 2019 (In millions) (In millions) Energy commodity derivative contracts $ (475) $ 240 $ (168) Revenues—Commodity sales $ (271) $ 222 $ 16 Costs of sales 20 (14) 5 Interest rate contracts(c) 5 (8) (1) Earnings from equity investments(c) — — 2 Foreign currency contracts (93) 92 (60) Other, net (105) 125 (31) Total $ (563) $ 324 $ (229) Total $ (356) $ 333 $ (8) (a) We expect to reclassify an approximately $58 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2021 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, 2021, 2020 and 2019, we recognized gains of $41 million, no gains and gains of $12 million, respectively, associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred). (c) Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss). Derivatives in net investment hedging relationships Gain/(loss) recognized in OCI on derivative Location Gain/(loss) reclassified from Accumulated OCI into income(a) Year Ended Year Ended December 31, December 31, 2021 2020 2019 2021 2020 2019 (In millions) (In millions) Foreign currency contracts $ — $ — $ (8) Loss (gain) on impairments and divestitures, net $ — $ — $ 83 Total $ — $ — $ (8) Total $ — $ — $ 83 (a) During the year ended December 31, 2019, we recognized an $83 million gain related to the KML and U.S. Cochin Sale. See Note 3. Derivatives not designated as accounting hedges Location Gain/(Loss) recognized in income on derivatives Year Ended December 31, 2021 2020 2019 (In millions) Energy commodity derivative contracts Revenues—Commodity sales $ (652) $ (1) $ 33 Costs of sales 152 25 (7) Earnings from equity investments(b) (5) — 3 Interest rate contracts Interest, net 12 — — Total(a) $ (493) $ 24 $ 29 (a) The years ended December 31, 2021, 2020 and 2019 include approximate losses of $479 million, $11 million and $8 million, respectively, associated with natural gas, crude and NGL derivative contract settlements. (b) Amounts represent our share of an equity investee’s income (loss).

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,402 $ 259 $ 751 $ 1 $ (2) $ 4,411 Fee-based services 746 949 375 45 (1) 2,114 Total services 4,148 1,208 1,126 46 (3) 6,525 Commodity sales Natural gas sales 6,463 — — 32 (15) 6,480 Product sales 1,260 845 24 1,070 (50) 3,149 Total commodity sales 7,723 845 24 1,102 (65) 9,629 Total revenues from contracts with customers 11,871 2,053 1,150 1,148 (68) 16,154 Other revenues(c) Leasing services(d) 473 172 565 56 — 1,266 Derivatives adjustments on commodity sales (700) (1) — (222) — (923) Other 65 21 — 27 — 113 Total other revenues (162) 192 565 (139) — 456 Total revenues $ 11,709 $ 2,245 $ 1,715 $ 1,009 $ (68) $ 16,610 Year Ended December 31, 2020 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,345 $ 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 Year Ended December 31, 2019 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,549 $ 319 $ 1,012 $ 1 $ (4) $ 4,877 Fee-based services 780 1,016 560 60 — 2,416 Total services 4,329 1,335 1,572 61 (4) 7,293 Commodity sales Natural gas sales 2,603 — — 1 (9) 2,595 Product sales 805 289 20 1,111 (33) 2,192 Total commodity sales 3,408 289 20 1,112 (42) 4,787 Total revenues from contracts with customers 7,737 1,624 1,592 1,173 (46) 12,080 Other revenues(c) Leasing services(d) 273 182 442 54 — 951 Derivatives adjustments on commodity sales 70 — — (21) — 49 Other 90 25 — 13 1 129 Total other revenues 433 207 442 46 1 1,129 Total revenues $ 8,170 $ 1,831 $ 2,034 $ 1,219 $ (45) $ 13,209 (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, 2021 that we will invoice or transfer from contract liabilities and recognize in future periods: Year Estimated Revenue (In millions) 2022 $ 4,324 2023 3,418 2024 2,857 2025 2,382 2026 2,108 Thereafter 12,618 Total $ 27,707

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Financial information by segment follows: Year Ended December 31, 2021 2020 2019 (In millions) Revenues Natural Gas Pipelines Revenues from external customers $ 11,644 $ 7,222 $ 8,128 Intersegment revenues 65 37 42 Products Pipelines 2,245 1,721 1,831 Terminals Revenues from external customers 1,712 1,719 2,031 Intersegment revenues 3 3 3 CO 2 1,009 1,038 1,219 Corporate and intersegment eliminations (68) (40) (45) Total consolidated revenues $ 16,610 $ 11,700 $ 13,209 Year Ended December 31, 2021 2020 2019 (In millions) Operating expenses(a) Natural Gas Pipelines $ 7,000 $ 3,457 $ 4,213 Products Pipelines 1,239 779 684 Terminals 793 762 888 CO 2 289 404 496 Corporate and intersegment eliminations (34) (4) (1) Total consolidated operating expenses $ 9,287 $ 5,398 $ 6,280 Year Ended December 31, 2021 2020 2019 (In millions) Other expense (income)(b) Natural Gas Pipelines $ 1,597 $ 1,009 $ (680) Products Pipelines — 21 — Terminals 32 (50) (342) CO 2 (8) 950 77 Kinder Morgan Canada — — 2 Corporate (4) — (2) Total consolidated other expense (income) $ 1,617 $ 1,930 $ (945) Year Ended December 31, 2021 2020 2019 (In millions) DD&A Natural Gas Pipelines $ 1,099 $ 1,062 $ 1,005 Products Pipelines 335 347 338 Terminals 440 438 494 CO 2 236 291 548 Corporate 25 26 26 Total consolidated DD&A $ 2,135 $ 2,164 $ 2,411 Year Ended December 31, 2021 2020 2019 (In millions) Earnings (loss) from equity investments and amortization of excess cost of equity investments, including loss on impairments of equity investments Natural Gas Pipelines $ 435 $ 551 $ (101) Products Pipelines 34 45 63 Terminals 15 22 23 CO 2 29 22 33 Total consolidated equity earnings $ 513 $ 640 $ 18 Year Ended December 31, 2021 2020 2019 (In millions) Other, net-income (expense) Natural Gas Pipelines $ 216 $ 11 $ 53 Products Pipelines 1 1 6 Terminals 3 13 (5) Corporate 62 31 21 Total consolidated other, net-income (expense) $ 282 $ 56 $ 75 Year Ended December 31, 2021 2020 2019 (In millions) Segment EBDA(c) Natural Gas Pipelines $ 3,815 $ 3,483 $ 4,661 Products Pipelines 1,064 977 1,225 Terminals 908 1,045 1,506 CO 2 760 (292) 681 Kinder Morgan Canada — — (2) Total Segment EBDA 6,547 5,213 8,071 DD&A (2,135) (2,164) (2,411) Amortization of excess cost of equity investments (78) (140) (83) General and administrative and corporate charges (623) (653) (611) Interest, net (1,492) (1,595) (1,801) Income tax expense (369) (481) (926) Total consolidated net income $ 1,850 $ 180 $ 2,239 Year Ended December 31, 2021 2020 2019 (In millions) Capital expenditures Natural Gas Pipelines $ 570 $ 945 $ 1,377 Products Pipelines 122 122 175 Terminals 332 433 347 CO 2 230 186 349 Corporate 27 21 22 Total consolidated capital expenditures $ 1,281 $ 1,707 $ 2,270 December 31, 2021 2020 (In millions) Investments Natural Gas Pipelines $ 6,887 $ 7,262 Products Pipelines 465 494 Terminals 137 136 CO 2 89 25 Total consolidated investments $ 7,578 $ 7,917 December 31, 2021 2020 (In millions) Other intangibles, net Natural Gas Pipelines $ 557 $ 1,418 Products Pipelines 868 961 Terminals 51 64 CO 2 202 10 Total consolidated other intangibles, net $ 1,678 $ 2,453 December 31, 2021 2020 (In millions) Assets Natural Gas Pipelines $ 47,746 $ 48,597 Products Pipelines 9,088 9,182 Terminals 8,513 8,639 CO 2 2,843 2,478 Corporate assets(d) 2,226 3,077 Total consolidated assets $ 70,416 $ 71,973 (a) Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes. (b) Includes loss (gain) on impairments and divestitures, net and other income, net. (c) Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss (gain) on impairments and divestitures, 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, 2021 2020 2019 (In millions) Revenues from external customers U.S. $ 16,479 $ 11,625 $ 12,833 Canada — — 300 Mexico and other foreign 131 75 76 Total consolidated revenues from external customers $ 16,610 $ 11,700 $ 13,209 December 31, 2021 2020 2019 (In millions) Long-term assets, excluding goodwill and other intangibles U.S. $ 44,916 $ 46,384 $ 46,709 Canada 1 1 1 Mexico and other foreign 78 81 82 Total consolidated long-lived assets $ 44,995 $ 46,466 $ 46,792

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Lease, Cost [Table Text Block]	Following are components of our lease cost: Year Ended December 31, 2021 2020 2019 (In millions) Operating leases $ 60 $ 55 $ 136 Short-term and variable leases 109 101 92 Total lease cost(a) $ 169 $ 156 $ 228 (a) 2021, 2020 and 2019 amounts include $32 million, $25 million and $46 million of capitalized lease costs, respectively. Other information related to our operating leases are as follows: Year Ended December 31, 2021 2020 2019 (In millions, Operating cash flows from operating leases $ (137) $ (131) $ (182) Investing cash flows from operating leases (32) (25) (46) ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion 59 20 102 Amortization of ROU assets 47 46 75 Removal of ROU assets and liabilities associated with the KML and U.S. Cochin Sale (394) Weighted average remaining lease term 10.39 years 11.56 years 13.40 years Weighted average discount rate 3.95 % 4.27 % 4.31 % Amounts recognized in the accompanying consolidated balance sheet are as follows: December 31, Lease Activity Balance sheet location 2021 2020 (In millions) ROU assets Deferred charges and other assets $ 315 $ 303 Short-term lease liability Other current liabilities 45 40 Long-term lease liability Other long-term liabilities and deferred credits 270 263 Finance lease assets Property, plant and equipment, net 1 1 Finance lease liabilities Long-term debt—Outstanding 1 1
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2021 are as follows: Year Commitment (In millions) 2022 $ 57 2023 51 2024 43 2025 36 2026 31 Thereafter 193 Total lease payments 411 Less: Interest (96) Present value of lease liabilities $ 315

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Accounts Receivable, Net (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Allowance for Credit Loss	$ 1	$ 26

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Composite depreciation rate, low	0.092%
Composite depreciation rate, high	33.30%

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Goodwill (Details)	May 31, 2021segment
Accounting Policies [Abstract]
Number of Reporting Units	6

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Other Intangibles (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Intangible Assets, Gross (Excluding Goodwill)	$ 3,036	$ 4,074
Finite-Lived Intangible Assets, Accumulated Amortization	1,358	1,621
Intangible Assets, Net (Excluding Goodwill)	1,678	2,453
Amortization of Intangible Assets	237	$ 212	$ 214
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	242
Finite-Lived Intangible Assets, Amortization Expense, Year Two	177
Finite-Lived Intangible Assets, Amortization Expense, Year Three	153
Finite-Lived Intangible Assets, Amortization Expense, Year Four	147
Finite-Lived Intangible Assets, Amortization Expense, Year Five	$ 144
Weighted average amortization period, customer contracts	10 years

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Operations and Maintenance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 180	$ 319	$ 382

Summary of Significant Accoun_9

Summary of Significant Accounting Policies - Leases (Details)	Dec. 31, 2021
Minimum
Lessee, Operating Lease, Remaining Lease Term	1 year
Maximum
Lessee, Operating Lease, Remaining Lease Term	49 years

Summary of Significant Accou_10

Summary of Significant Accounting Policies - Redeemable Noncontrolling Interest (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Elba Liquefaction Company
Entity Information [Line Items]
Net income (loss) attributable to redeemable noncontrolling interest	$ 58	$ 54	$ 11

Summary of Significant Accou_11

Summary of Significant Accounting Policies - Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Regulatory Assets and Liabilities [Line Items]
Current regulatory assets	$ 66	$ 25
Non-current regulatory assets	220	231
Total regulatory assets(a)	286	256
Current regulatory liabilities	32	26
Non-current regulatory liabilities	163	169
Total regulatory liabilities(b)	195	$ 195
Regulatory assets recoverable without earning a return	$ 155
Regulatory assets, weighted average remaining recovery period	10 years
Remaining Amounts of Regulatory Liabilities Subject to Crediting Period	$ 107
Remaining Recovery Period of Regulatory Liabilities Subject to Defined Crediting Period	16 years
Remaining Amounts of Regulatory Liabilities Not Subject to Defined Crediting Period	$ 56
Loss on Disposal of Assets
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	121
Income Tax Gross Up on AFUDC Equity
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	47
Other Regulatory Assets (Liabilities)
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	$ 118

Summary of Significant Accou_12

Summary of Significant Accounting Policies - Earnings per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Stockholders	$ 1,784	$ 119	$ 2,190
Less: Net Income Allocated to Restricted stock awards	$ (14)	$ (13)	$ (12)
Basic Weighted Average Shares Outstanding	2,266	2,263	2,264
Basic Earnings Per Share	$ 0.78	$ 0.05	$ 0.96
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	$ 1,770	$ 106	$ 2,178
Class P | Unvested restricted stock awards
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Awards outstanding	13

Acquisitions and Divestitures -

Acquisitions and Divestitures - Schedule of Recognized Identified Assets and Liabilities Assumed (Details) $ in Millions	Aug. 20, 2021USD ($)facilities	Nov. 24, 2021USD ($)	Dec. 31, 2021USD ($)	Jul. 09, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Business Acquisition [Line Items]
Goodwill			$ 19,914		$ 19,851	$ 21,451
Equity Method Investments			$ 7,578		$ 7,917
Weighted average amortization period, customer relationship			10 years
Kinetrex Energy
Business Acquisition [Line Items]
Purchase price	$ 318
Current assets	18
Property, plant, & equipment	49
Deferred charges & other	262
Goodwill	63
Current liabilities	(6)
Long-term liabilities	(68)
Payments to acquire businesses	318
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
Deferred charges & other				24
Goodwill				0
Current liabilities				(6)
Long-term liabilities				$ 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_4

Acquisitions and Divestitures - Sale of an interest in NGPL Holdings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Mar. 08, 2021
Schedule of Equity Method Investments [Line Items]
Gain on sale of interest in equity investment (Note 3)	$ (206)	$ 0	$ 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	500		$ 500
Interest rate, stated percentage	6.75%			6.75%
NGPL Holdings, LLC | Natural Gas Pipelines
Schedule of Equity Method Investments [Line Items]
Gain on sale of interest in equity investment (Note 3)	$ (206)	$ 0	$ 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%

Acquisitions and Divestitures_5

Acquisitions and Divestitures - Sale of U.S. Portion of Cochin Pipeline System and KML (Details) $ in Millions	Jan. 09, 2020USD ($)	Dec. 16, 2019USD ($)transactionsshares	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Jan. 03, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of transactions closed on | transactions		2
Loss (gain) on divestitures and impairments, net			$ 1,624	$ 1,932	$ (942)
Proceeds from sale of marketable securities	$ 907
Proceeds from sale of marketable securities, after taxes	$ 764
KML and U.S. Portion of Cochin Pipeline System
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss (gain) on divestitures and impairments, net					$ (1,296)
U.S. Portion of Cochin Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration		$ 1,553
Kinder Morgan Canada Limited
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration		$ 892
Shares of acquirer received, per share of subsidiary held | shares		0.3068
Aggregate number of shares received | shares		25,000,000
Kinder Morgan Canada Limited
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage		70.00%				70.00%

Acquisitions and Divestitures_6

Acquisitions and Divestitures - Sale of Trans Mountain Pipeline System and ts Expansion Project (Details) $ in Millions, $ in Billions	Jan. 03, 2019USD ($)	Jan. 03, 2019CAD ($)	Feb. 28, 2019USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 16, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments to noncontrolling interests	$ 900	$ 1.2		$ 0	$ 0	$ 879
Repayments of commercial paper	400
Repayments of debt				$ 6,831	$ 3,996	$ 11,224
Kinder Morgan, Inc.
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments	$ 1,900	$ 2.5
Repayments of debt			$ 1,300
Kinder Morgan Canada Limited
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage	70.00%	70.00%					70.00%

Losses and Gains on Impairmen_3

Losses and Gains on Impairments, Divestitures and Other Write-downs _ Impairment Table (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Pre-tax losses on impairments, divestitures and other write-downs, net		$ 1,535	$ 1,922	$ (285)
(Gain) Loss on Sale of Assets		1,624	1,932	(942)
Impairment losses on long-lived assets and equity investments				1,014
Impairments of long-lived assets		1,634	376
Impairment of goodwill			1,600
Gain on sale of interest in equity investment		(206)	0	0
Other
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gains) losses on divestitures of long-lived assets		(3)	0	1
KML and U.S. Portion of Cochin Pipeline System
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gain) Loss on Sale of Assets				(1,296)
Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of long-lived assets		1,600	0	290
Impairment of goodwill		0	1,000	0
(Gains) losses on divestitures of long-lived assets		(1)	10	(967)
Impairments of equity investments		0	0	650
Natural Gas Pipelines | KML and U.S. Portion of Cochin Pipeline System
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gains) losses on divestitures of long-lived assets				(957)
Products Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of long-lived assets		0	21	0
Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of long-lived assets		34	5	0
(Gains) losses on divestitures of long-lived assets		2	(54)	(335)
Gain on sale of interest in equity investment		0	(10)	0
Terminals | Kinder Morgan Canada Limited
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gains) losses on divestitures of long-lived assets				(339)
Terminals | Staten Island Terminal [Member]
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	350	74
Impairment of goodwill		0	600	0
(Gains) losses on divestitures of long-lived assets		(8)	0	2
Ruby
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of equity investments				650
Ruby | Notes Receivable
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of equity investments		117
Ruby | Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of equity investments				650
NGPL Holdings | Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Gain on sale of interest in equity investment		(206)	0	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	$ 117	$ 0	$ 0

Losses and Gains on Impairmen_4

Losses and Gains on Impairments, Divestitures and Other Write-downs_Impairments (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Impairments of long-lived assets		$ 1,634	$ 376
Ruby Pipeline Holding Company LLC
Property, Plant and Equipment [Line Items]
Impairments of equity investments				$ 650
Valuation Technique, Discounted Cash Flow | Natural Gas Pipelines Non-regulated
Property, Plant and Equipment [Line Items]
Estimated weighted average cost of capital			8.00%
Valuation Technique, Discounted Cash Flow | CO2
Property, Plant and Equipment [Line Items]
Estimated weighted average cost of capital	9.25%
CO2
Property, Plant and Equipment [Line Items]
Impairments of long-lived assets		0	$ 350	74
Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Impairments of long-lived assets		1,600	0	290
Impairments of equity investments		$ 0	$ 0	650
Natural Gas Pipelines | Ruby Pipeline Holding Company LLC
Property, Plant and Equipment [Line Items]
Impairments of equity investments				$ 650
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%

Losses and Gains on Impairmen_5

Losses and Gains on Impairments, Divestitures and Other Write-downs _GW (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020USD ($)	Dec. 31, 2020USD ($)
Goodwill [Line Items]
Impairment of goodwill		$ 1,600
CO2
Goodwill [Line Items]
Impairment of goodwill	$ 600	600
CO2 | Maximum
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	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 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
Natural Gas Pipelines Non-regulated | Valuation, Income Approach
Goodwill [Line Items]
Fair Value Measurement Inputs and Valuation Techniques, Weighting Of Approach	0.75
Terminals
Goodwill [Line Items]
Impairment of goodwill		$ 0
Terminals | Maximum
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	10.00%
Products Pipelines
Goodwill [Line Items]
Impairment of goodwill		$ 0
Products Pipelines | Maximum
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	10.00%

Losses and Gains on Impairmen_6

Losses and Gains on Impairments, Divestitures and Other Write-downs - Other write-downs (Details) - Natural Gas Pipelines - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Impairment of Long-lived assets and equity investments [Line Items]
Impairments of equity investments		$ 0	$ 0	$ 650
Ruby Pipeline Holding Company LLC | Notes Receivable
Impairment of Long-lived assets and equity investments [Line Items]
Impairments of equity investments	$ 117	$ 117	$ 0	$ 0

Income Taxes - Income Before In

Income Taxes - Income Before Income Taxes and Income Tax Provision (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Components of Income Before Income Taxes
U.S.	$ 2,217	$ 663	$ 2,482
Foreign	2	(2)	683
Income Before Income Taxes	2,219	661	3,165
Current tax expense (benefit)
Federal	0	(20)	(2)
State	11	9	10
Foreign(a)	3	147	201
Total	14	136	209
Deferred tax expense (benefit)
Federal	334	440	682
State	21	49	66
Foreign(a)	0	(144)	(31)
Total	355	345	717
Total	369	481	926
Canada
Components of Income Tax Provision
Foreign income tax (benefit) expense	$ (1)	$ (4)	$ 165

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Amount:
Federal income tax	$ 466	$ 139	$ 665
Taxes on foreign earnings, net of federal benefit	2	2	139
Net effects of noncontrolling interests	(14)	(13)	(10)
State income tax, net of federal benefit	50	52	68
Dividend received deduction	(46)	(27)	(39)
Release of valuation allowance	(38)	0	0
Nondeductible goodwill	0	336	108
General business credit	(36)	0	0
Federal refunds	0	(20)	0
Other	(15)	12	(5)
Total	$ 369	$ 481	$ 926
Percent:
Federal income tax, percent	21.00%	21.00%	21.00%
Taxes on foreign earnings, net of federal benefit, percent	0.10%	0.30%	4.40%
Net effects of noncontrolling interests, percent	(0.60%)	(2.00%)	(0.30%)
State income tax, net of federal benefit, percent	2.20%	7.90%	2.10%
Dividend received deduction, percent	(2.10%)	(4.10%)	(1.10%)
Release of valuation allowance, percent	(1.70%)	0.00%	0.00%
Nondeductible goodwill, percent	0.00%	50.80%	3.40%
General business credit, percent	(1.60%)	0.00%	0.00%
Federal refunds, percent	0.00%	(3.00%)	0.00%
Other, percent	(0.70%)	1.90%	(0.20%)
Total, percent	16.60%	72.80%	29.30%

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets
Employee benefits	$ 154	$ 224
Net operating loss carryforwards	1,476	1,484
Tax credit carryforwards	301	257
Other	229	242
Valuation allowances	(93)	(138)
Total deferred tax assets	2,067	2,069
Deferred tax liabilities
Property, plant and equipment	166	414
Investments	1,769	1,084
Other	17	35
Total deferred tax liabilities	1,952	1,533
Net deferred tax assets	$ 115	$ 536

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Valuation Allowances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Valuation Allowance [Line Items]
Net operating loss carryforwards	$ 1,476	$ 1,484
Tax credit carryforwards	301	257
Valuation allowance related to deferred tax assets	93	138
Change in valuation allowances	(7)
Net Operating Loss Carryovers Tax Credits and Capital Losses
Valuation Allowance [Line Items]
Valuation allowance related to deferred tax assets	93	$ 100
Change in valuation allowances	(5)
Net Operating Loss Carryovers Tax Credits and Capital Losses | Foreign Tax Authority
Valuation Allowance [Line Items]
Change in valuation allowances	(2)
Valuation Allowance Related to NGPL
Valuation Allowance [Line Items]
Change in valuation allowances	$ (38)

Income Taxes - Expiration Perio

Income Taxes - Expiration Periods for Deferred Tax Assets (Details) $ in Millions	Dec. 31, 2021USD ($)
State and Local Jurisdiction
Income Tax Examination [Line Items]
Net operating loss carryforwards	$ 4,000
Foreign Tax Authority
Income Tax Examination [Line Items]
Net operating loss carryforwards	77
Tax credit carryforwards	14
Indefinite Tax Period | Domestic Tax Authority
Income Tax Examination [Line Items]
Net operating loss carryforwards	2,700
Expires from 2022 - 2037 | Domestic Tax Authority
Income Tax Examination [Line Items]
Net operating loss carryforwards	3,200
General Business Tax Credit Carryforward
Income Tax Examination [Line Items]
Tax credit carryforwards	$ 287

Income Taxes - Unrecognized Tax

Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Unrecognized Tax Benefits
Gross unrecognized tax benefit balances	$ 21	$ 18	$ 16
Reductions based on settlements with taxing authority	0	$ 0	$ (21)
Unrecognized Tax Benefits, Other Disclosures
Unrecognized tax benefits, if recognized, which would affect effective tax rate	$ 21

Property, Plant and Equipment C

Property, Plant and Equipment Classes and Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Accumulated depreciation, depletion and amortization	$ (18,792)	$ (17,818)
Property, Plant and Equipment, Net, Excluding Nondepreciable Assets	33,329	33,851
Property, plant and equipment, net	35,653	35,836
Depreciation, Depletion and Amortization, Property, Plant and Equipment	1,873	1,928	$ 2,176
Pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	20,254	20,339
Equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	26,511	26,142
Other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	5,356	5,188
Land and land rights-of-way
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,718	1,403
Construction work in process
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	606	582
Natural Gas Pipelines Regulated
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 12,277	$ 12,160

Property, Plant and Equipment A

Property, Plant and Equipment Asset Retirement Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	$ 196	$ 214
Asset Retirement Obligation, Current	$ 4	$ 4

Investments Equity investments

Investments Equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Mar. 08, 2021
Schedule of Equity Method Investments [Line Items]
Equity Investments	$ 7,578	$ 7,917
Earnings (Loss) from Equity Investments	591	780	$ 101
Amortization of excess cost of equity investments	(78)	(140)	(83)
Pre-tax gain on sale of interest in equity investment	$ 206	0	0
ArcLight Capital Partners, LLC
Schedule of Equity Method Investments [Line Items]
Notes Receivable, Related Parties, Noncurrent				$ 125
Citrus Corporation
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 1,768	1,849
Earnings (Loss) from Equity Investments	$ 151	165	157
SNG
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 1,514	1,532
Earnings (Loss) from Equity Investments	$ 128	129	140
Permian Highway Pipeline
Schedule of Equity Method Investments [Line Items]
Ownership Interest	26.67%
Equity Investments	$ 647	632
Earnings (Loss) from Equity Investments	$ 63	0	0
Gulf Coast Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest	34.00%
Equity Investments	$ 618	638
Earnings (Loss) from Equity Investments	$ 86	90	37
NGPL Holdings
Schedule of Equity Method Investments [Line Items]
Ownership Interest	37.50%
Equity Investments	$ 604	803
Earnings (Loss) from Equity Investments	$ 94	116	81
Debt Instrument, Interest Rate, Stated Percentage	6.75%			6.75%
Notes Receivable, Related Parties, Noncurrent	$ 375	500		$ 500
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	$ 27	34	8
MEP
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 388	416
Earnings (Loss) from Equity Investments	$ (17)	(6)	15
Gulf LNG
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 347	361
Earnings (Loss) from Equity Investments	$ 22	19	17
Products (SE) Pipe Line Corporation
Schedule of Equity Method Investments [Line Items]
Ownership Interest	51.17%
Equity Investments	$ 346	357
Earnings (Loss) from Equity Investments	$ 48	43	58
Utopia Holding L.L.C.
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 328	329
Earnings (Loss) from Equity Investments	$ 20	20	20
EagleHawk
Schedule of Equity Method Investments [Line Items]
Ownership Interest	25.00%
Equity Investments	$ 266	275
Earnings (Loss) from Equity Investments	8	17	17
Watco Companies, LLC
Schedule of Equity Method Investments [Line Items]
Equity Investments	75	70
Earnings (Loss) from Equity Investments	$ 9	16	19
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
Cortez Pipeline Company
Schedule of Equity Method Investments [Line Items]
Ownership Interest	52.98%
Equity Investments	$ 28	25
Earnings (Loss) from Equity Investments	$ 29	24	35
FEP
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Equity Investments	$ 0	16
Earnings (Loss) from Equity Investments	0	70	59
Ruby
Schedule of Equity Method Investments [Line Items]
Equity Investments	0	1
Earnings (Loss) from Equity Investments	(116)	15	(609)
Impairments of equity investments			650
Ruby | Notes Receivable
Schedule of Equity Method Investments [Line Items]
Impairments of equity investments	$ 117
Ruby | KMI
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
Ruby | Pembina Pipeline Corporation
Schedule of Equity Method Investments [Line Items]
Ownership Interest	50.00%
All others
Schedule of Equity Method Investments [Line Items]
Equity Investments	$ 649	613
Earnings (Loss) from Equity Investments	$ 66	$ 62	$ 55

Investments Summary of Signific

Investments Summary of Significant Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Revenues	$ 16,610	$ 11,700	$ 13,209
Costs and expenses	13,694	10,140	8,336
Net (loss) income	1,850	180	2,239
Current assets	3,829	3,203
Current liabilities	5,821	5,074
Non-current liabilities	32,674	34,333
Partners’/owners’ equity	30,823	31,436
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	5,426	5,076	4,906
Costs and expenses	6,083	4,249	3,508
Net (loss) income	(657)	827	$ 1,398
Current assets	1,235	1,013
Non-current assets	22,749	25,069
Current liabilities	1,778	1,787
Non-current liabilities	9,931	9,734
Partners’/owners’ equity	$ 12,275	$ 14,561

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Goodwill [Line Items]
Gross goodwill		$ 26,700		$ 26,637
Accumulated impairment losses		(6,786)		(5,186)
Goodwill		19,914	$ 19,851	21,451
Acquisition of Kinetrex		63
Impairments			(1,600)
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
Acquisition of Kinetrex		0
Impairments			0
Natural Gas Pipelines Non-regulated
Goodwill [Line Items]
Gross goodwill		4,940		4,940
Accumulated impairment losses		(2,597)		(1,597)
Goodwill		2,343	2,343	3,343
Acquisition of Kinetrex		0
Impairments			(1,000)
CO2
Goodwill [Line Items]
Gross goodwill		1,528		1,528
Accumulated impairment losses		(600)		0
Goodwill		928	928	1,528
Acquisition of Kinetrex		0
Impairments	$ (600)		(600)
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
Acquisition of Kinetrex		0
Impairments			0
Products Pipelines Terminals
Goodwill [Line Items]
Gross goodwill		221		221
Accumulated impairment losses		(70)		(70)
Goodwill		151	151	151
Acquisition of Kinetrex		0
Impairments			0
Terminals
Goodwill [Line Items]
Gross goodwill		1,481		1,481
Accumulated impairment losses		(679)		(679)
Goodwill		802	802	802
Acquisition of Kinetrex		0
Impairments			0
Energy Transition Ventures
Goodwill [Line Items]
Gross goodwill		63		0
Accumulated impairment losses		0		0
Goodwill		63	0	$ 0
Acquisition of Kinetrex		$ 63
Impairments			$ 0

Debt - Schedule of Debt (Detail

Debt - Schedule of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2021	Oct. 26, 2021	Feb. 11, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries	$ 32,418			$ 33,396
Less: Current portion of debt	2,646			2,558
Total long-term debt – KMI and Subsidiaries	29,772			30,838
Credit facility and commercial paper borrowings(a)
Debt Instrument [Line Items]
Less: Current portion of debt	$ 0			0
EPC Building, LLC, promissory note, 3.967%, due January 2021 through December 2035 | EPC Building LLC
Debt Instrument [Line Items]
Interest rate, stated percentage	3.967%
Total debt – KMI and Subsidiaries	$ 364			380
Trust I Preferred Securities, 4.75%, due March 2028(i) | Capital Trust I
Debt Instrument [Line Items]
Interest rate, stated percentage	4.75%
Total debt – KMI and Subsidiaries	$ 221			221
Less: Current portion of debt	111			111
Other miscellaneous debt(j)
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries	248			254
Less: Current portion of debt	47			$ 47
Senior Notes | 5.00%, due February 2021
Debt Instrument [Line Items]
Interest rate, stated percentage				5.00%
Total debt – KMI and Subsidiaries	0			$ 750
Less: Current portion of debt	0			$ 750
Senior Notes | 3.50%, due March 2021(c)
Debt Instrument [Line Items]
Interest rate, stated percentage				3.50%
Total debt – KMI and Subsidiaries	0			$ 750
Less: Current portion of debt	0			$ 750
Senior Notes | 5.80%, due March 2021
Debt Instrument [Line Items]
Interest rate, stated percentage				5.80%
Total debt – KMI and Subsidiaries	0			$ 400
Less: Current portion of debt	0			$ 400
Senior Notes | 5.00%, due October 2021
Debt Instrument [Line Items]
Interest rate, stated percentage				5.00%
Total debt – KMI and Subsidiaries	0			$ 500
Less: Current portion of debt	$ 0			500
Senior Notes | 4.15%, due March 2022
Debt Instrument [Line Items]
Interest rate, stated percentage	4.15%
Total debt – KMI and Subsidiaries	$ 375			375
Less: Current portion of debt	$ 375			0
Senior Notes | 1.50%, due March 2022(d)
Debt Instrument [Line Items]
Interest rate, stated percentage	1.50%
Total debt – KMI and Subsidiaries	$ 853			917
Less: Current portion of debt	$ 853			0
Senior Notes | 3.95%, due September 2022
Debt Instrument [Line Items]
Interest rate, stated percentage	3.95%
Total debt – KMI and Subsidiaries	$ 1,000			1,000
Less: Current portion of debt	$ 1,000			0
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
Senior Notes | Floating rate, due January 2023(e)
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries	$ 250			250
Senior Notes | 3.45%, due February 2023
Debt Instrument [Line Items]
Interest rate, stated percentage	3.45%
Total debt – KMI and Subsidiaries	$ 625			625
Senior Notes | 3.50%, due September 2023
Debt Instrument [Line Items]
Interest rate, stated percentage	3.50%
Total debt – KMI and Subsidiaries	$ 600			600
Senior Notes | 5.625%, due November 2023
Debt Instrument [Line Items]
Interest rate, stated percentage	5.625%
Total debt – KMI and Subsidiaries	$ 750			750
Senior Notes | 4.15%, due February 2024
Debt Instrument [Line Items]
Interest rate, stated percentage	4.15%
Total debt – KMI and Subsidiaries	$ 650			650
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(f)
Debt Instrument [Line Items]
Interest rate, stated percentage	1.75%	1.75%
Total debt – KMI and Subsidiaries	$ 500	$ 500		0
Senior Notes | 6.70%, due February 2027
Debt Instrument [Line Items]
Interest rate, stated percentage	6.70%
Total debt – KMI and Subsidiaries	$ 7			7
Senior Notes | 2.25%, due March 2027(d)
Debt Instrument [Line Items]
Interest rate, stated percentage	2.25%
Total debt – KMI and Subsidiaries	$ 569			611
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 | 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(f)(g)
Debt Instrument [Line Items]
Interest rate, stated percentage	3.60%	3.60%	3.60%
Total debt – KMI and Subsidiaries	$ 1,050	$ 300	$ 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(h) | EPNG
Debt Instrument [Line Items]
Interest rate, stated percentage	8.625%
Total debt – KMI and Subsidiaries	$ 260			260
Less: Current portion of debt	$ 260			0
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 | 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 (

Debt - Additional Information (Details) $ / shares in Units, shares in Millions, $ in Millions	Oct. 26, 2021USD ($)	Feb. 11, 2021USD ($)	Jan. 04, 2021USD ($)	Dec. 31, 2021USD ($)$ / shares$ / €shares	Dec. 31, 2020USD ($)$ / €	Dec. 31, 2019USD ($)
Debt Instrument [Line Items]
Aggregate principal amount				$ 32,418	$ 33,396
Repayments of debt				6,831	3,996	$ 11,224
Issuances of debt				$ 5,959	$ 3,888	$ 8,036
Exchange rate | $ / €				1.1370	1.2216
Debt fair value adjustments				$ 902	$ 1,293
Capital Trust I
Debt Instrument [Line Items]
Ownership percentage				100.00%
Senior Notes
Debt Instrument [Line Items]
Redemption Price				100.00%
Issuances of debt	$ 796	$ 741
3.50%, due March 2021(c) | Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage					3.50%
Aggregate principal amount				$ 0	$ 750
Repayments of debt			$ 750
1.50%, due March 2022(d) | Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage				1.50%
Aggregate principal amount				$ 853	917
Change to debt as a result of changes in exchange rate				$ 38	102
2.25%, due March 2027(d) | Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage				2.25%
Aggregate principal amount				$ 569	611
Change to debt as a result of changes in exchange rate				$ 26	68
1.75%, due November 2026(f) | Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage	1.75%			1.75%
Aggregate principal amount	$ 500			$ 500	0
3.60%, due February 2051(f)(g) | Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage	3.60%	3.60%		3.60%
Aggregate principal amount	$ 300	$ 750		$ 1,050	0
Trust I Preferred Securities, 4.75%, due March 2028(i) | Capital Trust I
Debt Instrument [Line Items]
Interest rate, stated percentage				4.75%
Aggregate principal amount				$ 221	$ 221
Trust Convertible Preferred Securities Outstanding | shares				4.4
Liquidation preference | $ / shares				$ 50
Conversion price | $ / shares				$ 25.18
Trust I Preferred Securities, 4.75%, due March 2028(i) | Capital Trust I | Class P
Debt Instrument [Line Items]
Conversion rate				0.7197

Debt - Schedule of Current Port

Debt - Schedule of Current Portion of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Current portion of debt	$ 2,646	$ 2,558
Debt, weighted average interest rate	4.67%	4.86%
Line of Credit Facility, Current borrowing capacity	$ 3,900
$3.5 billion credit facility due August 20, 2026
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
Debt Instrument [Line Items]
Current portion of debt	0	0
Maximum borrowing capacity	4,000
5.00%, due February 2021 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 750
Interest rate, stated percentage		5.00%
3.50%, due March 2021 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 750
Interest rate, stated percentage		3.50%
5.80%, due March 2021 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 400
Interest rate, stated percentage		5.80%
5.00%, due October 2021 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 500
Interest rate, stated percentage		5.00%
8.625%, due January 2022(h) | EPNG | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 260	$ 0
Interest rate, stated percentage	8.625%
4.15%, due March 2022 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 375	0
Interest rate, stated percentage	4.15%
1.50%, due March 2022(d) | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 853	0
Interest rate, stated percentage	1.50%
3.95%, due September 2022 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 1,000	0
Interest rate, stated percentage	3.95%
Trust I Preferred Securities, 4.75% due March 2028(d) | Capital Trust I
Debt Instrument [Line Items]
Current portion of debt	$ 111	111
Interest rate, stated percentage	4.75%
Other debt
Debt Instrument [Line Items]
Current portion of debt	$ 47	$ 47

Debt - Credit Facilities and Re

Debt - Credit Facilities and Restrictive Covenants (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)
Line of Credit Facility [Line Items]
Current portion of debt	$ 2,646	$ 2,558
Line of Credit Facility, Current borrowing capacity	3,900
$3.5 billion credit facility due August 20, 2026
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, 2026 | Minimum
Line of Credit Facility [Line Items]
Standby fee rate	0.10%
$3.5 billion credit facility due August 20, 2026 | Maximum
Line of Credit Facility [Line Items]
Standby fee rate	0.25%
$3.5 billion credit facility due August 20, 2026 | LIBOR Alternate Base Rate | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.10%
$3.5 billion credit facility due August 20, 2026 | LIBOR Alternate Base Rate | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.75%
$3.5 billion credit facility due August 20, 2026 | London Interbank Offered Rate (LIBOR) | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
$3.5 billion credit facility due August 20, 2026 | London Interbank Offered Rate (LIBOR) | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.75%
$3.5 billion credit facility due August 20, 2026 | Federal Funds Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
$3.5 billion credit facility due August 20, 2026 | Eurodollar
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
$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 | LIBOR Alternate Base Rate | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.10%
$500 million credit facility due November 16, 2023 | LIBOR Alternate Base Rate | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
$500 million credit facility due November 16, 2023 | London Interbank Offered Rate (LIBOR) | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
$500 million credit facility due November 16, 2023 | London Interbank Offered Rate (LIBOR) | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.00%
Commercial Paper
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 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 o

Debt - Schedule of Maturities of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
2022	$ 2,646
2023	3,250
2024	1,925
2025	1,567
2026	1,102
Thereafter	21,928
Total debt – KMI and Subsidiaries	$ 32,418	$ 33,396

Debt - Schedule of Debt Fair Va

Debt - Schedule of Debt Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
Purchase accounting debt fair value adjustments	$ 498	$ 546
Carrying value adjustment to hedged debt	376	702
Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a)	223	240
Unamortized debt discounts, net	(71)	(76)
Unamortized debt issuance costs	(124)	(119)
Total debt fair value adjustments	$ 902	$ 1,293
Weighted-average amortization period of the unamortized premium from the termination of interest rate swaps	13 years

Debt - Schedule of Fair Value o

Debt - Schedule of Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	$ 33,320	$ 34,689
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	$ 37,775	$ 39,622

Debt - Interest Rates, Interest

Debt - Interest Rates, Interest Rate Swaps and Contingent Debt (Details)	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
Debt, weighted average interest rate	4.67%	4.86%

Share-based Compensation and _3

Share-based Compensation and Employee Benefits - Share-based Compensation - Narrative (Details) - Restricted Stock Awards - Class P - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors
Share-based Compensation
Shares of Class P common stock authorized under the plan	1,190,000
Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors | Six Month Vesting Period
Share-based Compensation
Grants during the period (shares)	49,890	14,570	23,100
Value of shares granted	$ 0.8	$ 0.3	$ 0.4
Award vesting period	6 months
Kinder Morgan Inc 2021 Amended and Restated Stock Incentive Plan
Share-based Compensation
Shares of Class P common stock authorized under the plan	63,000,000
Grants during the period (shares)	4,705,000
Intrinsic value of restricted stock vested	$ 77	59	87
Expense related to restricted stock awards	59	73	62
Amounts capitalized related to restricted stock awards	9	$ 11	$ 12
Unrecognized compensation costs	$ 112
Unrecognized compensation costs, weighted average remaining amortization period	1 year 11 months 23 days
Kinder Morgan Inc 2021 Amended and Restated Stock Incentive Plan | Minimum
Share-based Compensation
Award vesting period	1 year
Kinder Morgan Inc 2021 Amended and Restated Stock Incentive Plan | Maximum
Share-based Compensation
Award vesting period	10 years

Share-based Compensation and _4

Share-based Compensation and Employee Benefits - Summary of Activity and Related Balances of Restricted Stock Awards (Details) - Restricted Stock Awards - Class P - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Shares
Outstanding at end of period (shares)	13,000
Kinder Morgan Inc 2021 Amended and Restated Stock Incentive Plan
Shares
Outstanding at beginning of period (shares)	12,682
Granted (shares)	4,705
Vested (shares)	(4,463)
Forfeited (shares)	(307)
Outstanding at end of period (shares)	12,617	12,682
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (dollars per share)	$ 17.79
Granted (dollars per share)	17.44	$ 15.10	$ 20.46
Vested (dollars per share)	17.89
Forfeited (dollars per share)	17.47
Outstanding at end of period (dollars per share)	$ 17.63	$ 17.79

Share-based Compensation and _5

Share-based Compensation and Employee Benefits - Summary of Future Vesting of Outstanding Restricted Stock Awards (Details) - Restricted Stock Awards - Class P - shares shares in Thousands	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	13,000
Kinder Morgan Inc 2021 Amended and Restated Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	12,617	12,682
Kinder Morgan Inc 2021 Amended and Restated Stock Incentive Plan | 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	2,832
Kinder Morgan Inc 2021 Amended and Restated Stock Incentive Plan | 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	5,552
Kinder Morgan Inc 2021 Amended and Restated Stock Incentive Plan | 2024
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	3,662
Kinder Morgan Inc 2021 Amended and Restated Stock Incentive Plan | 2025
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	513
Kinder Morgan Inc 2021 Amended and Restated Stock Incentive Plan | 2026
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	58

Share-based Compensation and _6

Share-based Compensation and Employee Benefits - Pensions and Other Postretirement Benefit Plans - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 48	$ 53	$ 50
Pension Benefits
Pension and Other Postretirement Benefit Plans
Percentage of employees covered	100.00%
Vesting period	3 years
Accumulated benefit obligation	$ 2,608	2,804
Expected Payment of Future Benefits and Employer Contributions
Expected employer contributions in next year	$ 50
Pension Benefits | Minimum | Equities
Plan Assets
Target allocation percentage	42.00%
Pension Benefits | Minimum | Fixed Income Securities
Plan Assets
Target allocation percentage	37.00%
Pension Benefits | Minimum | Real Estate
Plan Assets
Target allocation percentage	2.00%
Pension Benefits | Minimum | Company Securities
Plan Assets
Target allocation percentage	0.00%
Pension Benefits | Maximum | Equities
Plan Assets
Target allocation percentage	52.00%
Pension Benefits | Maximum | Fixed Income Securities
Plan Assets
Target allocation percentage	47.00%
Pension Benefits | Maximum | Real Estate
Plan Assets
Target allocation percentage	12.00%
Pension Benefits | Maximum | Company Securities
Plan Assets
Target allocation percentage	10.00%
OPEB
Pension and Other Postretirement Benefit Plans
Medicare participation, age	65
Accumulated benefit obligation whose accumulated benefit obligations exceeded the fair value of plan assets	$ 219	255
Accumulated benefit obligation whose accumulated benefit obligations exceeded the fair value of plan assets, fair value of plan assets	42	$ 48
Expected Payment of Future Benefits and Employer Contributions
Expected employer contributions in next year	$ 7
Actuarial Assumptions and Sensitivity Analysis
Weighted-average annual rate of increase in the per capita cost of covered health care benefits	5.63%
Ultimate health care cost trend rate	4.00%
OPEB | Minimum | Equities
Plan Assets
Target allocation percentage	46.00%
OPEB | Minimum | Fixed Income Securities
Plan Assets
Target allocation percentage	25.00%
OPEB | Minimum | Cash
Plan Assets
Target allocation percentage	0.00%
OPEB | Maximum | Equities
Plan Assets
Target allocation percentage	68.00%
OPEB | Maximum | Fixed Income Securities
Plan Assets
Target allocation percentage	50.00%
OPEB | Maximum | Cash
Plan Assets
Target allocation percentage	22.00%

Share-based Compensation and _7

Share-based Compensation and Employee Benefits - Benefit Obligation, Plan Assets and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$ 2,844	$ 2,696
Service cost	53	59	$ 53
Interest cost	45	71	96
Actuarial (gain) loss	(80)	198
Benefits paid	(204)	(180)
Participant contributions	0	0
Medicare Part D subsidy receipts	0	0
Benefit obligation at end of period	2,658	2,844	2,696
Change in plan assets:
Fair value of plan assets at beginning of period	2,199	2,076
Actual return on plan assets	180	178
Employer contributions	56	125
Participant contributions	0	0
Medicare Part D subsidy receipts	0	0
Benefits paid	(204)	(180)
Fair value of plan assets at end of period	2,231	2,199	2,076
Funded status - net (liability) asset at December 31,	(427)	(645)
OPEB
Change in benefit obligation:
Benefit obligation at beginning of period	299	333
Service cost	1	1	1
Interest cost	4	8	12
Actuarial (gain) loss	(21)	(17)
Benefits paid	(28)	(29)
Participant contributions	1	2
Medicare Part D subsidy receipts	1	1
Benefit obligation at end of period	257	299	333
Change in plan assets:
Fair value of plan assets at beginning of period	361	333
Actual return on plan assets	40	47
Employer contributions	7	7
Participant contributions	1	2
Medicare Part D subsidy receipts	1	1
Benefits paid	(28)	(29)
Fair value of plan assets at end of period	382	361	$ 333
Funded status - net (liability) asset at December 31,	$ 125	$ 62

Share-based Compensation and _8

Share-based Compensation and Employee Benefits - Components of Funded Status (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-current benefit asset	$ 0	$ 0
Current benefit liability	0	0
Non-current benefit liability	(427)	(645)
Funded status - net (liability) asset at December 31,	(427)	(645)
OPEB
Defined Benefit Plan Disclosure [Line Items]
Non-current benefit asset	302	269
Current benefit liability	(18)	(19)
Non-current benefit liability	(159)	(188)
Funded status - net (liability) asset at December 31,	125	62
OPEB | Other Affiliates
Defined Benefit Plan Disclosure [Line Items]
Non-current benefit asset	$ 54	$ 46

Share-based Compensation and _9

Share-based Compensation and Employee Benefits - Schedule of Components of Accumulated Other Comprehensive (Loss) Income (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Unrecognized net actuarial (loss) gain	$ (495)	$ (674)
Unrecognized prior service (cost) credit	(2)	(2)
Accumulated other comprehensive (loss) income	(497)	(676)
OPEB
Defined Benefit Plan Disclosure [Line Items]
Unrecognized net actuarial (loss) gain	176	153
Unrecognized prior service (cost) credit	6	9
Accumulated other comprehensive (loss) income	$ 182	$ 162

Share-based Compensation and_10

Share-based Compensation and Employee Benefits - Fair Value of Pension and OPEB Assets by Level of Assets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 2,231	$ 2,199	$ 2,076
Pension Benefits | Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	755	762
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	164	249
Pension Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	591	513
Pension Benefits | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	1,476	1,437
Pension Benefits | Cash | Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	11	0
Pension Benefits | Cash | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	11	0
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	25	77
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	25	77
Pension Benefits | Equities | Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	153	249
Pension Benefits | Equities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	153	249
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	566	425
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	566	425
Amount of KMI securities invested in		1
Pension Benefits | Derivatives | Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	11
Pension Benefits | Derivatives | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits | Derivatives | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	11
Pension Benefits | Common/Collective Trusts | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 1,389	$ 1,184
Pension Benefits | Common/Collective Trusts Invested in Equity Securities | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	83.00%	71.00%
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	17.00%	29.00%
Pension Benefits | Private Investment Funds | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 39	$ 208
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%	71.00%
Pension Benefits | Private Investment Funds Invested in Equity Securities | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments		29.00%
Pension Benefits | Private Limited Partnerships | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 48	$ 45
OPEB
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	382	361	$ 333
OPEB | Short-term Investment Funds | Total
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	3	5
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	5
OPEB | Common/Collective Trusts | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 379	$ 356
OPEB | Common/Collective Trusts Invested in Equity Securities | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	63.00%	65.00%
OPEB | Common/Collective Trusts Invested in Fixed Income Securities | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	37.00%	35.00%
Class P | Pension Benefits | Equities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Amount of KMI securities invested in	$ 97	$ 83

Share-based Compensation and_11

Share-based Compensation and Employee Benefits - Schedule of Expected Payment of Future Benefits and Employer Contributions (Details) $ in Millions	Dec. 31, 2021USD ($)
Pension Benefits
Expected Future Benefit Payments:
2022	$ 212
2023	210
2024	204
2025	199
2026	194
2027 - 2031	864
OPEB
Expected Future Benefit Payments:
2022	28
2023	26
2024	24
2025	22
2026	21
2027 - 2031	84
Expected Future Reductions Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003:
2022	1
2023	1
2024	1
2025	1
2026	1
2027 - 2031	$ 4

Share-based Compensation and_12

Share-based Compensation and Employee Benefits - Schedule of Weighted-Average Actuarial Assumptions (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Assumptions related to benefit obligations:
Discount rate	2.74%	2.27%	3.17%
Rate of compensation increase	3.50%	3.50%	3.50%
Interest crediting rate	3.01%	2.57%	3.71%
Assumptions related to benefit costs:
Expected return on plan assets	6.25%	6.75%	7.25%
Rate of compensation increase	3.50%	3.50%	3.50%
Interest crediting rate	2.57%	3.71%	3.90%
OPEB
Defined Benefit Plan Disclosure [Line Items]
UBIT rate	27.00%	27.00%	27.00%
Assumptions related to benefit obligations:
Discount rate	2.56%	2.08%	3.03%
Assumptions related to benefit costs:
Expected return on plan assets	5.75%	6.50%	6.50%
Benefit obligation | Pension Benefits
Assumptions related to benefit costs:
Discount rate	2.27%	3.17%	4.26%
Benefit obligation | OPEB
Assumptions related to benefit costs:
Discount rate	2.08%	3.03%	4.16%
Discount rate for interest on benefit obligations | Pension Benefits
Assumptions related to benefit costs:
Discount rate	1.60%	2.71%	3.89%
Discount rate for interest on benefit obligations | OPEB
Assumptions related to benefit costs:
Discount rate	1.46%	2.63%	3.83%
Discount rate for service cost | Pension Benefits
Assumptions related to benefit costs:
Discount rate	2.33%	3.24%	4.28%
Discount rate for service cost | OPEB
Assumptions related to benefit costs:
Discount rate	2.70%	3.48%	4.51%
Discount rate for interest on service cost | Pension Benefits
Assumptions related to benefit costs:
Discount rate	1.70%	2.80%	3.93%
Discount rate for interest on service cost | OPEB
Assumptions related to benefit costs:
Discount rate	2.63%	3.39%	4.46%

Share-based Compensation and_13

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Components of net benefit cost (credit):
Service cost	$ 53	$ 59	$ 53
Interest cost	45	71	96
Expected return on assets	(133)	(137)	(129)
Amortization of prior service cost (credit)	0	1	0
Amortization of net actuarial loss (gain)	52	40	54
Net benefit cost (credit)	17	34	74
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net (gain) loss arising during period	(127)	157	(42)
Amortization or settlement recognition of net actuarial (loss) gain	(52)	(40)	(54)
Amortization of prior service (cost) credit	0	(1)	0
Total recognized in total other comprehensive (income) loss(a)	(179)	116	(96)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss	(162)	150	(22)
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)	3	2
OPEB
Components of net benefit cost (credit):
Service cost	1	1	1
Interest cost	4	8	12
Expected return on assets	(16)	(16)	(16)
Amortization of prior service cost (credit)	(5)	(5)	(4)
Amortization of net actuarial loss (gain)	(17)	(13)	(11)
Net benefit cost (credit)	(33)	(25)	(18)
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net (gain) loss arising during period	(40)	(43)	(17)
Amortization or settlement recognition of net actuarial (loss) gain	17	13	11
Amortization of prior service (cost) credit	3	3	2
Total recognized in total other comprehensive (income) loss(a)	(20)	(27)	(4)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss	$ (53)	$ (52)	$ (22)

Share-based Compensation and_14

Share-based Compensation and Employee Benefits - Other Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Multiemployer Plans
Amounts charged to expense	$ 8	$ 6	$ 8

Stockholders' Equity - Common E

Stockholders' Equity - Common Equity (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 19, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Jul. 19, 2017	Dec. 19, 2014
Class of Stock [Line Items]
Common share buy-back program, amount						$ 2,000
Value of shares repurchased		$ 0	$ 50	$ 2	$ 575
Common share buy-back program, average price per share					$ 17.71
Per common share cash dividend declared for the period		$ 1.08	$ 1.05	$ 1
Per share cash dividend paid in the period		$ 1.0725	$ 1.0375	$ 0.95
Subsequent Event
Class of Stock [Line Items]
Per common share cash dividend declared for the period	$ 0.27
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]
Shares repurchased		0	4,000,000	100,000	32,000,000

Stockholders' Equity - Accumula

Stockholders' Equity - Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	$ 31,838	$ 34,086	$ 34,531
Balance	31,921	31,838	34,086
Net unrealized gains/(losses) on cash flow hedge derivatives
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(13)	(7)	164
Other comprehensive (loss) gain before reclassifications	(432)	249	(177)
Losses (gains) reclassified from accumulated other comprehensive loss	273	(255)	6
Net current-period change in accumulated other comprehensive (loss) income	(159)	(6)	(171)
Balance	(172)	(13)	(7)
Foreign currency translation adjustments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	0	0	(91)
Other comprehensive (loss) gain before reclassifications	0	0	0
Losses (gains) reclassified from accumulated other comprehensive loss	0	0	91
Net current-period change in accumulated other comprehensive (loss) income	0	0	91
Balance	0	0	0
Pension and other postretirement liability adjustments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(394)	(326)	(403)
Other comprehensive (loss) gain before reclassifications	155	(68)	77
Losses (gains) reclassified from accumulated other comprehensive loss	0	0	0
Net current-period change in accumulated other comprehensive (loss) income	155	(68)	77
Balance	(239)	(394)	(326)
Total Accumulated other comprehensive loss
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(407)	(333)	(330)
Other comprehensive (loss) gain before reclassifications	(277)	181	(100)
Losses (gains) reclassified from accumulated other comprehensive loss	273	(255)	97
Net current-period change in accumulated other comprehensive (loss) income	(4)	(74)	(3)
Balance	$ (411)	$ (407)	$ (333)

Stockholders' Equity - Noncontr

Stockholders' Equity - Noncontrolling Interests (Details) $ in Millions, $ in Billions	Jan. 03, 2019USD ($)	Jan. 03, 2019CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Payments to noncontrolling interests	$ 900	$ 1.2	$ 0	$ 0	$ 879
Kinder Morgan Canada Limited
Dividends, Preferred Stock, Cash					22
Restricted Voting Shares | Kinder Morgan Canada Limited
Total value of distributions paid in the period					$ 17

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
RELATED PARTY ASSETS
Accounts receivable	$ 38	$ 41
Other current assets	4	6
Deferred charges and other assets	0	109
Total Assets	42	156
RELATED PARTY LIABILITIES
Current portion of debt	6	6
Accounts payable	21	25
Other current liabilities	4	4
Long-term debt	148	154
Other long-term liabilities and deferred credits	56	48
Total Liabilities	235	237
RELATED PARTY REVENUES
Revenues	16,610	11,700	$ 13,209
RELATED PARTY OPERATING COSTS, EXPENSES AND OTHER
Costs of sales	6,493	2,545	3,263
Other operating expenses	(7)	(2)	(3)
Affiliated Entity
RELATED PARTY REVENUES
Revenues	164	206	269
RELATED PARTY OPERATING COSTS, EXPENSES AND OTHER
Costs of sales	145	116	75
Other operating expenses	$ 52	$ 119	$ 132

Commitments and Contingent Li_2

Commitments and Contingent Liabilities Rights-of-way obligations (Details) $ in Millions	Dec. 31, 2021USD ($)
ROW
Other Commitments [Line Items]
Contractual Obligation	$ 149

Commitments and Contingent Li_3

Commitments and Contingent Liabilities Contingent Debt (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)investees	Dec. 31, 2020USD ($)
Indirect Guarantee of Indebtedness
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 170	$ 217
Number of equity investees subject to contingent obligation	1	3
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	$ 122

Risk Management - Energy Commod

Risk Management - Energy Commodity Price Risk Management (Details) - Short - Energy commodity derivative contracts	12 Months Ended
	Dec. 31, 2021MMBblsBcf
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	(6.5)
Designated as Hedging Instrument | Natural Gas Fixed Price
Derivative [Line Items]
Net open position | Bcf	(54.2)
Designated as Hedging Instrument | Natural Gas Basis
Derivative [Line Items]
Net open position | Bcf	(43.9)
Designated as Hedging Instrument | NGL Fixed Price
Derivative [Line Items]
Net open position	(0.7)
Not Designated as Hedging Instrument | Crude Oil Fixed Price
Derivative [Line Items]
Net open position	(1)
Not Designated as Hedging Instrument | Crude Oil Basis
Derivative [Line Items]
Net open position	(9.1)
Not Designated as Hedging Instrument | Natural Gas Fixed Price
Derivative [Line Items]
Net open position | Bcf	(13.2)
Not Designated as Hedging Instrument | Natural Gas Basis
Derivative [Line Items]
Net open position | Bcf	(38.5)
Not Designated as Hedging Instrument | NGL Fixed Price
Derivative [Line Items]
Net open position	(1.4)

Risk Management - Interest Rate

Risk Management - Interest Rate Risk Management (Details) - USD ($) $ in Millions	Jan. 04, 2022	Dec. 31, 2021
Fair Value Hedging | Fixed-To-Variable Interest Rate Contracts | Designated as Hedging Instrument
Derivative [Line Items]
Notional amount		$ 7,100
Fair Value Hedging | Variable-to-Fixed Interest Rate Contracts | Not Designated as Hedging Instrument
Derivative [Line Items]
Notional amount		5,100
Fair Value Hedging | Variable-to-Fixed Interest Rate Contracts | Not Designated as Hedging Instrument | Subsequent Event
Derivative [Line Items]
Notional amount	$ 4,860
Fair Value Hedging | Fixed-To-Variable Interest Rate Contracts Q1 2021 | Designated as Hedging Instrument
Derivative [Line Items]
Notional amount		375
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		750
Long-term Debt | Fixed-To-Variable Interest Rate Contracts
Derivative [Line Items]
Principal amount of hedged senior notes		$ 6,350

Risk Management - Foreign Curre

Risk Management - Foreign Currency Risk Management (Details) $ in Millions	Dec. 31, 2021USD ($)
Cash Flow Hedging | Cross Currency Interest Rate Contract
Derivative [Line Items]
Notional amount	$ 1,358

Risk Management - Fair Value of

Risk Management - Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Asset derivatives	$ 514	$ 931
Liability derivatives	(293)	(78)
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	76	99
Liability derivatives	(272)	(63)
Interest rate contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	397	694
Liability derivatives	(18)	(10)
Foreign currency contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	41	138
Liability derivatives	(3)	(6)
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Asset derivatives	490	907
Liability derivatives	(256)	(57)
Designated as Hedging Instrument | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	64	75
Liability derivatives	(235)	(41)
Designated as Hedging Instrument | Energy commodity derivative contracts | Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	61	42
Designated as Hedging Instrument | Energy commodity derivative contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liability derivatives	(141)	(33)
Designated as Hedging Instrument | Energy commodity derivative contracts | Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	3	33
Designated as Hedging Instrument | Energy commodity derivative contracts | Other Long-Term Liabilities and Deferred Credits
Derivatives, Fair Value [Line Items]
Liability derivatives	(94)	(8)
Designated as Hedging Instrument | Interest rate contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	385	694
Liability derivatives	(18)	(10)
Designated as Hedging Instrument | Interest rate contracts | Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	101	119
Designated as Hedging Instrument | Interest rate contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liability derivatives	(3)	(3)
Designated as Hedging Instrument | Interest rate contracts | Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	284	575
Designated as Hedging Instrument | Interest rate contracts | Other Long-Term Liabilities and Deferred Credits
Derivatives, Fair Value [Line Items]
Liability derivatives	(15)	(7)
Designated as Hedging Instrument | Foreign currency contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	41	138
Liability derivatives	(3)	(6)
Designated as Hedging Instrument | Foreign currency contracts | Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	35	0
Designated as Hedging Instrument | Foreign currency contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liability derivatives	(3)	(6)
Designated as Hedging Instrument | Foreign currency contracts | Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	6	138
Designated as Hedging Instrument | Foreign currency contracts | Other Long-Term Liabilities and Deferred Credits
Derivatives, Fair Value [Line Items]
Liability derivatives	0	0
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Asset derivatives	24	24
Liability derivatives	(37)	(21)
Not Designated as Hedging Instrument | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	12	24
Liability derivatives	(37)	(21)
Not Designated as Hedging Instrument | Energy commodity derivative contracts | Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	11	24
Not Designated as Hedging Instrument | Energy commodity derivative contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liability derivatives	(31)	(21)
Not Designated as Hedging Instrument | Energy commodity derivative contracts | Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	1	0
Not Designated as Hedging Instrument | Energy commodity derivative contracts | Other Long-Term Liabilities and Deferred Credits
Derivatives, Fair Value [Line Items]
Liability derivatives	(6)	0
Not Designated as Hedging Instrument | Interest rate contracts | Fair Value of Derivative Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	12	0
Not Designated as Hedging Instrument | Interest rate contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liability derivatives	$ 0	$ 0

Risk Management - FV Input Leve

Risk Management - FV Input Level - Assets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Gross amount	$ 514	$ 931
Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	76	99
Contracts available for netting	(53)	(35)
Cash collateral held(b)	(20)	0
Net amount	3	64
Interest rate contracts
Derivative [Line Items]
Gross amount	397	694
Contracts available for netting	(9)	(2)
Cash collateral held(b)	0	0
Net amount	388	692
Foreign currency contracts
Derivative [Line Items]
Gross amount	41	138
Contracts available for netting	(3)	(6)
Cash collateral held(b)	0	0
Net amount	38	132
Level 1 | Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	56	6
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	20	93
Level 2 | Interest rate contracts
Derivative [Line Items]
Gross amount	397	694
Level 2 | Foreign currency contracts
Derivative [Line Items]
Gross amount	41	138
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 Input Le_2

Risk Management - FV Input Level - Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Gross amount	$ (293)	$ (78)
Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	(272)	(63)
Contracts available for netting	53	35
Collateral posted(b)	0	(8)
Net amount	(219)	(36)
Interest rate contracts
Derivative [Line Items]
Gross amount	(18)	(10)
Contracts available for netting	9	2
Collateral posted(b)	0	0
Net amount	(9)	(8)
Foreign currency contracts
Derivative [Line Items]
Gross amount	(3)	(6)
Contracts available for netting	3	6
Collateral posted(b)	0	0
Net amount	0	0
Level 1 | Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	(15)	(7)
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	(257)	(56)
Level 2 | Interest rate contracts
Derivative [Line Items]
Gross amount	(18)	(10)
Level 2 | Foreign currency contracts
Derivative [Line Items]
Gross amount	(3)	(6)
Level 3 | Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	0	0
Level 3 | Interest rate contracts
Derivative [Line Items]
Gross amount	0	0
Level 3 | Foreign currency contracts
Derivative [Line Items]
Gross amount	$ 0	$ 0

Risk Management - FV Hedging Ef

Risk Management - FV Hedging Effect on Income Statements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Cumulative amount of fair value hedging adjustments to hedged fixed rate debt	$ 376	$ 702
Designated as Hedging Instrument | Fair Value Hedging | Hedged Fixed Rate Debt
Derivative [Line Items]
Cumulative amount of fair value hedging adjustments to hedged fixed rate debt	376
Designated as Hedging Instrument | Fair Value Hedging | Interest, net | Interest Rate Contract
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives and related hedged item	(322)	335	$ 340
Designated as Hedging Instrument | Fair Value Hedging | Interest, net | Hedged Fixed Rate Debt
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives and related hedged item	$ 326	$ (343)	$ (353)

Risk Management - CF Hedging Ef

Risk Management - CF Hedging Effect on the Income Statements (Details) - Designated as Hedging Instrument - Cash Flow Hedging - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	$ (563)	$ 324	$ (229)
Gain/(loss) reclassified from Accumulated OCI into income	(356)	333	(8)
Loss to be reclassified within twelve months	58
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	(475)	240	(168)
Energy commodity derivative contracts | Revenues—Commodity sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	(271)	222	16
Energy commodity derivative contracts | Costs of sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	20	(14)	5
Energy commodity derivative contracts | Write-down of hedged inventory
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	41	0	12
Interest rate contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	5	(8)	(1)
Interest rate contracts | Earnings from equity investments
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	0	0	2
Foreign currency contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	(93)	92	(60)
Foreign currency contracts | Other, net
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	$ (105)	$ 125	$ (31)

Risk Management - Net Investmen

Risk Management - Net Investment Hedging Effect on the Income Statements (Details) - Net Investment Hedging - Designated as Hedging Instrument - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	$ 0	$ 0	$ (8)
Gain/(loss) reclassified from Accumulated OCI into income	0	0	83
Foreign currency contracts
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	0	0	(8)
Loss (gain) on impairments and divestitures, net | Foreign currency contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	$ 0	$ 0	83
KML and U.S. Portion of Cochin Pipeline System | Foreign currency contracts
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income			$ 83

Risk Management - Not Designate

Risk Management - Not Designated as Hedges Effect on Income Statements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ (493)	$ 24	$ 29
Energy commodity derivative contracts
Derivative [Line Items]
Loss on Derivative Instruments	479	11	8
Revenues—Commodity sales | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	(652)	(1)	33
Costs of sales | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	152	25	(7)
Earnings from equity investments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	(5)	0	3
Interest, net | Interest rate contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ 12	$ 0	$ 0

Risk Management - Credit Risks

Risk Management - Credit Risks (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	$ 155
Energy commodity derivative contracts
Credit Derivatives [Line Items]
Letters of credit outstanding	0	$ 0
Initial Margin Requirements	6
Variation Margin Requirements	20
Collateral posted(b)	0	(8)
Derivative, Collateral, Obligation to Return Cash, Variation Margin	20	0
Other Current Liabilities | Contract and Over the Counter | Energy commodity derivative contracts
Credit Derivatives [Line Items]
Derivative, Collateral, Obligation to Return Cash, Variation Margin	$ 14	$ 3

Revenue Recognition - Schedule

Revenue Recognition - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 16,154	$ 10,097	$ 12,080
Leasing services(d)	1,266	1,236	951
Other	113	146	129
Total other revenues	456	1,603	1,129
Total revenues	16,610	11,700	13,209
Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,411	4,370	4,877
Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,114	2,056	2,416
Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,525	6,426	7,293
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,480	2,032	2,595
Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,149	1,639	2,192
Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	9,629	3,671	4,787
Total revenues	8,714	3,891	4,811
Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	11,644	7,222	8,128
Products Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	2,245	1,721	1,831
Terminals
Disaggregation of Revenue [Line Items]
Total revenues	1,712	1,719	2,031
CO2
Disaggregation of Revenue [Line Items]
Total revenues	1,009	1,038	1,219
Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	11,871	6,659	7,737
Leasing services(d)	473	466	273
Other	65	116	90
Total other revenues	(162)	600	433
Total revenues	11,709	7,259	8,170
Operating Segments | Natural Gas Pipelines | Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,402	3,345	3,549
Operating Segments | Natural Gas Pipelines | Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	746	714	780
Operating Segments | Natural Gas Pipelines | Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,148	4,059	4,329
Operating Segments | Natural Gas Pipelines | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,463	2,038	2,603
Operating Segments | Natural Gas Pipelines | Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,260	562	805
Operating Segments | Natural Gas Pipelines | Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	7,723	2,600	3,408
Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,053	1,534	1,624
Leasing services(d)	172	166	182
Other	21	21	25
Total other revenues	192	187	207
Total revenues	2,245	1,721	1,831
Operating Segments | Products Pipelines | Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	259	271	319
Operating Segments | Products Pipelines | Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	949	905	1,016
Operating Segments | Products Pipelines | Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,208	1,176	1,335
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	845	358	289
Operating Segments | Products Pipelines | Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	845	358	289
Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,150	1,165	1,592
Leasing services(d)	565	557	442
Other	0	0	0
Total other revenues	565	557	442
Total revenues	1,715	1,722	2,034
Operating Segments | Terminals | Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	751	756	1,012
Operating Segments | Terminals | Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	375	395	560
Operating Segments | Terminals | Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,126	1,151	1,572
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	24	14	20
Operating Segments | Terminals | Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	24	14	20
Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,148	779	1,173
Leasing services(d)	56	47	54
Other	27	9	13
Total other revenues	(139)	259	46
Total revenues	1,009	1,038	1,219
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	45	42	60
Operating Segments | CO2 | Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	46	43	61
Operating Segments | CO2 | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	32	1	1
Operating Segments | CO2 | Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,070	735	1,111
Operating Segments | CO2 | Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,102	736	1,112
Corporate and Eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(68)	(40)	(46)
Leasing services(d)	0	0	0
Other	0	0	1
Total other revenues	0	0	1
Total revenues	(68)	(40)	(45)
Corporate and Eliminations | Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(2)	(3)	(4)
Corporate and Eliminations | Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(1)	0	0
Corporate and Eliminations | Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(3)	(3)	(4)
Corporate and Eliminations | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(15)	(7)	(9)
Corporate and Eliminations | Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(50)	(30)	(33)
Corporate and Eliminations | Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(65)	(37)	(42)
Sales
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(923)	221	49
Sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(700)	18	70
Sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(1)	0	0
Sales | Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	0	0	0
Sales | Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	(222)	203	(21)
Sales | Corporate and Eliminations
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	$ 0	$ 0	$ 0

Revenue Recognition - Contract

Revenue Recognition - Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Contract Assets
Contract assets balances	$ 39	$ 20
Transfer to accounts receivable	18
Contract Liabilities
Contract liability balances	212	$ 239
Transfer to revenues	$ 83

Revenue Recognition - Revenue A

Revenue Recognition - Revenue Allocated to Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2021USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated Revenue	$ 27,707
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Estimated Revenue	$ 4,324
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	$ 3,418
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	$ 2,857
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	$ 2,382
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	$ 2,108
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
Estimated Revenue	$ 12,618

Reportable Segments Revenues (D

Reportable Segments Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Revenues	$ 16,610	$ 11,700	$ 13,209
Other
Segment Reporting Information [Line Items]
Revenues	(68)	(40)	(45)
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(68)	(40)	(45)
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Revenues	11,644	7,222	8,128
Natural Gas Pipelines | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(65)	(37)	(42)
Products Pipelines
Segment Reporting Information [Line Items]
Revenues	2,245	1,721	1,831
Terminals
Segment Reporting Information [Line Items]
Revenues	1,712	1,719	2,031
Terminals | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(3)	(3)	(3)
CO2
Segment Reporting Information [Line Items]
Revenues	$ 1,009	$ 1,038	$ 1,219
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 e

Reportable Segments Operating expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Operating expenses(a)	$ 9,287	$ 5,398	$ 6,280
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Operating expenses(a)	7,000	3,457	4,213
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Operating expenses(a)	1,239	779	684
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Operating expenses(a)	793	762	888
Operating Segments | CO2
Segment Reporting Information [Line Items]
Operating expenses(a)	289	404	496
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating expenses(a)	$ (34)	$ (4)	$ (1)

Reportable Segments Other expen

Reportable Segments Other expense (income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Other expense (income)(b)	$ 1,617	$ 1,930	$ (945)
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other expense (income)(b)	1,597	1,009	(680)
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Other expense (income)(b)	0	21	0
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Other expense (income)(b)	32	(50)	(342)
Operating Segments | CO2
Segment Reporting Information [Line Items]
Other expense (income)(b)	(8)	950	77
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Other expense (income)(b)	0	0	2
Other
Segment Reporting Information [Line Items]
Other expense (income)(b)	$ (4)	$ 0	$ (2)

Reportable Segments Depreciatio

Reportable Segments Depreciation, depletion and amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
DD&A	$ 2,135	$ 2,164	$ 2,411
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
DD&A	1,099	1,062	1,005
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
DD&A	335	347	338
Operating Segments | Terminals
Segment Reporting Information [Line Items]
DD&A	440	438	494
Operating Segments | CO2
Segment Reporting Information [Line Items]
DD&A	236	291	548
Other
Segment Reporting Information [Line Items]
DD&A	$ 25	$ 26	$ 26

Reportable Segments Earnings (l

Reportable Segments Earnings (loss) from equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Earnings (loss) from equity investments and amortization of excess cost of equity investments, including loss on impairments of equity investments	$ 513	$ 640	$ 18
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Earnings (loss) from equity investments and amortization of excess cost of equity investments, including loss on impairments of equity investments	435	551	(101)
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Earnings (loss) from equity investments and amortization of excess cost of equity investments, including loss on impairments of equity investments	34	45	63
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Earnings (loss) from equity investments and amortization of excess cost of equity investments, including loss on impairments of equity investments	15	22	23
Operating Segments | CO2
Segment Reporting Information [Line Items]
Earnings (loss) from equity investments and amortization of excess cost of equity investments, including loss on impairments of equity investments	$ 29	$ 22	$ 33

Reportable Segments Other, net-

Reportable Segments Other, net-income(expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Other, net (Note 3)	$ 282	$ 56	$ 75
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other, net (Note 3)	216	11	53
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Other, net (Note 3)	1	1	6
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Other, net (Note 3)	3	13	(5)
Other
Segment Reporting Information [Line Items]
Other, net (Note 3)	$ 62	$ 31	$ 21

Reportable Segments Segment ear

Reportable Segments Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
DD&A	$ (2,135)	$ (2,164)	$ (2,411)
Amortization of excess cost of equity investments	(78)	(140)	(83)
General and administrative and corporate charges	(655)	(648)	(590)
Interest, net	(1,492)	(1,595)	(1,801)
Income tax expense	(369)	(481)	(926)
Net Income	1,850	180	2,239
Total Segments EBDA(e)
Segment Reporting Information [Line Items]
Segment EBDA(c)	6,547	5,213	8,071
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(c)	3,815	3,483	4,661
DD&A	(1,099)	(1,062)	(1,005)
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(c)	1,064	977	1,225
DD&A	(335)	(347)	(338)
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Segment EBDA(c)	908	1,045	1,506
DD&A	(440)	(438)	(494)
Operating Segments | CO2
Segment Reporting Information [Line Items]
Segment EBDA(c)	760	(292)	681
DD&A	(236)	(291)	(548)
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Segment EBDA(c)	0	0	(2)
Other
Segment Reporting Information [Line Items]
DD&A	(25)	(26)	(26)
General and administrative and corporate charges	$ (623)	$ (653)	$ (611)

Reportable Segments Capital exp

Reportable Segments Capital expenditures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Capital expenditures	$ 1,281	$ 1,707	$ 2,270
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	570	945	1,377
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	122	122	175
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Capital expenditures	332	433	347
Operating Segments | CO2
Segment Reporting Information [Line Items]
Capital expenditures	230	186	349
Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 27	$ 21	$ 22

Reportable Segments Investments

Reportable Segments Investments (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Investments	$ 7,578	$ 7,917
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments	6,887	7,262
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Investments	465	494
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Investments	137	136
Operating Segments | CO2
Segment Reporting Information [Line Items]
Investments	$ 89	$ 25

Reportable Segments Other Intan

Reportable Segments Other Intangibles, Net (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Intangible Assets, Net (Excluding Goodwill)	$ 1,678	$ 2,453
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Intangible Assets, Net (Excluding Goodwill)	557	1,418
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Intangible Assets, Net (Excluding Goodwill)	868	961
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Intangible Assets, Net (Excluding Goodwill)	51	64
Operating Segments | CO2
Segment Reporting Information [Line Items]
Intangible Assets, Net (Excluding Goodwill)	$ 202	$ 10

Reportable Segments Assets (Det

Reportable Segments Assets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Assets	$ 70,416	$ 71,973
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets	47,746	48,597
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Assets	9,088	9,182
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Assets	8,513	8,639
Operating Segments | CO2
Segment Reporting Information [Line Items]
Assets	2,843	2,478
Other
Segment Reporting Information [Line Items]
Assets	$ 2,226	$ 3,077

Reportable Segments Geographica

Reportable Segments Geographical information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Revenues	$ 16,610	$ 11,700	$ 13,209
Long-term assets, excluding goodwill and other intangibles	44,995	46,466	46,792
U.S.
Segment Reporting Information [Line Items]
Revenues	16,479	11,625	12,833
Long-term assets, excluding goodwill and other intangibles	44,916	46,384	46,709
Canada
Segment Reporting Information [Line Items]
Revenues	0	0	300
Long-term assets, excluding goodwill and other intangibles	1	1	1
Mexico and other foreign
Segment Reporting Information [Line Items]
Revenues	131	75	76
Long-term assets, excluding goodwill and other intangibles	$ 78	$ 81	$ 82

Leases - Lessee (Details)

Leases - Lessee (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Lease, Cost [Abstract]
Operating leases	$ 60	$ 55	$ 136
Short-term and variable leases	109	101	92
Total lease cost(a)	169	156	228
Capitalized lease costs	32	25	46
Lessee, Operating Lease, Description [Abstract]
Operating cash flows from operating leases	(137)	(131)	(182)
Investing cash flows from operating leases	(32)	(25)	(46)
ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion	59	20	399
Amortization of ROU assets	$ 47	$ 46	$ 75
Weighted average remaining lease term	10 years 4 months 20 days	11 years 6 months 21 days	13 years 4 months 24 days
Weighted average discount rate	3.95%	4.27%	4.31%
Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Other Assets, Noncurrent	Other Assets, Noncurrent
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
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Property, plant and equipment, net	Property, plant and equipment, net
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Total long-term debt – KMI and Subsidiaries	Total long-term debt – KMI and Subsidiaries
ROU assets	$ 315	$ 303
Short-term lease liability	45	40
Long-term lease liability	270	263
Finance lease assets	1	1
Finance lease liabilities	1	1
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2022	57
2023	51
2024	43
2025	36
2026	31
Thereafter	193
Total lease payments	411
Less: Interest	(96)
Present value of lease liabilities	315
KML and U.S. Portion of Cochin Pipeline System
Lessee, Operating Lease, Description [Abstract]
Removal of ROU assets and liabilities associated with the KML and U.S. Cochin Sale			$ (394)
Amount Excluding Cumulative Adjustment
Lessee, Operating Lease, Description [Abstract]
ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion	$ 59	$ 20	$ 102

Litigation and Environmental -

Litigation and Environmental - Other Commercial Matters (Details) - Pending Litigation $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)	Jun. 01, 2018projects
Freeport LNG Marketing, LLC Case
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 104
Hiland Partners Holdings, LLC
Loss Contingencies [Line Items]
Infrastructures to Build for Settlement | projects		10
Loss Contingency, Damages Sought, Value	$ 276

Litigation and Environmental _2

Litigation and Environmental - General (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Loss Contingency, Information about Litigation Matters [Abstract]
Estimated Litigation Liability	$ 231	$ 273

Litigation and Environmental _3

Litigation and Environmental - Portland (Details) - Portland Harbor Superfund Site, Willamette River, Portland, Oregon $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)TerminalsParties
Environmental Protection Agency | GATX Terminals Corporation (n/k/a 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 | GATX Terminals Corporation (n/k/a KMLT)
Site Contingency [Line Items]
Loss Contingency, Damages Sought, Value | $	$ 5
Pro Forma | Environmental Protection Agency | GATX Terminals Corporation (n/k/a KMLT)
Site Contingency [Line Items]
Environmental Remediation Expense | $	$ 2,800
Estimated Remedy Implementation Period	10 years

Litigation and Environmental _4

Litigation and Environmental - Uranium Mine (Details) - EPNG - mines	Apr. 16, 2019	Dec. 31, 1969
Number of Uranium Mines		20
Percentage of Response Costs	35.00%

Litigation and Environmental _5

Litigation and Environmental - Lower Passaic River (Details) - Pending Litigation $ in Millions	Oct. 04, 2021USD ($)mi	Mar. 04, 2016USD ($)mi	Dec. 31, 2021miParties
Lower Passaic River Study Area
Site Contingency [Line Items]
Miles of river			17
Number of Parties at a Joint Defense Group | Parties			44
Lower Passaic River Study Area | EPA preferred alternative estimate | Pro Forma
Site Contingency [Line Items]
Environmental Remediation Expense | $		$ 1,700
Lower Passaic River Study Area | Clean Up Implementation
Site Contingency [Line Items]
Estimated Remedy Implementation Period			6 years
Lower Passaic River Study Area, Lower Portion
Site Contingency [Line Items]
Miles of river		8	8
Upper Passaic River Study Area, Upper Portion | Pro Forma
Site Contingency [Line Items]
Miles of river	9
Environmental Remediation Expense | $	$ 440

Litigation and Environmental _6

Litigation and Environmental - Louisiana Governmental (Details) - Coastal Zone	Mar. 29, 2019Parties	Nov. 08, 2013Parties	Dec. 31, 2021cases
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 _7

Litigation and Environmental - Louisiana Landowner (Details) - Judicial District of Louisiana - Louisiana Landowner Coastal Erosion Litigation	Dec. 31, 2021cases
TGP
Loss Contingency, Pending Claims, Number	4
SNG
Loss Contingency, Pending Claims, Number	3
TGP and SNG
Loss Contingency, Pending Claims, Number	1

Litigation and Environmental _8

Litigation and Environmental - Walnut Creek (Details) - State of California - SFPP $ in Millions	Dec. 16, 2021USD ($)	Dec. 31, 2021	Dec. 08, 2020bbl
Environmental Remediation Estimated Spill Volume | bbl			1,000
Environmental Remediation Expense | $	$ 2.5
Estimated Remedy Implementation Period		18 months

Litigation and Environmental _9

Litigation and Environmental - Environmental Matters - General (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Loss Contingency, Information about Litigation Matters [Abstract]
Accrual for Environmental Loss Contingencies	$ 243	$ 250
Recorded Third-Party Environmental Recoveries Receivable	$ 12	$ 12

Uncategorized Items - kmi-20211

Label	Element	Value
Accounting Standards Update [Extensible Enumeration]	us-gaap_AccountingStandardsUpdateExtensibleList	Accounting Standards Update 2017-12 [Member]