Kinder Morgan (KMI) 10-K 5 Feb 21 2020 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2020	Feb. 04, 2021	Jun. 30, 2020
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
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			$ 29,459,747,400
Entity Common Stock, Shares Outstanding		2,264,450,220
Entity Central Index Key	0001506307
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
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
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
Entity Information [Line Items]
Title of 12(b) Security	2.250% Senior Notes due 2027
Trading Symbol	KMI 27 A
Security Exchange Name	NYSE

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues
Total Revenues	$ 11,700	$ 13,209	$ 14,144
Operating Costs, Expenses and Other
Cost of Sales	2,545	3,263	4,421
Operations and maintenance	2,475	2,591	2,522
Depreciation, depletion and amortization	2,164	2,411	2,297
General and administrative	648	590	601
Taxes, other than income taxes	378	426	345
Loss (gain) on divestitures and impairments, net (Note 3)	1,932	(942)	167
Other income, net	(2)	(3)	(3)
Total Operating Costs, Expenses and Other	10,140	8,336	10,350
Operating Income	1,560	4,873	3,794
Other Income (Expense)
Earnings from equity investments	780	101	617
Amortization of excess cost of equity investments	(140)	(83)	(95)
Interest, net	(1,595)	(1,801)	(1,917)
Other, net	56	75	107
Total Other Expense	(899)	(1,708)	(1,288)
Income Before Income Taxes	661	3,165	2,506
Income Tax Expense	(481)	(926)	(587)
Net Income	180	2,239	1,919
Net Income Attributable to Noncontrolling Interests	(61)	(49)	(310)
Net Income Attributable to Kinder Morgan, Inc.	119	2,190	1,609
Preferred Stock Dividends	0	0	(128)
Net Income Available to Common Stockholders	$ 119	$ 2,190	$ 1,481
Class P Shares
Basic and Diluted Earnings Per Common Share	$ 0.05	$ 0.96	$ 0.66
Basic and Diluted Weighted Average Common Shares Outstanding	2,263	2,264	2,216
Services
Revenues
Total Revenues	$ 7,618	$ 8,198	$ 7,955
Commodity sales
Revenues
Total Revenues	3,891	4,811	5,987
Other
Revenues
Total Revenues	$ 191	$ 200	$ 202

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net income	$ 180	$ 2,239	$ 1,919
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(75), $52, and $(34), respectively)	249	(177)	111
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $78, $(2), and $(25), respectively)	(255)	6	84
Foreign currency translation adjustments (net of tax expense of $—, $27, and $16, respectively)	0	108	141
Benefit plan adjustments (net of tax benefit (expense) of $19, $(23), and $(11), respectively)	(68)	77	2
Total other comprehensive (loss) income	(74)	14	338
Comprehensive income	106	2,253	2,257
Comprehensive income attributable to noncontrolling interests	(61)	(66)	(328)
Comprehensive income attributable to KMI	$ 45	$ 2,187	$ 1,929

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Change in fair value of hedge derivatives, tax benefit (expense)	$ (75)	$ 52	$ (34)
Reclassification of change in fair value of derivatives to net income, tax (expense) benefit	78	(2)	(25)
Foreign currency translation adjustments, tax expense	0	27	16
Benefit plan adjustments, tax benefit (expense)	$ (19)	$ 23	$ 11

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents	$ 1,184	$ 185
Restricted deposits	25	24
Marketable securities at fair value	0	925
Accounts receivable	1,293	1,379
Fair value of derivative contracts	185	84
Inventories	348	371
Other current assets	168	270
Total current assets	3,203	3,238
Property, plant and equipment, net	35,836	36,419
Investments	7,917	7,759
Goodwill	19,851	21,451
Other intangibles, net	2,453	2,676
Deferred income taxes	536	857
Deferred charges and other assets	2,177	1,757
Total Assets	71,973	74,157
Current liabilities
Current portion of debt	2,558	2,477
Accounts payable	837	914
Accrued interest	525	548
Accrued taxes	267	364
Accrued contingencies	307	89
Other current liabilities	580	708
Total current liabilities	5,074	5,100
Long-term debt
Outstanding	30,838	30,883
Debt fair value adjustments	1,293	1,032
Total long-term debt	32,131	31,915
Other long-term liabilities and deferred credits	2,202	2,253
Total long-term liabilities and deferred credits	34,333	34,168
Total Liabilities	39,407	39,268
Commitments and contingencies (Notes 9, 13, 17 and 18)
Redeemable Noncontrolling Interest	728	803
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,264,257,336 and 2,264,936,054 shares, respectively, issued and outstanding	23	23
Additional paid-in capital	41,756	41,745
Accumulated deficit	(9,936)	(7,693)
Accumulated other comprehensive loss	(407)	(333)
Total Kinder Morgan, Inc.’s stockholders’ equity	31,436	33,742
Noncontrolling interests	402	344
Total Stockholders’ Equity	31,838	34,086
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$ 71,973	$ 74,157

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
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)	2,264,257,336	2,264,936,054
Common stock, shares outstanding (in shares)	2,264,257,336	2,264,936,054

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Cash Flows From Operating Activities
Net income	$ 180	$ 2,239	$ 1,919
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	2,164	2,411	2,297
Deferred income taxes	345	717	405
Amortization of excess cost of equity investments	140	83	95
Change in fair market value of derivative contracts	(5)	(22)	77
Loss (gain) on divestitures and impairments, net (Note 3)	1,932	(942)	167
Earnings from equity investments	(780)	(101)	(617)
Distributions of equity investment earnings	633	590	499
Pension (contributions) net of noncash pension benefit expenses	(90)	14	(4)
Changes in components of working capital, net of the effects of acquisitions and dispositions
Accounts receivable	88	98	(45)
Income tax receivable	0	0	137
Inventories	16	4	15
Other current assets	49	100	(21)
Accounts payable	(19)	(198)	21
Accrued interest, net of interest rate swaps	(51)	(43)	(22)
Accrued taxes	(93)	(142)	241
Accrued contingencies and other current liabilities	(113)	(69)	73
Other, net	154	9	(194)
Net Cash Provided by Operating Activities	4,550	4,748	5,043
Cash Flows From Investing Activities
Capital expenditures	(1,707)	(2,270)	(2,904)
Sales of property, plant and equipment, investments, and other net assets, net of removal costs	1,069	110	104
Proceeds from the KML and U.S. Cochin Sale, net of cash disposed (Note 4)	0	1,527	0
Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments (Note 4)	0	(28)
Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments (Note 4)			2,998
Acquisitions of assets and investments	(16)	(79)	(39)
Contributions to investments	(386)	(1,299)	(433)
Distributions from equity investments in excess of cumulative earnings	154	333	237
Other, net	(25)	(8)	(31)
Net Cash Used in Investing Activities	(911)	(1,714)	(68)
Cash Flows From Financing Activities
Issuances of debt	3,888	8,036	14,751
Payments of debt	(3,996)	(11,224)	(14,591)
Debt issue costs	(25)	(10)	(42)
Cash dividends - common shares (Note 11)	(2,362)	(2,163)	(1,618)
Cash dividends - preferred shares (Note 11)	0	0	(156)
Repurchases of common shares	(50)	(2)	(273)
Contributions from investment partner and noncontrolling interests	14	151	200
Distributions to investment partner	(79)	(11)	0
Distribution to noncontrolling interests - KML distribution of the TMPL Sale proceeds	0	(879)	0
Distributions to noncontrolling interests - other	(15)	(55)	(78)
Other, net	(13)	(28)	(17)
Net Cash Used in Financing Activities	(2,638)	(6,185)	(1,824)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	(1)	29	(146)
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	1,000	(3,122)	3,005
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	209	3,331	326
Cash, Cash Equivalents, and Restricted Deposits, end of period	1,209	209	3,331
Cash and Cash Equivalents, beginning of period	185	3,280	264
Restricted Deposits, beginning of period	24	51	62
Cash and Cash Equivalents, end of period	1,184	185	3,280
Restricted Deposits, end of period	25	24	51
Noncash Investing and Financing Activities
ROU assets and operating lease obligations recognized (Note 17)	20	399
Marketable securities obtained as consideration for divestiture (Note 4)	0	892	0
Decrease in noncontrolling interests for distribution accrual	0	0	905
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,661	1,860	1,879
Cash paid (refunded) during the period for income taxes, net	$ 227	$ 372	$ (109)

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Millions, $ in Millions	Total	Preferred stock	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 ASUAccumulated other comprehensive loss	Impact of Adoption of ASUStockholders’ equity attributable to KMI	Adjusted Balance	Adjusted BalancePreferred stock	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, 2017	$ 35,124	$ 0	$ 22	$ 41,909	$ (7,754)	$ (541)	$ 33,636	$ 1,488	$ 66	$ 175	$ (109)	$ 66	$ 35,190	$ 0	$ 22	$ 41,909	$ (7,579)	$ (650)	$ 33,702	$ 1,488
Balance (shares) at Dec. 31, 2017		2	2,217											2	2,217
Repurchases of shares	(273)			(273)			(273)
Repurchases of shares (shares)			(15)
Mandatory conversion of preferred shares (shares)		(2)
Mandatory conversion of preferred shares	0		$ 1	(1)			0
Mandatory conversion of preferred shares (shares)			58
Restricted shares	65			65			65
Restricted shares (shares)			2
Net income	1,919				1,609		1,609	310
Distributions	(997)						0	(997)
Contributions	33						0	33
Preferred stock dividends	(128)				(128)		(128)
Common stock dividends	(1,618)				(1,618)		(1,618)
Other	2			1			1	1
Other comprehensive (loss) income	338					320	320	18
Balance at Dec. 31, 2018	$ 34,531	$ 0	$ 23	41,701	(7,716)	(330)	33,678	853	$ (4)	$ (4)		$ (4)	$ 34,527	$ 0	$ 23	$ 41,701	$ (7,720)	$ (330)	$ 33,674	$ 853
Balance (shares) at Dec. 31, 2018		0	2,262											0	2,262
Accounting Standards Update [Extensible List]	us-gaap:AccountingStandardsUpdate201712Member
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
Common stock 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	$ 0	$ 23	41,745	(7,693)	(333)	33,742	344
Balance (shares) at Dec. 31, 2019		0	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
Common stock 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	$ 0	$ 23	$ 41,756	$ (9,936)	$ (407)	$ 31,436	$ 402
Balance (shares) at Dec. 31, 2020		0	2,264

General (Notes)

General (Notes)	12 Months Ended
	Dec. 31, 2020
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, 2020
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. COVID-19 The COVID-19 pandemic-related reduction in energy demand and the dramatic decline in commodity prices that began to impact us in the first quarter of 2020 has continued to cause disruptions and volatility. Sharp declines in crude oil and natural gas production along with reduced demand for refined products due to the economic shutdown in the wake of the pandemic affected our business and continues to do so. While we have seen some meaningful recovery during the second half of the year in demand for refined products that we move through our terminals, significant uncertainty remains regarding the duration and extent of the impact of the pandemic (including the timing and distribution of vaccines) on the energy industry, including demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities. These events, among other factors, resulted in certain non-cash impairments charges during 2020 as further discussed in Note 3. 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 as it relates 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 Effective with our adoption of Accounting Standards Update (ASU) No. 2016-13, “ Financial Instruments–Credit Losses ” on January 1, 2020, 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 as of December 31, 2020 includes an evaluation of estimated impacts resulting from the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices, which we estimate could have a more significant impact to certain subset or pools of customers. Prior to the adoption of ASU No. 2016-13, generally our evaluation of appropriate reserves for our accounts receivable was based on a historical analysis of uncollected amounts and we recorded adjustments for changed circumstances and customer-specific information. Our allowance for credit losses as of December 31, 2020 and 2019 was $26 million and $9 million, respectively, 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. We generally 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. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 0.08% 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 generally 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 and Other Intangibles 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 estimated future cash flows expected to result from our use of the asset and its eventual disposition 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. Because the impairment test for long-lived assets held in use is based on 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 undiscounted cash flows, we typically use discounted cash flow analyses to determine if an impairment is required. 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 3 for further information. Equity Method of Accounting and Basis Differences We account for investments which we do not control, but do have the ability to exercise significant influence using the equity method of accounting. 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 this purpose, we have 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. 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. Prior to our adoption of ASU No. 2017-04, “ Intangibles - Goodwill and Other (Topic) 350: Simplifying the Test for Goodwill Impairment ” effective January 1, 2020, we performed a two-step quantitative test. Step 1 involved the quantitative test still applied under ASU No. 2017-04 described above. If the estimated fair value exceeded the carrying value, the reporting unit’s goodwill was not considered impaired. If the carrying value exceeded the estimated fair value, step 2 was performed to determine whether goodwill was impaired and, if so, the amount of the impairment. Step 2 involved calculating an implied fair value of goodwill by performing a hypothetical allocation of the estimated fair value of the reporting unit determined in step 1 to the respective tangible and intangible net assets of the reporting unit. The remaining implied goodwill was then compared to the actual carrying amount of the goodwill for the reporting unit. To the extent the carrying amount of goodwill exceeded the implied goodwill, the difference was the amount of the goodwill impairment. 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 both December 31, 2020 and 2019, the gross carrying amounts of these intangible assets was $4,074 million and $4,126 million, respectively, and the accumulated amortization was $1,621 million and $1,450 million, respectively, resulting in net carrying amounts of $2,453 million and $2,676 million, respectively. These intangible assets primarily consisted of customer contracts, relationships and agreements associated with our Natural Gas Pipelines and Product Pipelines business segments. Primarily, these contracts, relationships and agreements relate to the gathering of natural gas, and the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline and other refined petroleum products, petroleum coke, metals and ores. 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, 2020, 2019 and 2018, the amortization expense on our intangibles totaled $212 million, $214 million and $219 million, respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2021 – 2025) is approximately $228 million, $227 million, $222 million, $222 million, and $216 million, respectively. As of December 31, 2020, the weighted average amortization period for our intangible assets was approximately eleven 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 $319 million, $382 million and $363 million for the years ended December 31, 2020, 2019 and 2018, 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 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 Beginning January 1, 2019, operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Operating leases in effect prior to January 1, 2019 were recognized at the present va

Impairments and Losses and Gain

Impairments and Losses and Gains on Divestitures (Notes)	12 Months Ended
	Dec. 31, 2020
Impairments [Abstract]
Impairment of Goodwill, Long-lived assets and equity investments [Text Block]	3. Impairments and Losses and Gains on Divestitures During the years ended December 31, 2020, 2019, and 2018, we recorded net pre-tax losses of $1,922 million, gains of $285 million and losses of $437 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, 2020 amount primarily includes pre-tax goodwill and long-lived and intangible 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 4) and impairment losses of $1,014 million as further described below. During the first quarter 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 and conducted interim tests of the recoverability of goodwill for our CO 2 and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020, which resulted in impairments of $350 million on long-lived assets and $600 million on goodwill within our CO 2 business segment during the three months ended March 31, 2020. Additionally, we performed our annual goodwill impairment testing as of May 31, 2020. For our Natural Gas Pipelines Non-Regulated reporting unit, while no goodwill impairment was required as of March 31, 2020, the additional market and economic indicators existing at May 31, 2020, as further described below, resulted in the recognition of a goodwill impairment for that reporting unit during the three months ended June 30, 2020. 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, 2020, 2019 and 2018: Year Ended December 31, 2020 2019 2018 (In millions) Natural Gas Pipelines Impairment of goodwill(a) $ 1,000 $ — $ — Impairments of long-lived assets(b) — 290 636 Gains on divestitures of long-lived assets(c) (1) (967) (6) Impairments of equity investments(d) — 650 270 Impairments of inventory 11 — — Products Pipelines Impairments of long-lived and intangible assets 21 — — Terminals Impairments of long-lived and intangible assets(e) 5 — 59 Gains on divestitures of long-lived assets(f) (54) (335) (6) Gain on sale of equity investment interests (10) — — CO 2 Impairment of goodwill(a) 600 — — Impairments of long-lived assets(g) 350 74 79 Losses on divestitures of long-lived assets — 2 — Kinder Morgan Canada Loss (gain) on divestiture of long-lived assets(h) — 2 (595) Other losses (gains) on divestitures of long-lived assets — (1) — Pre-tax losses (gains) on divestitures and impairments, net $ 1,922 $ (285) $ 437 (a) 2020 amounts represent non-cash goodwill impairments associated with our Natural Gas Pipelines Non-Regulated and CO 2 reporting units (see “— Goodwill Impairments ” below). (b) 2019 amount represents non-cash impairments associated with certain gathering and processing assets in Oklahoma and northern Texas. 2018 amount represents non-cash impairment associated with certain gathering and processing assets in Oklahoma and a project write-off associated with the Utica Marcellus Texas pipeline. (c) 2019 amount includes a $957 million gain related to the sale of the Cochin Pipeline system. (d) Non-cash impairments of equity investments are included in “Earnings from equity investments” on our accompanying consolidated statements of income for the years ended December 31, 2019 and 2018. 2019 amount represents the non-cash impairment of our investment in Ruby. 2018 amount represents the non-cash impairment of our investment in Gulf LNG Holdings Group, LLC (Gulf LNG) which was driven by a ruling by an arbitration panel affecting a customer contract. Our share of earnings recognized by Gulf LNG on the respective customer contract is included in “Earnings from equity investments” on our accompanying consolidated statement of income for the year ended December 31, 2018. (e) 2018 amount primarily relates to non-cash impairments of certain northeast terminal assets. (f) 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. (g) 2020, 2019 and 2018 amounts represent impairments of oil and gas properties. (h) 2019 and 2018 amounts represent a working capital adjustment and gain on sale, respectively, associated with the TMPL Sale. Long-lived Assets As of March 31, 2020, for our CO 2 assets, the long-lived asset impairment test involved an assessment as to whether each asset’s net book value is expected to be recovered from the estimated undiscounted future cash flows. • 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. Certain oil and gas properties failed the first step. For these assets, 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. Our largest impairment for the year ended December 31, 2018 was a $600 million non-cash impairment in our Natural Gas Pipelines business segment driven by reduced cash flow estimates for some of our gathering and processing assets in Oklahoma identified during the period as a result of our decision to redirect our focus to other areas of our portfolio. Regarding our 2019 and 2018 impairments, for our long-lived assets, the reduced estimates triggered an impairment analysis, in each case, as we determined that our carrying value may no longer be recoverable. The impairment analysis for long-lived assets was based upon a two-step process as prescribed in the accounting standards. Step 1 involved comparing the undiscounted future cash flows to be derived from the asset group to the carrying value of the asset group. Based on the results of our step 1 test, we determined that the undiscounted future cash flows were less than the carrying value of the asset group. 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 Impairments Following are the considerations made in our goodwill analysis and testing. • 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, 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 test 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 such as those described above 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. Although we did not identify additional triggering events during the third or fourth quarters of 2020, in the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill which could result in further impairment charges. 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.

Divestitures (Notes)

Divestitures (Notes)	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Divestitures	4. Divestitures 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 fair market value as of December 31, 2019 of the Pembina common shares was $925 million and is reported as “Marketable securities at fair value” within our accompanying consolidated balance sheet as of December 31, 2019. Level 1 inputs in the fair value hierarchy were utilized to measure the fair value of the Pembina common shares. 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 August 31, 2018, KML completed the sale of the TMPL, the TMEP, the Puget Sound pipeline system for net cash consideration of C$4.43 billion (U.S.$3.4 billion), which is the contractual purchase price of C$4.5 billion net of a preliminary working capital adjustment (the “TMPL Sale”). These assets comprised our Kinder Morgan Canada business segment. We recognized a pre-tax gain from the TMPL Sale of $595 million within “Loss (gain) on impairments and divestitures, net” in our accompanying consolidated statement of income during the year ended December 31, 2018. During the first quarter of 2019, KML settled the remaining C$37 million (U.S.$28 million) of working capital adjustments which amount was substantially accrued for as of December 31, 2018. On January 3, 2019, KML distributed the net proceeds from the TMPL Sale 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.

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes	5. Income Taxes The components of “Income Before Income Taxes” are as follows: Year Ended December 31, 2020 2019 2018 (In millions) U.S. $ 663 $ 2,482 $ 1,739 Foreign (2) 683 767 Total Income Before Income Taxes $ 661 $ 3,165 $ 2,506 Components of the income tax provision applicable for federal, foreign and state taxes are as follows: Year Ended December 31, 2020 2019 2018 (In millions) Current tax expense (benefit) Federal $ (20) $ (2) $ (22) State 9 10 (45) Foreign(a) 147 201 249 Total 136 209 182 Deferred tax expense (benefit) Federal 440 682 425 State 49 66 55 Foreign(a) (144) (31) (75) Total 345 717 405 Total tax provision $ 481 $ 926 $ 587 (a) Our Canadian income tax (benefit) expense was $(4) million, $165 million and $168 million for the years ended December 31, 2020, 2019 and 2018, respectively. The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows: Year Ended December 31, 2020 2019 2018 (In millions, except percentages) Federal income tax $ 139 21.0 % $ 665 21.0 % $ 526 21.0 % Increase (decrease) as a result of: Taxes on foreign earnings, net of federal benefit 2 0.3 % 139 4.4 % 131 5.2 % Net effects of noncontrolling interests (13) (2.0) % (10) (0.3) % (65) (2.6) % State income tax, net of federal benefit 52 7.9 % 68 2.1 % 46 1.8 % Dividend received deduction (27) (4.1) % (39) (1.1) % (31) (1.2) % Adjustments to uncertain tax positions 3 0.5 % (5) (0.2) % (47) (1.9) % Nondeductible goodwill 336 50.8 % 108 3.4 % 58 2.3 % General business credit — — % — — % (64) (2.6) % Federal refunds (20) (3.0) % — — % — — % Other 9 1.4 % — — % 33 1.4 % Total $ 481 72.8 % $ 926 29.3 % $ 587 23.4 % Deferred tax assets and liabilities result from the following: December 31, 2020 2019 (In millions) Deferred tax assets Employee benefits $ 224 $ 208 Net operating loss carryforwards 1,484 1,261 Tax credit carryforwards 257 258 Other 242 241 Valuation allowances (138) (155) Total deferred tax assets 2,069 1,813 Deferred tax liabilities Property, plant and equipment 414 385 Investments 1,084 529 Other 35 42 Total deferred tax liabilities 1,533 956 Net deferred tax assets $ 536 $ 857 Deferred Tax Assets and Valuation Allowances We have 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 as of December 31, 2020. As of December 31, 2019, we had deferred tax assets of $1,261 million related to net operating loss carryovers, $258 million related to general business and foreign tax credits, and $117 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 in 2020 by $17 million, primarily due to $9 million of statute expirations for state net operating losses and $8 million of currency fluctuations on foreign net operating losses. Expiration Periods for Deferred Tax Assets: As of December 31, 2020, we have U.S. federal net operating loss carryforwards of $2.6 billion that will be carried forward indefinitely and $3.4 billion that will expire from 2021 - 2037; state losses of $3.8 billion which will expire from 2021 - 2039; and foreign losses of $83 million which will be carried forward indefinitely. We also have $240 million of general business credits which will expire from 2021 - 2039; and approximately $17 million of foreign tax credits, which will expire from 2021 - 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 $18 million, $16 million and $34 million as of December 31, 2020, 2019 and 2018, respectively. Reductions based on settlements with taxing authorities were $0 million, $21 million and $73 million for the years ended December 31, 2020, 2019 and 2018, respectively. All of the $18 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 decrease by approximately $1 million during the next year to approximately $17 million, primarily due to releases from statute expirations, offset by additions for state filing positions taken in prior years. We are subject to taxation, and have tax years open to examination for the periods 2016-2019 in the U.S., which include net operating loss utilization from earlier years, 2006-2019 in various states and 2007-2019 in various foreign jurisdictions.

Property, Plant and Equipment (

Property, Plant and Equipment (Notes)	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, net	6. Property, Plant and Equipment, net Classes and Depreciation As of December 31, 2020 and 2019, our property, plant and equipment, net consisted of the following: December 31, 2020 2019 (In millions) Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 20,339 $ 19,856 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 26,142 25,791 Other(a) 5,188 5,360 Accumulated depreciation, depletion and amortization (17,818) (16,950) 33,851 34,057 Land and land rights-of-way 1,403 1,356 Construction work in process 582 1,006 Property, plant and equipment, net $ 35,836 $ 36,419 (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, 2020 and 2019, property, plant and equipment, net included $12,160 million and $12,229 million, respectively, of assets which were regulated by the FERC. Depreciation, depletion, and amortization expense charged against property, plant and equipment was $1,928 million, $2,176 million, and $2,057 million for the years ended December 31, 2020, 2019, and 2018, respectively. Asset Retirement Obligations As of December 31, 2020 and 2019, we recognized asset retirement obligations in the aggregate amount of $214 million and $218 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, 2020
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, 2020 and 2019, and our earnings (loss) from these respective investments for the years ended December 31, 2020, 2019 and 2018: Ownership Interest Equity Investments Earnings (Loss) from December 31, December 31, Year Ended December 31, 2020 2020 2019 2020 2019 2018 (In millions) Citrus Corporation 50% $ 1,849 $ 1,856 $ 165 $ 157 $ 169 SNG 50% 1,532 1,473 129 140 141 NGPL Holdings LLC(a) 50% 803 721 116 81 66 Gulf Coast Express Pipeline LLC 34% 638 656 90 37 2 Permian Highway Pipeline 27% 632 309 — — — MEP 50% 416 439 (6) 15 31 Gulf LNG(b) 50% 361 361 19 17 (61) Products (SE) Pipe Line Corporation(c) 51% 357 348 43 58 55 Utopia Holding LLC 50% 329 335 20 20 14 EagleHawk 25% 275 285 17 17 7 Watco Companies, LLC (d) 70 185 16 19 21 Cortez Pipeline Company 53% 25 26 24 35 36 FEP 50% 16 102 70 59 55 Ruby(e) (f) 1 41 15 (609) 26 All others 613 622 62 55 55 Total investments $ 7,917 $ 7,759 $ 780 $ 101 $ 617 Amortization of excess cost $ (140) $ (83) $ (95) (a) Investment in NGPL Holdings LLC (NGPL Holdings) includes a related party promissory note receivable with a principal amount of $500 million as of December 31, 2020. On October 1, 2019, NGPL Holdings issued a non-cash related party promissory note with a principal amount of $500 million as a capital distribution. The related party promissory note accrues interest at 6.75% and is payable quarterly. For the years ended December 31, 2020 and 2019, we recognized $34 million and $8 million, respectively, of interest within “Earnings from equity investments” on our accompanying consolidated statements of income. (b) The loss from Gulf LNG for the year ended December 31, 2018 includes our share of earnings recognized due to a ruling by an arbitration panel affecting a customer contract. 2018 amount also includes a non-cash impairment charge of $270 million (pre-tax) driven by this ruling. See Note 3 for more information. (c) Previously known as Plantation Pipe Line Company. (d) 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. (e) The loss from Ruby for the year ended December 31, 2019 amount includes a non-cash impairment charge of $650 million (pre-tax) related to our investment. See Note 3 for more information. (f) 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 2020 2019 2018 (In millions) Revenues $ 5,076 $ 4,906 $ 4,898 Costs and expenses 4,249 3,508 3,245 Net income $ 827 $ 1,398 $ 1,653 December 31, Balance Sheet 2020 2019 (In millions) Current assets $ 1,013 $ 1,195 Non-current assets 25,069 24,743 Current liabilities 1,787 2,125 Non-current liabilities 9,734 9,670 Partners’/owners’ equity 14,561 14,143

Goodwill (Notes)

Goodwill (Notes)	12 Months Ended
	Dec. 31, 2020
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, 2020 and 2019 are summarized by reporting unit as follows: Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated CO 2 Products Pipelines Products Pipelines Terminals Terminals Total (In millions) Gross goodwill $ 15,892 $ 5,812 $ 1,528 $ 2,125 $ 221 $ 1,573 $ 27,151 Accumulated impairment losses (1,643) (1,597) — (1,197) (70) (679) (5,186) December 31, 2018 14,249 4,215 1,528 928 151 894 21,965 Divestitures(a) — (422) — — — (92) (514) Transfer(b) — (450) — 450 — — — December 31, 2019 14,249 3,343 1,528 1,378 151 802 21,451 Impairments(c) — (1,000) (600) — — — (1,600) Transfer — — — — — — — December 31, 2020 14,249 2,343 928 1,378 151 802 19,851 Gross goodwill 15,892 4,940 1,528 2,575 221 1,481 26,637 Accumulated impairment losses (1,643) (2,597) (600) (1,197) (70) (679) (6,786) December 31, 2020 $ 14,249 $ 2,343 $ 928 $ 1,378 $ 151 $ 802 $ 19,851 (a) 2019 includes $514 million related to the KML and U.S. Cochin Sale. See Note 4 for more information. (b) Effective January 1, 2019, for segment reporting purposes, certain assets were transferred among our business segments which resulted in the transfer of goodwill from the Natural Gas Pipelines Non-Regulated reporting unit to the Products Pipelines reporting unit. See Note 16 for more information. (c) See Note 3 “ Impairments and Losses and Gains on Divestitures—Goodwill Impairments ” for further information regarding our goodwill impairments.

Debt (Notes)

Debt (Notes)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Debt	9. Debt The following table provides detail on the principal amount of our outstanding debt balances: December 31, 2020 2019 (In millions, Credit facility and commercial paper borrowings(a) $ — $ 37 Corporate senior notes(b) 6.85%, due February 2020 — 700 6.50%, due April 2020 — 535 5.30%, due September 2020 — 600 6.50%, due September 2020 — 349 5.00%, due February 2021 750 750 3.50%, due March 2021(c) 750 750 5.80%, due March 2021 400 400 5.00%, due October 2021 500 500 4.15%, due March 2022 375 375 1.50%, due March 2022(d) 917 841 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 6.70%, due February 2027 7 7 2.25%, due March 2027(d) 611 561 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(f) 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 (continued) December 31, 2020 2019 5.20%, due March 2048 750 750 3.25%, due August 2050(f) 500 — 7.45%, due March 2098 26 26 TGP senior notes(b) 7.00%, due March 2027 300 300 7.00%, due October 2028 400 400 2.90%, due March 2030(g) 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 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 2020 through December 2035 380 395 Trust I Preferred Securities, 4.75%, due March 2028(h) 221 221 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(i) — 100 Other miscellaneous debt(j) 254 258 Total debt – KMI and Subsidiaries 33,396 33,360 Less: Current portion of debt(k) 2,558 2,477 Total long-term debt – KMI and Subsidiaries(l) $ 30,838 $ 30,883 (a) See “—Current portion of debt” below for further details regarding the outstanding credit facility 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, 2020 exchange rate of 1.2216 U.S. dollars per Euro and at the December 31, 2019 exchange rate of 1.1213 U.S. dollars per Euro. As of December 31, 2020 and 2019, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in increases to our debt balance of $102 million and $26 million, respectively, related to the 1.50% series and increases of $68 million and $18 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) During the year ended December 31, 2019, we entered into a floating-to-fixed interest rate swap agreement which was designated as a cash flow hedge. (f) On August 5, 2020, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 2.00% senior notes due 2031 and $500 million aggregate principal amount of 3.25% senior notes due 2050 and received combined net proceeds of $1,226 million. (g) On February 24, 2020, TGP issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 2030 and received net proceeds of $991 million. (h) Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2020, 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, 2020 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. (i) As of December 31, 2019, KMGP had outstanding 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057, which was redeemed including accrued dividends on January 15, 2020. (j) Includes finance lease obligations with monthly installments. The lease terms expire between 2024 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, 2020 and 2019, increased our combined debt balances by $1,293 million and $1,032 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, 2020 2019 (In millions, unless otherwise stated) $4 billion credit facility due November 16, 2023 $ — $ — Commercial paper notes(a) — 37 Current portion of senior notes 6.85%, due February 2020 — 700 6.50%, due April 2020 — 535 5.30%, due September 2020 — 600 6.50%, due September 2020 — 349 5.00%, due February 2021 750 — 3.50%, due March 2021(b) 750 — 5.80%, due March 2021 400 — 5.00%, due October 2021 500 — Trust I Preferred Securities, 4.75% due March 2028(c) 111 111 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(d) — 100 Current portion of other debt 47 45 Total current portion of debt $ 2,558 $ 2,477 (a) Weighted average interest rates on borrowings outstanding as of December 31, 2019 was 1.90%. (b) On January 4, 2021, we repaid our $750 million senior corporate notes. (c) 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. (d) In December 2019, we notified the holder of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as current in our accompanying balance sheet as of December 31, 2019. We redeemed these securities including accrued dividends on January 15, 2020. 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 As of December 31, 2020, we had borrowing capacity of approximately $3.9 billion under our $4 billion revolving credit facility. 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 facility bear interest at either (i) LIBOR adjusted for a eurocurrency funding reserve plus an applicable margin ranging from 1.000% to 2.000% 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 1.000% 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 0.300%. 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, 2020, we had no borrowings outstanding under our credit facility, no borrowings outstanding under our commercial paper program and $82 million in letters of credit. Our availability under this facility as of December 31, 2020 was approximately $3.9 billion. As of December 31, 2020, 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, 2020, are summarized as follows: Year Total (In millions) 2021 $ 2,558 2022 2,575 2023 3,250 2024 1,925 2025 1,566 Thereafter 21,522 Total $ 33,396 Debt Fair Value Adjustments The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets: December 31, 2020 2019 (In millions) Purchase accounting debt fair value adjustments $ 546 $ 599 Carrying value adjustment to hedged debt 702 359 Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a) 240 257 Unamortized debt discounts, net (76) (67) Unamortized debt issuance costs (119) (116) Total debt fair value adjustments $ 1,293 $ 1,032 (a) As of December 31, 2020, the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 14 years. Fair Value of Financial Instruments The carrying value and estimated fair value of our outstanding debt balances is disclosed below: December 31, 2020 December 31, 2019 Carrying Estimated Carrying Estimated (In millions) Total debt $ 34,689 $ 39,622 $ 34,392 $ 38,016 We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2020 and 2019. Interest Rates, Interest Rate Swaps and Contingent Debt The weighted average interest rate on all of our borrowings was 4.86% during 2020 and 5.27% during 2019. 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, 2020
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 Shares Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors We have a Kinder Morgan, Inc. 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 250,000. During 2020, 2019 and 2018, we made restricted Class P common stock grants to our non-employee directors of 14,570, 23,100 and 25,800, respectively. These grants were valued at time of issuance at $0.3 million, $0.4 million and $0.5 million, respectively. All of the restricted stock awards made to non-employee directors vest during a 6-month period. Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan The Kinder Morgan, Inc. 2015 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 33,000,000. 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, 2019 12,414 $ 20.07 Granted 4,532 15.10 Vested (4,035) 21.71 Forfeited (229) 18.99 Outstanding at December 31, 2020 12,682 $ 17.79 The following table sets forth additional information related to our restricted stock awards excluding that issued to non-employee directors: Year Ended December 31, 2020 2019 2018 (In millions, except per share amounts) Weighted average grant date fair value per share $ 15.10 $ 20.46 $ 17.73 Intrinsic value of awards vested during the year 59 87 42 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) 2021 4,216 2022 3,051 2023 4,775 2024 127 2025 513 Total Outstanding 12,682 During 2020, 2019 and 2018, we recorded $73 million, $62 million and $63 million, respectively, in expense related to restricted stock awards and capitalized approximately $11 million, $12 million and $13 million, respectively. We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements. At December 31, 2020, unrecognized restricted stock awards compensation costs, less estimated forfeitures, was approximately $102 million with a weighted average remaining amortization period of 2.08 years. Pension and Other Postretirement Benefit (OPEB) Plans Savings Plan We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain collectively bargained participants receive Company contributions in accordance with collective bargaining agreements. A participant becomes fully vested in Company contributions after two years and may take a distribution upon termination of employment or retirement. The total cost for our savings plan was approximately $53 million, $50 million, and $48 million for the years ended December 31, 2020, 2019 and 2018, 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, 2020 and 2019: Pension Benefits OPEB 2020 2019 2020 2019 (In millions) Change in benefit obligation: Benefit obligation at beginning of period $ 2,696 $ 2,566 $ 333 $ 339 Service cost 59 53 1 1 Interest cost 71 96 8 12 Actuarial loss (gain) 198 159 (17) 10 Benefits paid (180) (178) (29) (32) Participant contributions — — 2 2 Medicare Part D subsidy receipts — — 1 1 Benefit obligation at end of period 2,844 2,696 299 333 Change in plan assets: Fair value of plan assets at beginning of period 2,076 1,864 333 306 Actual return on plan assets 178 330 47 49 Employer contributions 125 60 7 7 Participant contributions — — 2 2 Medicare Part D subsidy receipts — — 1 1 Benefits paid (180) (178) (29) (32) Fair value of plan assets at end of period 2,199 2,076 361 333 Funded status - net (liability) asset at December 31, $ (645) $ (620) $ 62 $ — 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. The 2019 net actuarial loss for the pension plans was primarily due to a decrease in the weighted average discount rate used to determine the benefit obligations as of December 31, 2019, partially offset by a change in the mortality assumption. The 2019 net actuarial loss for the OPEB plans was primarily due to a decrease in the weighted average discount rate used to determine the benefit obligations as of December 31, 2019, partially offset by a change in the claims cost and mortality assumptions. Components of Funded Status . The following table details the amounts recognized in our balance sheets at December 31, 2020 and 2019 related to our pension and OPEB plans: Pension Benefits OPEB 2020 2019 2020 2019 (In millions) Non-current benefit asset(a) $ — $ — $ 269 $ 231 Current benefit liability — — (19) (18) Non-current benefit liability (645) (620) (188) (213) Funded status - net (liability) asset at December 31, $ (645) $ (620) $ 62 $ — (a) 2020 and 2019 OPEB amounts include $46 million and $39 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, 2020 and 2019 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets: Pension Benefits OPEB 2020 2019 2020 2019 (In millions) Unrecognized net actuarial (loss) gain $ (674) $ (557) $ 153 $ 123 Unrecognized prior service (cost) credit (2) (3) 9 12 Accumulated other comprehensive (loss) income $ (676) $ (560) $ 162 $ 135 Our accumulated benefit obligation for our pension plans was $2,804 million and $2,659 million at December 31, 2020 and 2019, respectively. Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $255 million and $288 million at December 31, 2020 and 2019, respectively. The fair value of these plans’ assets was approximately $48 million and $57 million at December 31, 2020 and 2019, 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, 2020, the allowable range for asset allocations in effect for our pension plan were 31% to 55% equity, 37% to 57% fixed income, 0% to 5% cash, 0% to 2% alternative investments and 0% to 10% company securities (KMI Class P common stock and/or debt securities). As of December 31, 2020, the allowable range for asset allocations in effect for our OPEB plans were 46% to 68% equity, 25% to 50% fixed income and 0% to 22% cash. 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, 2020 and 2019: Pension Assets 2020 2019 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Short-term investment funds $ — $ 77 $ 77 $ — $ 50 $ 50 Equities(a) 249 — 249 296 — 296 Fixed income securities(b) — 425 425 — 405 405 Derivatives — 11 11 — 12 12 Subtotal $ 249 $ 513 762 $ 296 $ 467 763 Measured at NAV(c) Common/collective trusts(d) 1,184 1,069 Private investment funds(e) 208 200 Private limited partnerships(f) 45 44 Subtotal 1,437 1,313 Total plan assets fair value $ 2,199 $ 2,076 (a) Plan assets include $83 million and $129 million of KMI Class P common stock for 2020 and 2019, respectively. (b) Plan assets include $1 million of KMI debt securities for both 2020 and 2019. (c) Plan assets which used NAV as a practical expedient to measure fair value. (d) Common/collective trust funds were invested in approximately 29% fixed income and 71% equity in 2020 and 32% fixed income and 68% equity in 2019. (e) Private investment funds were invested in approximately 71% fixed income and 29% equity in 2020 and 73% fixed income and 27% equity in 2019. (f) Includes assets invested in real estate, venture and buyout funds. OPEB Assets 2020 2019 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Cash $ — $ — $ — $ 1 $ — $ 1 Short-term investment funds — 5 5 — 5 5 Equities — — — 25 — 25 Fixed income securities — — — — 17 17 Mutual funds(a) — — — 11 — 11 Subtotal $ — $ 5 5 $ 37 $ 22 59 Measured at NAV(b) Common/collective trusts(c) 356 274 Subtotal 356 274 Total plan assets fair value $ 361 $ 333 (a) Includes mutual funds which are invested in equities and fixed income securities. (b) Plan assets which used NAV as a practical expedient to measure fair value. (c) Common/collective trust funds were invested in approximately 65% equity and 35% fixed income securities for 2020 and 64% equity and 36% fixed income securities for 2019. Expected Payment of Future Benefits and Employer Contributions . As of December 31, 2020, we expect to make the following benefit payments under our plans: Fiscal year Pension Benefits OPEB(a) (In millions) 2021 $ 239 $ 30 2022 238 28 2023 225 27 2024 219 25 2025 211 23 2026 - 2030 902 94 (a) Includes a reduction of approximately $1 million in each of the years 2021 through 2025 and approximately $6 million in aggregate for the period 2026 - 2030 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. In 2021, we expect to contribute approximately $56 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 2020, 2019 and 2018: Pension Benefits OPEB 2020 2019 2018 2020 2019 2018 (In millions) Assumptions related to benefit obligations: Discount rate 2.27 % 3.17 % 4.26 % 2.08 % 3.03 % 4.16 % 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 Assumptions related to benefit costs: Discount rate for benefit obligations 3.17 % 4.26 % 3.56 % 3.03 % 4.16 % 3.48 % Discount rate for interest on benefit obligations 2.71 % 3.89 % 3.13 % 2.63 % 3.83 % 3.08 % Discount rate for service cost 3.24 % 4.28 % 3.56 % 3.48 % 4.51 % 3.82 % Discount rate for interest on service cost 2.80 % 3.93 % 3.14 % 3.39 % 4.46 % 3.76 % Expected return on plan assets(a) 6.75 % 7.25 % 7.25 % 6.50 % 6.50 % 7.08 % Rate of compensation increase 3.50 % 3.50 % 3.50 % n/a n/a n/a Interest crediting rate 3.71 % 3.90 % 2.71 % 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%, 27% and 21% for 2020, 2019 and 2018, respectively. 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 5.80% which gradually decreases to 4.50% by the year 2038. 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 2020 2019 2018 2020 2019 2018 (In millions) Components of net benefit cost (credit): Service cost $ 59 $ 53 $ 52 $ 1 $ 1 $ 1 Interest cost 71 96 84 8 12 12 Expected return on assets (137) (129) (149) (16) (16) (20) Amortization of prior service cost (credit) 1 — — (5) (4) (4) Amortization of net actuarial loss (gain) 40 54 40 (13) (11) (6) Net benefit cost (credit) 34 74 27 (25) (18) (17) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 157 (42) 105 (43) (17) (32) Amortization or settlement recognition of net actuarial (loss) gain (40) (54) (87) 13 11 3 Amortization of prior service (cost) credit (1) — (1) 3 2 3 Total recognized in total other comprehensive loss (income)(a) 116 (96) 17 (27) (4) (26) Total recognized in net benefit cost (credit) and other comprehensive loss (income) $ 150 $ (22) $ 44 $ (52) $ (22) $ (43) (a) Excludes $2 million for the year ended December 31, 2020 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 $6 million for the year ended December 31, 2020 and $8 million for each of the years ended December 31, 2019 and 2018. 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, 2020
Stockholders' Equity Note [Abstract]
Stockholders' Equity	11. Stockholders' Equity Mandatory Convertible Preferred Stock As of October 26, 2018, all of our issued and outstanding 1,600,000 shares of 9.75% Series A mandatory convertible preferred stock, with a liquidating preference of $1,000 per share were converted into common stock either at the option of the holders before or automatically on October 26, 2018. Based on the market price of our common stock at the time of conversion, our Series A Preferred Shares converted into approximately 58 million common shares. We paid all dividends on our mandatory convertible preferred stock in cash. Common Equity As of December 31, 2020, our common equity consisted of our Class P common stock. On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. During the years ended December 31, 2020, 2019 and 2018, we repurchased approximately 4 million, 0.1 million and 15 million, respectively, of our Class P shares for approximately $50 million, $2 million and $273 million, respectively. Since December 2017, in total, we have repurchased approximately 32 million of our Class P 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 of our Class P common stock having an aggregate offering of up to $5.0 billion from time to time during the term of this agreement. During the years ended December 31, 2020, 2019 and 2018 we did not issue any Class P common stock under this agreement. KMI Common Stock Dividends Holders of our common stock participate in any dividend declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends: Year Ended December 31, 2020 2019 2018 Per common share cash dividend declared for the period $ 1.05 $ 1.00 $ 0.80 Per common share cash dividend paid in the period 1.0375 0.95 0.725 On January 20, 2021, our board of directors declared a cash dividend of $0.2625 per common share for the quarterly period ended December 31, 2020, which is payable on February 16, 2021 to shareholders of record as of February 1, 2021. 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, 2017 $ (27) $ (189) $ (325) $ (541) Other comprehensive gain (loss) before reclassifications 111 (89) (31) (9) Losses reclassified from accumulated other comprehensive loss(a) 84 223 22 329 Impact of adoption of ASU 2018-02 (see below) (4) (36) (69) (109) Net current-period change in accumulated other comprehensive (loss) income 191 98 (78) 211 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) (a) Amounts for foreign currency translation adjustments and pension and other postretirement liability adjustments reflect the deferred losses recognized in income during the year ended December 31, 2018 related to the TMPL Sale. 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 dividends during the years ended December 31, 2019 and 2018, on its restricted voting shares to the public valued at $17 million and $52 million, respectively, of which $17 million and $38 million, respectively, was paid in cash. The remaining value of $14 million for the year ended December 31, 2018, respectively, was paid in 1,092,791 KML restricted voting shares. KML also paid dividends to the public on its preferred shares of $22 million and $21 million for the years ended December 31, 2019 and 2018. 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. Adoption of Accounting Pronouncements On January 1, 2018, we adopted ASU No. 2017-05, “ Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets .” This ASU clarifies the scope and application of ASC 610-20 on contracts for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU also clarifies that the derecognition of all businesses is in the scope of ASC 810 and defines an “in substance nonfinancial asset.” We utilized the modified retrospective method to adopt the provisions of this ASU, which required us to apply the new standard to (i) all new contracts entered into after January 1, 2018, and (ii) to contracts that were not completed contracts as of January 1, 2018 through a cumulative adjustment to our “Accumulated deficit” balance. The cumulative effect of the adoption of this ASU was a $66 million, net of income taxes, adjustment to our beginning “Accumulated deficit” balance as presented in our consolidated statement of stockholders’ equity for the year ended December 31, 2018. This ASU also required us to classify EIG Global Energy Partners’ (EIG) cumulative contribution to ELC as mezzanine equity, which we have included as “Redeemable Noncontrolling Interest” on our consolidated balance sheets as of December 31, 2020 and 2019, as EIG has the right to redeem their interests for cash under certain conditions. On January 1, 2018, we adopted ASU No. 2018-02, “ Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income .” Our accounting policy for the release of stranded tax effects in accumulated other comprehensive income is on an aggregate portfolio basis. This ASU permits companies to reclassify the income tax effects of the 2017 Tax Reform on items within accumulated other comprehensive income to retained earnings. The FASB refers to these amounts as “stranded tax effects.” Only the stranded tax effects resulting from the 2017 Tax Reform are eligible for reclassification. The adoption of this ASU resulted in a $109 million reclassification adjustment of stranded income tax effects from “Accumulated other comprehensive loss” to “Accumulated deficit” on our consolidated statement of stockholders’ equity for the year ended December 31, 2018.

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2020
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 balances and 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, 2020 2019 (In millions) Balance sheet location Accounts receivable $ 41 $ 38 Other current assets 6 — Deferred charges and other assets 109 86 $ 156 $ 124 Current portion of debt $ 6 $ 6 Accounts payable 25 23 Other current liabilities 4 3 Long-term debt 154 157 Other long-term liabilities and deferred credits 48 41 $ 237 $ 230 Year Ended December 31, 2020 2019 2018 (In millions) Income statement location Revenues $ 206 $ 269 $ 265 Operating Costs, Expenses and Other Costs of sales $ 116 $ 75 $ 63 Other operating expenses 119 132 91

Commitments and Contingent Liab

Commitments and Contingent Liabilities (Notes)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	Commitments and Contingent Liabilities Rights-Of-Way (ROW) Obligations Our ROW 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 ROW obligations were $172 million as of December 31, 2020. 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, 2020 and 2019, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $217 million and $330 million, respectively. December 31, 2020 and 2019 amounts are represented by our proportional share of the debt obligations of three equity investees. 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, 2020 and 2019 included $122 million and $128 million, respectively, for 100% guaranteed debt obligations for a subsidiary of our equity investee, Cortez Pipeline Company. Guarantees and Indemnifications Our equity investee, SNG, has $300 million of debt maturing in June 2021 that it anticipates refinancing. We currently have a commitment to SNG to fund $150 million if SNG is unable to refinance or otherwise satisfy its obligation. 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, 2020
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, 2020, 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 (20.4) MMBbl Crude oil basis (2.2) MMBbl Natural gas fixed price (30.1) Bcf Natural gas basis (20.0) Bcf NGL fixed price (1.1) MMBbl Derivatives not designated as hedging contracts Crude oil fixed price (5.6) MMBbl Crude oil basis (6.8) MMBbl Natural gas fixed price (6.7) Bcf Natural gas basis (5.5) Bcf NGL fixed price (1.0) MMBbl As of December 31, 2020, 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 2024. 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, 2020: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments Fixed-to-variable interest rate contracts(a) $ 7,625 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 2,500 Mark-to-Market December 2021 (a) The principal amount of hedged senior notes consisted of $900 million included in “Current portion of debt” and $6,725 million included in “Long-term debt” on our accompanying consolidated balance sheet. 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, 2020: 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, 2020 2019 2020 2019 Location Fair value Fair value (In millions) Derivatives designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 42 $ 31 $ (33) $ (43) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 33 17 (8) (8) Subtotal 75 48 (41) (51) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 119 45 (3) — Deferred charges and other assets/(Other long-term liabilities and deferred credits) 575 313 (7) (1) Subtotal 694 358 (10) (1) Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) — — (6) (6) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 138 46 — — Subtotal 138 46 (6) (6) Total 907 452 (57) (58) Derivatives not designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 24 8 (21) (7) Total derivatives $ 931 $ 460 $ (78) $ (65) 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 Gross amount Contracts available for netting Cash collateral held(b) Net amount (In millions) 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 As of December 31, 2019 Energy commodity derivative contracts(a) $ 19 $ 37 $ — $ 56 $ (19) $ (21) $ 16 Interest rate contracts — 358 — 358 — — 358 Foreign currency contracts — 46 — 46 (6) — 40 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, 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 — — As of December 31, 2019 Energy commodity derivative contracts(a) (3) (55) — (58) 19 — (39) Interest rate contracts — (1) — (1) — — (1) 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, 2020 2019 2018 (In millions) Interest rate contracts Interest, net $ 335 $ 340 $ (122) Hedged fixed rate debt(a) Interest, net $ (343) $ (353) $ 113 (a) As of December 31, 2020, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $702 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, 2020 2019 2018 2020 2019 2018 (In millions) (In millions) Energy commodity derivative contracts $ 240 $ (168) $ 201 Revenues—Commodity sales $ 222 $ 16 $ (59) Costs of sales (14) 5 21 Interest rate contracts(c) (8) (1) 3 Earnings from equity investments(c) — 2 (4) Foreign currency contracts 92 (60) (59) Other, net 125 (31) (67) Total $ 324 $ (229) $ 145 Total $ 333 $ (8) $ (109) (a) We expect to reclassify an approximate $9 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2020 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 year ended December 31, 2019, we recognized a $12 million gain associated with a write-down of hedged inventory. During the year ended December 31, 2018, we recognized a $3 million loss as a result of our equity investment’s forecasted transactions being probable of not occurring and a $21 million gain 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, 2020 2019 2018 2020 2019 2018 (In millions) (In millions) Foreign currency contracts $ — $ (8) $ 91 Loss (gain) on impairments and divestitures, net $ — $ 83 $ 26 Total $ — $ (8) $ 91 Total $ — $ 83 $ 26 (a) During the year ended December 31, 2019, we recognized an $83 million gain related to the KML and U.S. Cochin Sale. During the year ended December 31, 2018, we recognized a $26 million gain related to the TMPL Sale. See Note 4. Derivatives not designated as accounting hedges Location Gain/(Loss) recognized in income on derivatives Year Ended December 31, 2020 2019 2018 (In millions) Energy commodity derivative contracts Revenues—Commodity sales $ (1) $ 33 $ (9) Costs of sales 25 (7) 2 Earnings from equity investments(b) — 3 — Total(a) $ 24 $ 29 $ (7) (a) The years ended December 31, 2020 , 2019 and 2018 include approximate gains of $11 million and losses of $8 million and $4 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, 2020 and 2019, we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2020 and 2019, we had cash margins of $3 million and $15 million, respectively, posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The balance at December 31, 2020 represents the net of our initial margin requirements of $11 million, offset by counterparty variation margin requirements of $8 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, 2020, 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 $6 million of additional collateral.

Revenue Recognition (Notes)

Revenue Recognition (Notes)	12 Months Ended
	Dec. 31, 2020
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 fee reserving the right to transport or store natural gas in our facilities up to contractually specified capacity levels (referred to as “reservation”) and (ii) a fee-based per-unit rate for quantities of natural gas actually transported or injected into/withdrawn from storage. In our firm service contracts we generally promise to provide a single integrated service each day over the life of the contract, which is fundamentally a stand-ready obligation to provide services up to the customer’s reservation capacity prescribed in the contract. Our customers have a take-or-pay payment obligation with respect to the fixed reservation fee component, regardless of the quantities they actually transport or store. In other cases, generally described as interruptible service, there is no fixed fee associated with these transportation and storage services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have firm service contracts. We do not have an obligation to perform under interruptible customer arrangements until we accept and schedule the customer’s request for periodic 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, we typically promise to transport on a stand-ready basis the customer’s minimum volume commitment amount. The customer is obligated to pay for its 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 monthly fee for the portion of storage capacity reserved by the customer and a per-unit rate for actual quantities injected into/withdrawn from storage. The customer is obligated to pay the fixed monthly reservation fee, regardless of whether or not it uses our storage facility (i.e., take-or-pay payment obligation). Non-firm transportation and storage service is provided to our customers when and to the extent we determine the requested capacity is available in our pipeline system and/or terminal storage facility. 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, we have a stand-ready obligation to perform this contracted service each day over the life of the contract. The customer pays a transaction price typically in the form of a fixed monthly charge and is obligated to pay whether or not it uses the storage capacity and throughput service (i.e., a take-or-pay payment obligation). These contracts 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 and non-firm basis. In our firm bulk storage and handling contracts, we are committed to handle and store on a stand-ready basis the minimum throughput quantity of bulk materials contracted by the customer. In some cases, the customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it uses the storage and handling service. The customer pays a transaction price typically based on a per-unit rate for quantities handled, including amounts attributable to deficiency quantities. For non-firm storage and handling services, 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. Kinder Morgan Canada Segment On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment will not have revenues on a prospective basis (see Note 4). Prior to the sale of these assets, we provided crude oil and refined petroleum transportation services generally as described above for non-firm, interruptible transportation services in our Products Pipelines business segment. The TMPL regulated tariff was designed to provide revenues sufficient to recover the costs of providing transportation services to shippers, including a return on invested capital. TMPL’s revenue was adjusted according to terms prescribed in our toll settlement with shippers as approved by the National Energy Board (NEB). Differences between transportation revenue recognized pursuant to our toll settlement and actual toll receipts were recognized as regulatory assets or liabilities and settled through future tolls. 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, 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 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 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 Year Ended December 31, 2018 Natural Gas Pipelines Products Pipelines Terminals CO 2 Kinder Morgan Canada(d) Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,387 $ 376 $ 983 $ 2 $ — $ (2) $ 4,746 Fee-based services 692 956 584 67 167 — 2,466 Total services 4,079 1,332 1,567 69 167 (2) 7,212 Commodity sales Natural gas sales 3,327 — — 2 — (11) 3,318 Product sales 1,190 393 20 1,222 — (37) 2,788 Total commodity sales 4,517 393 20 1,224 — (48) 6,106 Total revenues from contracts with customers 8,596 1,725 1,587 1,293 167 (50) 13,318 Other revenues(c) Leasing services 220 158 440 48 2 — 868 Derivatives adjustments on commodity sales (25) — — (108) — — (133) Other 64 4 — 22 1 — 91 Total other revenues 259 162 440 (38) 3 — 826 Total revenues $ 8,855 $ 1,887 $ 2,027 $ 1,255 $ 170 $ (50) $ 14,144 (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) On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment does not have results of operations on a prospective basis (see Note 4). Contract Balances As of December 31, 2020 and 2019, our contract asset balances were $20 million and $27 million, respectively. Of the contract asset balance at December 31, 2019, $24 million was transferred to accounts receivable during the year ended December 31. 2020. As of December 31, 2020 and 2019, our contract liability balances were $239 million and $232 million, respectively. Of the contract liability balance at December 31, 2019, $65 million was recognized as revenue during the year ended December 31, 2020. 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, 2020 that we will invoice or transfer from contract liabilities and recognize in future periods: Year Estimated Revenue (In millions) 2021 $ 4,281 2022 3,500 2023 2,824 2024 2,439 2025 2,073 Thereafter 13,286 Total $ 28,403 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, 2020
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, ethanol, 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; and (iii) the ownership and operation of a crude oil pipeline system in West Texas; and • Kinder Morgan Canada (prior to August 31, 2018)—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington. As a result of the TMPL Sale, this segment does not have results of operations on a prospective basis. 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 2020, 2019 and 2018, 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, 2020 2019 2018 (In millions) Revenues Natural Gas Pipelines Revenues from external customers $ 7,222 $ 8,128 $ 8,807 Intersegment revenues 37 42 48 Products Pipelines 1,721 1,831 1,887 Terminals Revenues from external customers 1,719 2,031 2,025 Intersegment revenues 3 3 2 CO 2 1,038 1,219 1,255 Kinder Morgan Canada — — 170 Corporate and intersegment eliminations (40) (45) (50) Total consolidated revenues $ 11,700 $ 13,209 $ 14,144 Year Ended December 31, 2020 2019 2018 (In millions) Operating expenses(a) Natural Gas Pipelines $ 3,457 $ 4,213 $ 5,218 Products Pipelines 779 684 748 Terminals 762 888 823 CO 2 404 496 453 Kinder Morgan Canada — — 72 Corporate and intersegment eliminations (4) (1) (26) Total consolidated operating expenses $ 5,398 $ 6,280 $ 7,288 Year Ended December 31, 2020 2019 2018 (In millions) Other expense (income)(b) Natural Gas Pipelines $ 1,009 $ (680) $ 629 Products Pipelines 21 — (2) Terminals (50) (342) 54 CO 2 950 77 79 Kinder Morgan Canada — 2 (596) Corporate — (2) — Total consolidated other expense (income) $ 1,930 $ (945) $ 164 Year Ended December 31, 2020 2019 2018 (In millions) DD&A Natural Gas Pipelines $ 1,062 $ 1,005 $ 955 Products Pipelines 347 338 326 Terminals 438 494 489 CO 2 291 548 473 Kinder Morgan Canada — — 29 Corporate 26 26 25 Total consolidated DD&A $ 2,164 $ 2,411 $ 2,297 Year Ended December 31, 2020 2019 2018 (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 $ 551 $ (101) $ 410 Products Pipelines 45 63 56 Terminals 22 23 22 CO 2 22 33 34 Total consolidated equity earnings $ 640 $ 18 $ 522 Year Ended December 31, 2020 2019 2018 (In millions) Other, net-income (expense) Natural Gas Pipelines $ 11 $ 53 $ 39 Products Pipelines 1 6 2 Terminals 13 (5) 3 Kinder Morgan Canada — — 26 Corporate 31 21 37 Total consolidated other, net-income (expense) $ 56 $ 75 $ 107 Year Ended December 31, 2020 2019 2018 (In millions) Segment EBDA(c) Natural Gas Pipelines $ 3,483 $ 4,661 $ 3,540 Products Pipelines 977 1,225 1,209 Terminals 1,045 1,506 1,175 CO 2 (292) 681 759 Kinder Morgan Canada — (2) 720 Total Segment EBDA 5,213 8,071 7,403 DD&A (2,164) (2,411) (2,297) Amortization of excess cost of equity investments (140) (83) (95) General and administrative and corporate charges (653) (611) (588) Interest, net (1,595) (1,801) (1,917) Income tax expense (481) (926) (587) Total consolidated net income $ 180 $ 2,239 $ 1,919 Year Ended December 31, 2020 2019 2018 (In millions) Capital expenditures Natural Gas Pipelines $ 945 $ 1,377 $ 1,565 Products Pipelines 122 175 199 Terminals 433 347 386 CO 2 186 349 397 Kinder Morgan Canada — — 332 Corporate 21 22 25 Total consolidated capital expenditures $ 1,707 $ 2,270 $ 2,904 December 31, 2020 2019 (In millions) Investments Natural Gas Pipelines $ 7,262 $ 6,991 Products Pipelines 494 491 Terminals 136 251 CO 2 25 26 Total consolidated investments $ 7,917 $ 7,759 December 31, 2020 2019 (In millions) Assets Natural Gas Pipelines $ 48,597 $ 50,310 Products Pipelines 9,182 9,468 Terminals 8,639 8,890 CO 2 2,478 3,523 Corporate assets(d) 3,077 1,966 Total consolidated assets $ 71,973 $ 74,157 (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, 2020 2019 2018 (In millions) Revenues from external customers U.S. $ 11,625 $ 12,833 $ 13,596 Canada — 300 447 Mexico and other foreign 75 76 101 Total consolidated revenues from external customers $ 11,700 $ 13,209 $ 14,144 December 31, 2020 2019 2018 (In millions) Long-term assets, excluding goodwill and other intangibles U.S. $ 46,384 $ 46,709 $ 47,468 Canada 1 1 748 Mexico and other foreign 81 82 83 Total consolidated long-lived assets $ 46,466 $ 46,792 $ 48,299

Leases (Notes)

Leases (Notes)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Leases: Lessee	17. Leases Lessee Following are components of our lease cost: Year Ended December 31, 2020 2019 (In millions) Operating leases $ 55 $ 136 Short-term and variable leases 101 92 Total lease cost(a) $ 156 $ 228 (a) 2020 and 2019 amounts include $25 million and $46 million of capitalized lease costs. Other information related to our operating leases are as follows: Year Ended December 31, 2020 2019 (In millions, Operating cash flows from operating leases $ (131) $ (182) Investing cash flows from operating leases (25) (46) ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion 20 102 Amortization of ROU assets 46 75 Removal of ROU assets and liabilities associated with the KML and U.S. Cochin Sale — (394) Weighted average remaining lease term 11.56 years 13.40 years Weighted average discount rate 4.27 % 4.31 % Amounts recognized in the accompanying consolidated balance sheet are as follows: December 31, Lease Activity Balance sheet location 2020 2019 (In millions) ROU assets Deferred charges and other assets $ 303 $ 329 Short-term lease liability Other current liabilities 40 40 Long-term lease liability Other long-term liabilities and deferred credits 263 289 Finance lease assets Property, plant and equipment, net 1 2 Finance lease liabilities Long-term debt—Outstanding 1 2 Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2020 are as follows: Year Commitment (In millions) 2021 $ 53 2022 46 2023 38 2024 34 2025 30 Thereafter 211 Total lease payments 412 Less: Interest (109) Present value of lease liabilities $ 303 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, 2020
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. FERC Inquiry Regarding the Commission’s Policy for Determining Return on Equity On March 21, 2019, the FERC issued a notice of inquiry (NOI) seeking comments regarding whether the FERC should revise its policies for determining the base return on equity (ROE) used in setting cost of service rates charged by jurisdictional public utilities and interstate natural gas and liquids pipelines. The NOI sought comment on whether any aspects of the existing methodologies used by the FERC to set an ROE for a regulated entity should be changed, whether the ROE methodology should be the same across all three industries, and whether alternative methodologies should be considered. Comments were filed by industry groups, pipeline companies and shippers for review and evaluation by the FERC. On May 21, 2020, the FERC issued its Policy Statement on Determining Return on Equity for Natural Gas and Oil Pipelines (Policy Statement). As it applies to natural gas and oil pipelines, the Policy Statement requires averaging the results of the discounted cash flow model and capital asset pricing model, giving equal weight to each model, retains its existing two-thirds/one-third weighting of short and long-term growth projections in the discounted cash flow model, and excludes the risk premium or expected earnings models. On other matters raised in this proceeding, the FERC declined to adopt rigid policy changes, and will address issues, such as the appropriate sources for data sets and the specific companies to use for a given proxy group, as those issues arise in future rate proceedings on a pipeline-by-pipeline, case-by-case basis. The Policy Statement does not result in any immediate changes to any existing rates or ROEs for any of our pipelines, and any future changes to rates or ROEs for a pipeline will depend on a variety of factors that remain to be determined when they are raised and argued in connection with future or existing rate proceedings. SFPP FERC Proceedings The FERC approved the SFPP East Line Settlement in Docket No. IS21-138 (“EL Settlement”) on December 31, 2020 and it became final and effective on February 2, 2021. The EL Settlement resolved certain dockets in their entirety (IS09-437 and OR16-6) and resolved the SFPP East Line related disputes in other dockets which remain ongoing (OR14-35/36 and OR19-21/33/37). The amounts SFPP agreed to pay pursuant to the EL Settlement were fully accrued on or before December 31, 2020. The tariffs and rates charged by SFPP which were not fully resolved by the EL Settlement are subject to a number of ongoing shipper-initiated proceedings at the FERC. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. If the shippers prevail on their arguments or claims, they would be entitled to seek reparations for the two EPNG FERC Proceedings The tariffs and rates charged by EPNG were subject to two FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that its findings in Opinion 517-A would apply to the same issues in the 2010 rate case. All refund obligations related to the 2008 rate case were satisfied in 2015. EPNG sought federal appellate review of Opinion 517-A. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528-A) on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with Opinions 517-A and 528-A. On May 3, 2018, the FERC issued Opinion 528-B upholding its decisions in Opinion 528-A and requiring EPNG to implement the rates required by its rulings and provide refunds within 60 days. On July 2, 2018, EPNG reported to the FERC that the refunds had been provided as ordered. Also on July 2, 2018, EPNG initiated appellate review of Opinions 528, 528-A and 528-B. EPNG’s appeals in the 2008 and 2010 rate cases as well as the intervenors’ appeal in the 2010 rate case were consolidated. The U.S. Court of Appeals for the D.C. Circuit denied all petitions for review on July 24, 2020, which concludes these rate proceedings. 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 panel delivered its Award, and the panel's ruling 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. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG. This lawsuit remains pending. 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. By its second Notice of Arbitration, Eni USA 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 to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the arbitration. On January 10, 2020, the Court of Chancery entered an Order and Final Judgment granting GLNG’s motion to enjoin arbitration of the negligent misrepresentation claim, but denying the motion to enjoin arbitration of the breach of contract claims. The parties filed cross appeals of the Final Judgment. On November 17, 2020, the Delaware Supreme Court ruled in favor of GLNG and a permanent injunction was entered prohibiting Eni USA from re-arbitrating both the breach of contract and negligent misrepresentation claims. On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), 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 seeks a declaration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project have given rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also seeks a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. A final decision in this arbitration is expected before the end of the third quarter of 2021. GLNG intends to continue to vigorously prosecute and defend all of the foregoing proceedings. 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 $225 million. Hiland Partners denies and will vigorously defend 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, 2020 and 2019, our total reserve for legal matters was $273 million and $203 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 by the EPA to be approximately $1.1 billion and active cleanup is expected to take as long as 13 years to complete. KMLT, KMBT, and 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 acquired from GATX Terminals Corporation) 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. 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. In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability. 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. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved 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. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs. On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Site. At that time the final cleanup plan in the ROD was estimated by the EPA to cost $1.7 billion. On October 5, 2016, the EPA entered into an AOC with Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight miles of the Site. The design work is underway. Initial expectations were that the design work would take four years to complete. The cleanup is expected to take at least six years to complete once it begins. In addition, the EPA and numerous PRPs, including EPEC Polymers, are 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. We anticipate the PRPs, including EPEC Polymers, will engage in further discussions with the EPA during 2021. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD. There is also uncertainty as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until the PRPs engage in discussions with the EPA, the FS is completed, and the RI/FS is finalized, we are unable to reasonably estimate the extent of our potential liability. 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 case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified a federal jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing which is pending. The case remains effectively stayed pending a final ruling by the Court of Appeals. 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 two cases against TGP, two cases against SNG, and two cases 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. One of these cases filed by Vintage Assets, Inc. and several landowners against SNG, TGP, and another defendant was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana. On May 4, 2018, the U.S. District Court entered a judgment ruling in favor of the plaintiffs on certain of their contract claims. The Court stayed the judgment pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. In October 2018, the Court of Appeals dismissed the appeals for lack of subject matter jurisdiction. In April 2019 the case was remanded to the state district court for Plaquemines Parish, Louisiana for further proceedings. On October 2, 2020, the case was settled for an amount which is not material to our business. We will continue to vigorously defend the remaining cases. General

Recent Accounting Pronoucements

Recent Accounting Pronoucements (Notes)	12 Months Ended
	Dec. 31, 2020
Accounting Standards Update and Change in Accounting Principle [Abstract]
Recent Accounting Pronouncements	19. Recent Accounting Pronouncements Accounting Standards Updates Reference Rate Reform (Topic 848) On March 12, 2020, the FASB issued ASU No. 2020-04, “ Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting. ” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the SOFR. Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met. On January 7, 2021, the FASB issued ASU No. 2021-01, “ Reference Rate Reform (Topic 848): Scope. ” This ASU clarifies that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price alignment (“The Discounting Transition”) are in the scope of 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 will be effective for us for the fiscal year beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
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. COVID-19 The COVID-19 pandemic-related reduction in energy demand and the dramatic decline in commodity prices that began to impact us in the first quarter of 2020 has continued to cause disruptions and volatility. Sharp declines in crude oil and natural gas production along with reduced demand for refined products due to the economic shutdown in the wake of the pandemic affected our business and continues to do so. While we have seen some meaningful recovery during the second half of the year in demand for refined products that we move through our terminals, significant uncertainty remains regarding the duration and extent of the impact of the pandemic (including the timing and distribution of vaccines) on the energy industry, including demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities. These events, among other factors, resulted in certain non-cash impairments charges during 2020 as further discussed in Note 3.
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 as it relates 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.
Accounts Receivable and Allowance for Credit Losses	Allowance for Credit Losses Effective with our adoption of Accounting Standards Update (ASU) No. 2016-13, “ Financial Instruments–Credit Losses ” on January 1, 2020, 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 as of December 31, 2020 includes an evaluation of estimated impacts resulting from the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices, which we estimate could have a more significant impact to certain subset or pools of customers. Prior to the adoption of ASU No. 2016-13, generally our evaluation of appropriate reserves for our accounts receivable was based on a historical analysis of uncollected amounts and we recorded adjustments for changed circumstances and customer-specific information.
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. We generally 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. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 0.08% 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 generally 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 and Other Intangibles Impairments	Long-lived Asset and Other Intangibles 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 estimated future cash flows expected to result from our use of the asset and its eventual disposition 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. Because the impairment test for long-lived assets held in use is based on 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 undiscounted cash flows, we typically use discounted cash flow analyses to determine if an impairment is required. 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 3 for further information.
Equity Method of Accounting and Basis Difference	Equity Method of Accounting and Basis Differences We account for investments which we do not control, but do have the ability to exercise significant influence using the equity method of accounting. 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 this purpose, we have 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. 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. Prior to our adoption of ASU No. 2017-04, “ Intangibles - Goodwill and Other (Topic) 350: Simplifying the Test for Goodwill Impairment ” effective January 1, 2020, we performed a two-step quantitative test. Step 1 involved the quantitative test still applied under ASU No. 2017-04 described above. If the estimated fair value exceeded the carrying value, the reporting unit’s goodwill was not considered impaired. If the carrying value exceeded the estimated fair value, step 2 was performed to determine whether goodwill was impaired and, if so, the amount of the impairment. Step 2 involved calculating an implied fair value of goodwill by performing a hypothetical allocation of the estimated fair value of the reporting unit determined in step 1 to the respective tangible and intangible net assets of the reporting unit. The remaining implied goodwill was then compared to the actual carrying amount of the goodwill for the reporting unit. To the extent the carrying amount of goodwill exceeded the implied goodwill, the difference was the amount of the goodwill impairment. 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 both December 31, 2020 and 2019, the gross carrying amounts of these intangible assets was $4,074 million and $4,126 million, respectively, and the accumulated amortization was $1,621 million and $1,450 million, respectively, resulting in net carrying amounts of $2,453 million and $2,676 million, respectively. These intangible assets primarily consisted of customer contracts, relationships and agreements associated with our Natural Gas Pipelines and Product Pipelines business segments. Primarily, these contracts, relationships and agreements relate to the gathering of natural gas, and the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline and other refined petroleum products, petroleum coke, metals and ores. 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.
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 $319 million, $382 million and $363 million for the years ended December 31, 2020, 2019 and 2018, 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. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims we may have against others. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable.
Lessee	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 Beginning January 1, 2019, operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Operating leases in effect prior to January 1, 2019 were recognized at the present value of the remaining payments on the remaining lease term as of January 1, 2019. 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 common units 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 our Class P common shares.
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 Redeemable noncontrolling interest represents the interest in one of our consolidated subsidiaries, ELC, that is not owned by us, which in certain limited circumstances, the partner has the right to relinquish its interest in the subsidiary and redeem its cumulative contributions, net of distributions it has received through date of redemption. Distributions paid to ELC are recorded as a reduction to the Redeemable Noncontrolling Interest balance . Net income attributable to redeemable noncontrolling interest was $54 million, $11 million and less than $1 million for the years ended December 31, 2020, 2019 and 2018, respectively, and is reported 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, and prior to the divestitures of our Canadian assets, our net investments in foreign operations. 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 value. We assign each fair value measurement to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. Recognized valuation techniques utilize inputs such as contractual prices, quoted market prices or rates, and discount factors. These inputs may be either readily observable or corroborated by market data.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or returned to customers through the ratemaking process. In instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount. We include the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets.
Earnings per Share	Earnings per Share We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares 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.

Income Taxes (Policies)

Income Taxes (Policies)	12 Months Ended
	Dec. 31, 2020
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, 2020
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, 2020 and 2019: December 31, 2020 2019 (In millions) Current regulatory assets $ 25 $ 55 Non-current regulatory assets 231 212 Total regulatory assets(a) $ 256 $ 267 Current regulatory liabilities $ 26 $ 26 Non-current regulatory liabilities 169 189 Total regulatory liabilities(b) $ 195 $ 215 (a) Regulatory assets as of December 31, 2020 include (i) $131 million of unamortized losses on disposal of assets; (ii) $49 million income tax gross up on equity AFUDC; and (iii) $76 million of other assets including amounts related to fuel tracker arrangements. Approximately $119 million of the regulatory assets, with a weighted average remaining recovery period of 14 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, 2020 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 $112 million of the $169 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 17 years, while the remaining $57 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 shares and participating securities: Year Ended December 31, 2020 2019 2018 (In millions, except per share amounts) Net Income Available to Common Stockholders $ 119 $ 2,190 $ 1,481 Participating securities: Less: Net Income Allocated to Restricted stock awards(a) (13) (12) (8) Net Income Allocated to Class P Stockholders $ 106 $ 2,178 $ 1,473 Basic Weighted Average Common Shares Outstanding 2,263 2,264 2,216 Basic Earnings Per Common Share $ 0.05 $ 0.96 $ 0.66 (a) As of December 31, 2020, 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, 2020 2019 2018 (In millions on a weighted average basis) Unvested restricted stock awards 13 13 12 Convertible trust preferred securities 3 3 3 Mandatory convertible preferred stock(a) — — 48 (a) The holder of each convertible preferred share participated in our earnings by receiving preferred stock dividends through the mandatory conversion date of October 26, 2018 at which time our convertible preferred shares were converted to common shares.

Impairments and Losses and Ga_2

Impairments and Losses and Gains on Divestitures (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020, 2019 and 2018: Year Ended December 31, 2020 2019 2018 (In millions) Natural Gas Pipelines Impairment of goodwill(a) $ 1,000 $ — $ — Impairments of long-lived assets(b) — 290 636 Gains on divestitures of long-lived assets(c) (1) (967) (6) Impairments of equity investments(d) — 650 270 Impairments of inventory 11 — — Products Pipelines Impairments of long-lived and intangible assets 21 — — Terminals Impairments of long-lived and intangible assets(e) 5 — 59 Gains on divestitures of long-lived assets(f) (54) (335) (6) Gain on sale of equity investment interests (10) — — CO 2 Impairment of goodwill(a) 600 — — Impairments of long-lived assets(g) 350 74 79 Losses on divestitures of long-lived assets — 2 — Kinder Morgan Canada Loss (gain) on divestiture of long-lived assets(h) — 2 (595) Other losses (gains) on divestitures of long-lived assets — (1) — Pre-tax losses (gains) on divestitures and impairments, net $ 1,922 $ (285) $ 437 (a) 2020 amounts represent non-cash goodwill impairments associated with our Natural Gas Pipelines Non-Regulated and CO 2 reporting units (see “— Goodwill Impairments ” below). (b) 2019 amount represents non-cash impairments associated with certain gathering and processing assets in Oklahoma and northern Texas. 2018 amount represents non-cash impairment associated with certain gathering and processing assets in Oklahoma and a project write-off associated with the Utica Marcellus Texas pipeline. (c) 2019 amount includes a $957 million gain related to the sale of the Cochin Pipeline system. (d) Non-cash impairments of equity investments are included in “Earnings from equity investments” on our accompanying consolidated statements of income for the years ended December 31, 2019 and 2018. 2019 amount represents the non-cash impairment of our investment in Ruby. 2018 amount represents the non-cash impairment of our investment in Gulf LNG Holdings Group, LLC (Gulf LNG) which was driven by a ruling by an arbitration panel affecting a customer contract. Our share of earnings recognized by Gulf LNG on the respective customer contract is included in “Earnings from equity investments” on our accompanying consolidated statement of income for the year ended December 31, 2018. (e) 2018 amount primarily relates to non-cash impairments of certain northeast terminal assets. (f) 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. (g) 2020, 2019 and 2018 amounts represent impairments of oil and gas properties. (h) 2019 and 2018 amounts represent a working capital adjustment and gain on sale, respectively, associated with the TMPL Sale.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Schedule of Income Before Income Taxes	The components of “Income Before Income Taxes” are as follows: Year Ended December 31, 2020 2019 2018 (In millions) U.S. $ 663 $ 2,482 $ 1,739 Foreign (2) 683 767 Total Income Before Income Taxes $ 661 $ 3,165 $ 2,506
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, 2020 2019 2018 (In millions) Current tax expense (benefit) Federal $ (20) $ (2) $ (22) State 9 10 (45) Foreign(a) 147 201 249 Total 136 209 182 Deferred tax expense (benefit) Federal 440 682 425 State 49 66 55 Foreign(a) (144) (31) (75) Total 345 717 405 Total tax provision $ 481 $ 926 $ 587 (a) Our Canadian income tax (benefit) expense was $(4) million, $165 million and $168 million for the years ended December 31, 2020, 2019 and 2018, 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, 2020 2019 2018 (In millions, except percentages) Federal income tax $ 139 21.0 % $ 665 21.0 % $ 526 21.0 % Increase (decrease) as a result of: Taxes on foreign earnings, net of federal benefit 2 0.3 % 139 4.4 % 131 5.2 % Net effects of noncontrolling interests (13) (2.0) % (10) (0.3) % (65) (2.6) % State income tax, net of federal benefit 52 7.9 % 68 2.1 % 46 1.8 % Dividend received deduction (27) (4.1) % (39) (1.1) % (31) (1.2) % Adjustments to uncertain tax positions 3 0.5 % (5) (0.2) % (47) (1.9) % Nondeductible goodwill 336 50.8 % 108 3.4 % 58 2.3 % General business credit — — % — — % (64) (2.6) % Federal refunds (20) (3.0) % — — % — — % Other 9 1.4 % — — % 33 1.4 % Total $ 481 72.8 % $ 926 29.3 % $ 587 23.4 %
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities result from the following: December 31, 2020 2019 (In millions) Deferred tax assets Employee benefits $ 224 $ 208 Net operating loss carryforwards 1,484 1,261 Tax credit carryforwards 257 258 Other 242 241 Valuation allowances (138) (155) Total deferred tax assets 2,069 1,813 Deferred tax liabilities Property, plant and equipment 414 385 Investments 1,084 529 Other 35 42 Total deferred tax liabilities 1,533 956 Net deferred tax assets $ 536 $ 857

Property, Plant and Equipment_2

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	As of December 31, 2020 and 2019, our property, plant and equipment, net consisted of the following: December 31, 2020 2019 (In millions) Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 20,339 $ 19,856 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 26,142 25,791 Other(a) 5,188 5,360 Accumulated depreciation, depletion and amortization (17,818) (16,950) 33,851 34,057 Land and land rights-of-way 1,403 1,356 Construction work in process 582 1,006 Property, plant and equipment, net $ 35,836 $ 36,419 (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, 2020
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, 2020 and 2019, and our earnings (loss) from these respective investments for the years ended December 31, 2020, 2019 and 2018: Ownership Interest Equity Investments Earnings (Loss) from December 31, December 31, Year Ended December 31, 2020 2020 2019 2020 2019 2018 (In millions) Citrus Corporation 50% $ 1,849 $ 1,856 $ 165 $ 157 $ 169 SNG 50% 1,532 1,473 129 140 141 NGPL Holdings LLC(a) 50% 803 721 116 81 66 Gulf Coast Express Pipeline LLC 34% 638 656 90 37 2 Permian Highway Pipeline 27% 632 309 — — — MEP 50% 416 439 (6) 15 31 Gulf LNG(b) 50% 361 361 19 17 (61) Products (SE) Pipe Line Corporation(c) 51% 357 348 43 58 55 Utopia Holding LLC 50% 329 335 20 20 14 EagleHawk 25% 275 285 17 17 7 Watco Companies, LLC (d) 70 185 16 19 21 Cortez Pipeline Company 53% 25 26 24 35 36 FEP 50% 16 102 70 59 55 Ruby(e) (f) 1 41 15 (609) 26 All others 613 622 62 55 55 Total investments $ 7,917 $ 7,759 $ 780 $ 101 $ 617 Amortization of excess cost $ (140) $ (83) $ (95) (a) Investment in NGPL Holdings LLC (NGPL Holdings) includes a related party promissory note receivable with a principal amount of $500 million as of December 31, 2020. On October 1, 2019, NGPL Holdings issued a non-cash related party promissory note with a principal amount of $500 million as a capital distribution. The related party promissory note accrues interest at 6.75% and is payable quarterly. For the years ended December 31, 2020 and 2019, we recognized $34 million and $8 million, respectively, of interest within “Earnings from equity investments” on our accompanying consolidated statements of income. (b) The loss from Gulf LNG for the year ended December 31, 2018 includes our share of earnings recognized due to a ruling by an arbitration panel affecting a customer contract. 2018 amount also includes a non-cash impairment charge of $270 million (pre-tax) driven by this ruling. See Note 3 for more information. (c) Previously known as Plantation Pipe Line Company. (d) 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. (e) The loss from Ruby for the year ended December 31, 2019 amount includes a non-cash impairment charge of $650 million (pre-tax) related to our investment. See Note 3 for more information.
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 2020 2019 2018 (In millions) Revenues $ 5,076 $ 4,906 $ 4,898 Costs and expenses 4,249 3,508 3,245 Net income $ 827 $ 1,398 $ 1,653 December 31, Balance Sheet 2020 2019 (In millions) Current assets $ 1,013 $ 1,195 Non-current assets 25,069 24,743 Current liabilities 1,787 2,125 Non-current liabilities 9,734 9,670 Partners’/owners’ equity 14,561 14,143

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill [Table Text Block]	Changes in the amounts of our goodwill for each of the years ended December 31, 2020 and 2019 are summarized by reporting unit as follows: Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated CO 2 Products Pipelines Products Pipelines Terminals Terminals Total (In millions) Gross goodwill $ 15,892 $ 5,812 $ 1,528 $ 2,125 $ 221 $ 1,573 $ 27,151 Accumulated impairment losses (1,643) (1,597) — (1,197) (70) (679) (5,186) December 31, 2018 14,249 4,215 1,528 928 151 894 21,965 Divestitures(a) — (422) — — — (92) (514) Transfer(b) — (450) — 450 — — — December 31, 2019 14,249 3,343 1,528 1,378 151 802 21,451 Impairments(c) — (1,000) (600) — — — (1,600) Transfer — — — — — — — December 31, 2020 14,249 2,343 928 1,378 151 802 19,851 Gross goodwill 15,892 4,940 1,528 2,575 221 1,481 26,637 Accumulated impairment losses (1,643) (2,597) (600) (1,197) (70) (679) (6,786) December 31, 2020 $ 14,249 $ 2,343 $ 928 $ 1,378 $ 151 $ 802 $ 19,851 (a) 2019 includes $514 million related to the KML and U.S. Cochin Sale. See Note 4 for more information. (b) Effective January 1, 2019, for segment reporting purposes, certain assets were transferred among our business segments which resulted in the transfer of goodwill from the Natural Gas Pipelines Non-Regulated reporting unit to the Products Pipelines reporting unit. See Note 16 for more information. (c) See Note 3 “ Impairments and Losses and Gains on Divestitures—Goodwill Impairments ” for further information regarding our goodwill impairments.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Schedule of Debt	The following table provides detail on the principal amount of our outstanding debt balances: December 31, 2020 2019 (In millions, Credit facility and commercial paper borrowings(a) $ — $ 37 Corporate senior notes(b) 6.85%, due February 2020 — 700 6.50%, due April 2020 — 535 5.30%, due September 2020 — 600 6.50%, due September 2020 — 349 5.00%, due February 2021 750 750 3.50%, due March 2021(c) 750 750 5.80%, due March 2021 400 400 5.00%, due October 2021 500 500 4.15%, due March 2022 375 375 1.50%, due March 2022(d) 917 841 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 6.70%, due February 2027 7 7 2.25%, due March 2027(d) 611 561 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(f) 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 (continued) December 31, 2020 2019 5.20%, due March 2048 750 750 3.25%, due August 2050(f) 500 — 7.45%, due March 2098 26 26 TGP senior notes(b) 7.00%, due March 2027 300 300 7.00%, due October 2028 400 400 2.90%, due March 2030(g) 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 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 2020 through December 2035 380 395 Trust I Preferred Securities, 4.75%, due March 2028(h) 221 221 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(i) — 100 Other miscellaneous debt(j) 254 258 Total debt – KMI and Subsidiaries 33,396 33,360 Less: Current portion of debt(k) 2,558 2,477 Total long-term debt – KMI and Subsidiaries(l) $ 30,838 $ 30,883 (a) See “—Current portion of debt” below for further details regarding the outstanding credit facility 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, 2020 exchange rate of 1.2216 U.S. dollars per Euro and at the December 31, 2019 exchange rate of 1.1213 U.S. dollars per Euro. As of December 31, 2020 and 2019, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in increases to our debt balance of $102 million and $26 million, respectively, related to the 1.50% series and increases of $68 million and $18 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) During the year ended December 31, 2019, we entered into a floating-to-fixed interest rate swap agreement which was designated as a cash flow hedge. (f) On August 5, 2020, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 2.00% senior notes due 2031 and $500 million aggregate principal amount of 3.25% senior notes due 2050 and received combined net proceeds of $1,226 million. (g) On February 24, 2020, TGP issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 2030 and received net proceeds of $991 million. (h) Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2020, 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, 2020 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. (i) As of December 31, 2019, KMGP had outstanding 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057, which was redeemed including accrued dividends on January 15, 2020. (j) Includes finance lease obligations with monthly installments. The lease terms expire between 2024 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, 2020 and 2019, increased our combined debt balances by $1,293 million and $1,032 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, 2020 2019 (In millions, unless otherwise stated) $4 billion credit facility due November 16, 2023 $ — $ — Commercial paper notes(a) — 37 Current portion of senior notes 6.85%, due February 2020 — 700 6.50%, due April 2020 — 535 5.30%, due September 2020 — 600 6.50%, due September 2020 — 349 5.00%, due February 2021 750 — 3.50%, due March 2021(b) 750 — 5.80%, due March 2021 400 — 5.00%, due October 2021 500 — Trust I Preferred Securities, 4.75% due March 2028(c) 111 111 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(d) — 100 Current portion of other debt 47 45 Total current portion of debt $ 2,558 $ 2,477 (a) Weighted average interest rates on borrowings outstanding as of December 31, 2019 was 1.90%. (b) On January 4, 2021, we repaid our $750 million senior corporate notes. (c) 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. (d) In December 2019, we notified the holder of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as current in our accompanying balance sheet as of December 31, 2019. We redeemed these securities including accrued dividends on January 15, 2020.
Schedule of Maturities of Long-term Debt	The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2020, are summarized as follows: Year Total (In millions) 2021 $ 2,558 2022 2,575 2023 3,250 2024 1,925 2025 1,566 Thereafter 21,522 Total $ 33,396
Schedule of Debt Fair Value Adjustments	The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets: December 31, 2020 2019 (In millions) Purchase accounting debt fair value adjustments $ 546 $ 599 Carrying value adjustment to hedged debt 702 359 Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a) 240 257 Unamortized debt discounts, net (76) (67) Unamortized debt issuance costs (119) (116) Total debt fair value adjustments $ 1,293 $ 1,032
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, 2020 December 31, 2019 Carrying Estimated Carrying Estimated (In millions) Total debt $ 34,689 $ 39,622 $ 34,392 $ 38,016

Share-based Compensation and _2

Share-based Compensation and Employee Benefits (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2019 12,414 $ 20.07 Granted 4,532 15.10 Vested (4,035) 21.71 Forfeited (229) 18.99 Outstanding at December 31, 2020 12,682 $ 17.79
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, 2020 2019 2018 (In millions, except per share amounts) Weighted average grant date fair value per share $ 15.10 $ 20.46 $ 17.73 Intrinsic value of awards vested during the year 59 87 42 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) 2021 4,216 2022 3,051 2023 4,775 2024 127 2025 513 Total Outstanding 12,682
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, 2020 and 2019: Pension Benefits OPEB 2020 2019 2020 2019 (In millions) Change in benefit obligation: Benefit obligation at beginning of period $ 2,696 $ 2,566 $ 333 $ 339 Service cost 59 53 1 1 Interest cost 71 96 8 12 Actuarial loss (gain) 198 159 (17) 10 Benefits paid (180) (178) (29) (32) Participant contributions — — 2 2 Medicare Part D subsidy receipts — — 1 1 Benefit obligation at end of period 2,844 2,696 299 333 Change in plan assets: Fair value of plan assets at beginning of period 2,076 1,864 333 306 Actual return on plan assets 178 330 47 49 Employer contributions 125 60 7 7 Participant contributions — — 2 2 Medicare Part D subsidy receipts — — 1 1 Benefits paid (180) (178) (29) (32) Fair value of plan assets at end of period 2,199 2,076 361 333 Funded status - net (liability) asset at December 31, $ (645) $ (620) $ 62 $ —
Components of Funded Status	Components of Funded Status . The following table details the amounts recognized in our balance sheets at December 31, 2020 and 2019 related to our pension and OPEB plans: Pension Benefits OPEB 2020 2019 2020 2019 (In millions) Non-current benefit asset(a) $ — $ — $ 269 $ 231 Current benefit liability — — (19) (18) Non-current benefit liability (645) (620) (188) (213) Funded status - net (liability) asset at December 31, $ (645) $ (620) $ 62 $ — (a) 2020 and 2019 OPEB amounts include $46 million and $39 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, 2020 and 2019 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets: Pension Benefits OPEB 2020 2019 2020 2019 (In millions) Unrecognized net actuarial (loss) gain $ (674) $ (557) $ 153 $ 123 Unrecognized prior service (cost) credit (2) (3) 9 12 Accumulated other comprehensive (loss) income $ (676) $ (560) $ 162 $ 135
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, 2020 and 2019: Pension Assets 2020 2019 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Short-term investment funds $ — $ 77 $ 77 $ — $ 50 $ 50 Equities(a) 249 — 249 296 — 296 Fixed income securities(b) — 425 425 — 405 405 Derivatives — 11 11 — 12 12 Subtotal $ 249 $ 513 762 $ 296 $ 467 763 Measured at NAV(c) Common/collective trusts(d) 1,184 1,069 Private investment funds(e) 208 200 Private limited partnerships(f) 45 44 Subtotal 1,437 1,313 Total plan assets fair value $ 2,199 $ 2,076 (a) Plan assets include $83 million and $129 million of KMI Class P common stock for 2020 and 2019, respectively. (b) Plan assets include $1 million of KMI debt securities for both 2020 and 2019. (c) Plan assets which used NAV as a practical expedient to measure fair value. (d) Common/collective trust funds were invested in approximately 29% fixed income and 71% equity in 2020 and 32% fixed income and 68% equity in 2019. (e) Private investment funds were invested in approximately 71% fixed income and 29% equity in 2020 and 73% fixed income and 27% equity in 2019. (f) Includes assets invested in real estate, venture and buyout funds. OPEB Assets 2020 2019 Level 1 Level 2 Total Level 1 Level 2 Total (In millions) Measured within fair value hierarchy Cash $ — $ — $ — $ 1 $ — $ 1 Short-term investment funds — 5 5 — 5 5 Equities — — — 25 — 25 Fixed income securities — — — — 17 17 Mutual funds(a) — — — 11 — 11 Subtotal $ — $ 5 5 $ 37 $ 22 59 Measured at NAV(b) Common/collective trusts(c) 356 274 Subtotal 356 274 Total plan assets fair value $ 361 $ 333 (a) Includes mutual funds which are invested in equities and fixed income securities. (b) 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, 2020, we expect to make the following benefit payments under our plans: Fiscal year Pension Benefits OPEB(a) (In millions) 2021 $ 239 $ 30 2022 238 28 2023 225 27 2024 219 25 2025 211 23 2026 - 2030 902 94 (a) Includes a reduction of approximately $1 million in each of the years 2021 through 2025 and approximately $6 million in aggregate for the period 2026 - 2030 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 2020, 2019 and 2018: Pension Benefits OPEB 2020 2019 2018 2020 2019 2018 (In millions) Assumptions related to benefit obligations: Discount rate 2.27 % 3.17 % 4.26 % 2.08 % 3.03 % 4.16 % 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 Assumptions related to benefit costs: Discount rate for benefit obligations 3.17 % 4.26 % 3.56 % 3.03 % 4.16 % 3.48 % Discount rate for interest on benefit obligations 2.71 % 3.89 % 3.13 % 2.63 % 3.83 % 3.08 % Discount rate for service cost 3.24 % 4.28 % 3.56 % 3.48 % 4.51 % 3.82 % Discount rate for interest on service cost 2.80 % 3.93 % 3.14 % 3.39 % 4.46 % 3.76 % Expected return on plan assets(a) 6.75 % 7.25 % 7.25 % 6.50 % 6.50 % 7.08 % Rate of compensation increase 3.50 % 3.50 % 3.50 % n/a n/a n/a Interest crediting rate 3.71 % 3.90 % 2.71 % 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%, 27% and 21% for 2020, 2019 and 2018, respectively.
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 2020 2019 2018 2020 2019 2018 (In millions) Components of net benefit cost (credit): Service cost $ 59 $ 53 $ 52 $ 1 $ 1 $ 1 Interest cost 71 96 84 8 12 12 Expected return on assets (137) (129) (149) (16) (16) (20) Amortization of prior service cost (credit) 1 — — (5) (4) (4) Amortization of net actuarial loss (gain) 40 54 40 (13) (11) (6) Net benefit cost (credit) 34 74 27 (25) (18) (17) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 157 (42) 105 (43) (17) (32) Amortization or settlement recognition of net actuarial (loss) gain (40) (54) (87) 13 11 3 Amortization of prior service (cost) credit (1) — (1) 3 2 3 Total recognized in total other comprehensive loss (income)(a) 116 (96) 17 (27) (4) (26) Total recognized in net benefit cost (credit) and other comprehensive loss (income) $ 150 $ (22) $ 44 $ (52) $ (22) $ (43) (a) Excludes $2 million for the year ended December 31, 2020 associated with other plans.

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2020
Stockholders' Equity Note [Abstract]
Schedule of Dividends Paid and Payable	The following table provides information about our per share dividends: Year Ended December 31, 2020 2019 2018 Per common share cash dividend declared for the period $ 1.05 $ 1.00 $ 0.80 Per common share cash dividend paid in the period 1.0375 0.95 0.725
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, 2017 $ (27) $ (189) $ (325) $ (541) Other comprehensive gain (loss) before reclassifications 111 (89) (31) (9) Losses reclassified from accumulated other comprehensive loss(a) 84 223 22 329 Impact of adoption of ASU 2018-02 (see below) (4) (36) (69) (109) Net current-period change in accumulated other comprehensive (loss) income 191 98 (78) 211 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) (a) Amounts for foreign currency translation adjustments and pension and other postretirement liability adjustments reflect the deferred losses recognized in income during the year ended December 31, 2018 related to the TMPL Sale. 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, 2020
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, 2020 2019 (In millions) Balance sheet location Accounts receivable $ 41 $ 38 Other current assets 6 — Deferred charges and other assets 109 86 $ 156 $ 124 Current portion of debt $ 6 $ 6 Accounts payable 25 23 Other current liabilities 4 3 Long-term debt 154 157 Other long-term liabilities and deferred credits 48 41 $ 237 $ 230 Year Ended December 31, 2020 2019 2018 (In millions) Income statement location Revenues $ 206 $ 269 $ 265 Operating Costs, Expenses and Other Costs of sales $ 116 $ 75 $ 63 Other operating expenses 119 132 91

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	As of December 31, 2020, 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 (20.4) MMBbl Crude oil basis (2.2) MMBbl Natural gas fixed price (30.1) Bcf Natural gas basis (20.0) Bcf NGL fixed price (1.1) MMBbl Derivatives not designated as hedging contracts Crude oil fixed price (5.6) MMBbl Crude oil basis (6.8) MMBbl Natural gas fixed price (6.7) Bcf Natural gas basis (5.5) Bcf NGL fixed price (1.0) MMBbl
Schedule of Interest Rate Derivatives [Table Text Block]	The following table summarizes our outstanding interest rate contracts as of December 31, 2020: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments Fixed-to-variable interest rate contracts(a) $ 7,625 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 2,500 Mark-to-Market December 2021 (a) The principal amount of hedged senior notes consisted of $900 million included in “Current portion of debt” and $6,725 million included in “Long-term debt” on our accompanying consolidated balance sheet.
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, 2020: 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, 2020 2019 2020 2019 Location Fair value Fair value (In millions) Derivatives designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 42 $ 31 $ (33) $ (43) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 33 17 (8) (8) Subtotal 75 48 (41) (51) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 119 45 (3) — Deferred charges and other assets/(Other long-term liabilities and deferred credits) 575 313 (7) (1) Subtotal 694 358 (10) (1) Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) — — (6) (6) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 138 46 — — Subtotal 138 46 (6) (6) Total 907 452 (57) (58) Derivatives not designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 24 8 (21) (7) Total derivatives $ 931 $ 460 $ (78) $ (65)
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 Gross amount Contracts available for netting Cash collateral held(b) Net amount (In millions) 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 As of December 31, 2019 Energy commodity derivative contracts(a) $ 19 $ 37 $ — $ 56 $ (19) $ (21) $ 16 Interest rate contracts — 358 — 358 — — 358 Foreign currency contracts — 46 — 46 (6) — 40 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, 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 — — As of December 31, 2019 Energy commodity derivative contracts(a) (3) (55) — (58) 19 — (39) Interest rate contracts — (1) — (1) — — (1) 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, 2020 2019 2018 (In millions) Interest rate contracts Interest, net $ 335 $ 340 $ (122) Hedged fixed rate debt(a) Interest, net $ (343) $ (353) $ 113 (a) As of December 31, 2020, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $702 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, 2020 2019 2018 2020 2019 2018 (In millions) (In millions) Energy commodity derivative contracts $ 240 $ (168) $ 201 Revenues—Commodity sales $ 222 $ 16 $ (59) Costs of sales (14) 5 21 Interest rate contracts(c) (8) (1) 3 Earnings from equity investments(c) — 2 (4) Foreign currency contracts 92 (60) (59) Other, net 125 (31) (67) Total $ 324 $ (229) $ 145 Total $ 333 $ (8) $ (109) (a) We expect to reclassify an approximate $9 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2020 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 year ended December 31, 2019, we recognized a $12 million gain associated with a write-down of hedged inventory. During the year ended December 31, 2018, we recognized a $3 million loss as a result of our equity investment’s forecasted transactions being probable of not occurring and a $21 million gain 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, 2020 2019 2018 2020 2019 2018 (In millions) (In millions) Foreign currency contracts $ — $ (8) $ 91 Loss (gain) on impairments and divestitures, net $ — $ 83 $ 26 Total $ — $ (8) $ 91 Total $ — $ 83 $ 26 (a) During the year ended December 31, 2019, we recognized an $83 million gain related to the KML and U.S. Cochin Sale. During the year ended December 31, 2018, we recognized a $26 million gain related to the TMPL Sale. See Note 4. Derivatives not designated as accounting hedges Location Gain/(Loss) recognized in income on derivatives Year Ended December 31, 2020 2019 2018 (In millions) Energy commodity derivative contracts Revenues—Commodity sales $ (1) $ 33 $ (9) Costs of sales 25 (7) 2 Earnings from equity investments(b) — 3 — Total(a) $ 24 $ 29 $ (7) (a) The years ended December 31, 2020 , 2019 and 2018 include approximate gains of $11 million and losses of $8 million and $4 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, 2020
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, 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 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 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 Year Ended December 31, 2018 Natural Gas Pipelines Products Pipelines Terminals CO 2 Kinder Morgan Canada(d) Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 3,387 $ 376 $ 983 $ 2 $ — $ (2) $ 4,746 Fee-based services 692 956 584 67 167 — 2,466 Total services 4,079 1,332 1,567 69 167 (2) 7,212 Commodity sales Natural gas sales 3,327 — — 2 — (11) 3,318 Product sales 1,190 393 20 1,222 — (37) 2,788 Total commodity sales 4,517 393 20 1,224 — (48) 6,106 Total revenues from contracts with customers 8,596 1,725 1,587 1,293 167 (50) 13,318 Other revenues(c) Leasing services 220 158 440 48 2 — 868 Derivatives adjustments on commodity sales (25) — — (108) — — (133) Other 64 4 — 22 1 — 91 Total other revenues 259 162 440 (38) 3 — 826 Total revenues $ 8,855 $ 1,887 $ 2,027 $ 1,255 $ 170 $ (50) $ 14,144 (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) On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment does not have results of operations on a prospective basis (see Note 4).
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, 2020 that we will invoice or transfer from contract liabilities and recognize in future periods: Year Estimated Revenue (In millions) 2021 $ 4,281 2022 3,500 2023 2,824 2024 2,439 2025 2,073 Thereafter 13,286 Total $ 28,403

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Financial information by segment follows: Year Ended December 31, 2020 2019 2018 (In millions) Revenues Natural Gas Pipelines Revenues from external customers $ 7,222 $ 8,128 $ 8,807 Intersegment revenues 37 42 48 Products Pipelines 1,721 1,831 1,887 Terminals Revenues from external customers 1,719 2,031 2,025 Intersegment revenues 3 3 2 CO 2 1,038 1,219 1,255 Kinder Morgan Canada — — 170 Corporate and intersegment eliminations (40) (45) (50) Total consolidated revenues $ 11,700 $ 13,209 $ 14,144 Year Ended December 31, 2020 2019 2018 (In millions) Operating expenses(a) Natural Gas Pipelines $ 3,457 $ 4,213 $ 5,218 Products Pipelines 779 684 748 Terminals 762 888 823 CO 2 404 496 453 Kinder Morgan Canada — — 72 Corporate and intersegment eliminations (4) (1) (26) Total consolidated operating expenses $ 5,398 $ 6,280 $ 7,288 Year Ended December 31, 2020 2019 2018 (In millions) Other expense (income)(b) Natural Gas Pipelines $ 1,009 $ (680) $ 629 Products Pipelines 21 — (2) Terminals (50) (342) 54 CO 2 950 77 79 Kinder Morgan Canada — 2 (596) Corporate — (2) — Total consolidated other expense (income) $ 1,930 $ (945) $ 164 Year Ended December 31, 2020 2019 2018 (In millions) DD&A Natural Gas Pipelines $ 1,062 $ 1,005 $ 955 Products Pipelines 347 338 326 Terminals 438 494 489 CO 2 291 548 473 Kinder Morgan Canada — — 29 Corporate 26 26 25 Total consolidated DD&A $ 2,164 $ 2,411 $ 2,297 Year Ended December 31, 2020 2019 2018 (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 $ 551 $ (101) $ 410 Products Pipelines 45 63 56 Terminals 22 23 22 CO 2 22 33 34 Total consolidated equity earnings $ 640 $ 18 $ 522 Year Ended December 31, 2020 2019 2018 (In millions) Other, net-income (expense) Natural Gas Pipelines $ 11 $ 53 $ 39 Products Pipelines 1 6 2 Terminals 13 (5) 3 Kinder Morgan Canada — — 26 Corporate 31 21 37 Total consolidated other, net-income (expense) $ 56 $ 75 $ 107 Year Ended December 31, 2020 2019 2018 (In millions) Segment EBDA(c) Natural Gas Pipelines $ 3,483 $ 4,661 $ 3,540 Products Pipelines 977 1,225 1,209 Terminals 1,045 1,506 1,175 CO 2 (292) 681 759 Kinder Morgan Canada — (2) 720 Total Segment EBDA 5,213 8,071 7,403 DD&A (2,164) (2,411) (2,297) Amortization of excess cost of equity investments (140) (83) (95) General and administrative and corporate charges (653) (611) (588) Interest, net (1,595) (1,801) (1,917) Income tax expense (481) (926) (587) Total consolidated net income $ 180 $ 2,239 $ 1,919 Year Ended December 31, 2020 2019 2018 (In millions) Capital expenditures Natural Gas Pipelines $ 945 $ 1,377 $ 1,565 Products Pipelines 122 175 199 Terminals 433 347 386 CO 2 186 349 397 Kinder Morgan Canada — — 332 Corporate 21 22 25 Total consolidated capital expenditures $ 1,707 $ 2,270 $ 2,904 December 31, 2020 2019 (In millions) Investments Natural Gas Pipelines $ 7,262 $ 6,991 Products Pipelines 494 491 Terminals 136 251 CO 2 25 26 Total consolidated investments $ 7,917 $ 7,759 December 31, 2020 2019 (In millions) Assets Natural Gas Pipelines $ 48,597 $ 50,310 Products Pipelines 9,182 9,468 Terminals 8,639 8,890 CO 2 2,478 3,523 Corporate assets(d) 3,077 1,966 Total consolidated assets $ 71,973 $ 74,157 (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, 2020 2019 2018 (In millions) Revenues from external customers U.S. $ 11,625 $ 12,833 $ 13,596 Canada — 300 447 Mexico and other foreign 75 76 101 Total consolidated revenues from external customers $ 11,700 $ 13,209 $ 14,144 December 31, 2020 2019 2018 (In millions) Long-term assets, excluding goodwill and other intangibles U.S. $ 46,384 $ 46,709 $ 47,468 Canada 1 1 748 Mexico and other foreign 81 82 83 Total consolidated long-lived assets $ 46,466 $ 46,792 $ 48,299

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Lease, Cost [Table Text Block]	Following are components of our lease cost: Year Ended December 31, 2020 2019 (In millions) Operating leases $ 55 $ 136 Short-term and variable leases 101 92 Total lease cost(a) $ 156 $ 228 (a) 2020 and 2019 amounts include $25 million and $46 million of capitalized lease costs. Other information related to our operating leases are as follows: Year Ended December 31, 2020 2019 (In millions, Operating cash flows from operating leases $ (131) $ (182) Investing cash flows from operating leases (25) (46) ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion 20 102 Amortization of ROU assets 46 75 Removal of ROU assets and liabilities associated with the KML and U.S. Cochin Sale — (394) Weighted average remaining lease term 11.56 years 13.40 years Weighted average discount rate 4.27 % 4.31 % Amounts recognized in the accompanying consolidated balance sheet are as follows: December 31, Lease Activity Balance sheet location 2020 2019 (In millions) ROU assets Deferred charges and other assets $ 303 $ 329 Short-term lease liability Other current liabilities 40 40 Long-term lease liability Other long-term liabilities and deferred credits 263 289 Finance lease assets Property, plant and equipment, net 1 2 Finance lease liabilities Long-term debt—Outstanding 1 2
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2020 are as follows: Year Commitment (In millions) 2021 $ 53 2022 46 2023 38 2024 34 2025 30 Thereafter 211 Total lease payments 412 Less: Interest (109) Present value of lease liabilities $ 303

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Accounts Receivable, Net (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Allowance for Credit Loss	$ 26	$ 9

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Composite depreciation rate, low	0.08%
Composite depreciation rate, high	33.30%

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Goodwill (Details)	12 Months Ended
	Dec. 31, 2020segment
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Intangible Assets, Gross (Excluding Goodwill)	$ 4,074	$ 4,126
Finite-Lived Intangible Assets, Accumulated Amortization	1,621	1,450
Intangible Assets, Net (Excluding Goodwill)	2,453	2,676
Amortization of Intangible Assets	212	$ 214	$ 219
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	228
Finite-Lived Intangible Assets, Amortization Expense, Year Two	227
Finite-Lived Intangible Assets, Amortization Expense, Year Three	222
Finite-Lived Intangible Assets, Amortization Expense, Year Four	222
Finite-Lived Intangible Assets, Amortization Expense, Year Five	$ 216
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	11 years

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Operations and Maintenance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Expense [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Results of Operations, Expense from Oil and Gas Producing Activities	$ 319	$ 382	$ 363

Summary of Significant Accoun_9

Summary of Significant Accounting Policies - Leases (Details)	Dec. 31, 2020
Minimum
Lessee, Operating Lease, Remaining Lease Term	1 year
Maximum
Lessee, Operating Lease, Remaining Lease Term	50 years

Summary of Significant Accou_10

Summary of Significant Accounting Policies - Redeemable Noncontrolling Interest (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Elba Liquefaction Company [Member]
Entity Information [Line Items]
Net income (loss) attributable to redeemable noncontrolling interest	$ 54	$ 11	$ 1

Summary of Significant Accou_11

Summary of Significant Accounting Policies - Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Regulatory Assets and Liabilities [Line Items]
Current regulatory assets	$ 25	$ 55
Non-current regulatory assets	231	212
Total regulatory assets(a)	256	267
Current regulatory liabilities	26	26
Non-current regulatory liabilities	169	189
Total regulatory liabilities(b)	195	$ 215
Regulatory assets recoverable without earning a return	$ 119
Regulatory assets, weighted average remaining recovery period	14 years
Remaining Amounts of Regulatory Liabilities Subject to Crediting Period	$ 112
Remaining Recovery Period of Regulatory Liabilities Subject to Defined Crediting Period	17 years
Remaining Amounts of Regulatory Liabilities Not Subject to Defined Crediting Period	$ 57
Loss on Disposal of Assets [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	131
Income Tax Gross Up on AFUDC Equity [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	49
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	$ 76

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ 119	$ 2,190	$ 1,481
Less: Net Income Allocated to Restricted stock awards	$ (13)	$ (12)	$ (8)
Basic Weighted Average Common Shares Outstanding	2,263	2,264	2,216
Basic Earnings Per Common Share	$ 0.05	$ 0.96	$ 0.66
Unvested restricted stock awards
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities	13	13	12
Convertible trust preferred securities
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities	3	3	3
Mandatory convertible preferred stock(a)
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities	0	0	48
Class P
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ 106	$ 2,178	$ 1,473
Class P | Unvested restricted stock awards
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Awards outstanding	13

Impairments and Losses and Ga_3

Impairments and Losses and Gains on Divestitures (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2020	Jun. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Pre-tax losses (gains) on divestitures and impairments, net			$ 1,922	$ (285)	$ 437
(Gain) Loss on Sale of Assets and Asset Impairment Charges			1,932	(942)	167
Impairment of goodwill			1,600
Impairments of long-lived and intangible assets			376
Impairment losses on long-lived assets and equity investments				1,014
Other
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gains) losses on divestitures of long-lived assets			0	(1)	0
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 and Asset Impairment Charges				(1,296)
Trans Mountain and Trans Mountain Expansion Project
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gain) Loss on Sale of Assets and Asset Impairment Charges					(595)
Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairment of goodwill			1,000	0	0
Impairments of long-lived assets			0	290	636
Impairments of long-lived and intangible assets		$ 600		290
(Gains) losses on divestitures of long-lived assets			(1)	(967)	(6)
Impairments of equity investments			0	650	270
Impairments of inventory			11	0	0
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 and intangible assets			21	0	0
Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of long-lived and intangible assets			5	0	59
(Gains) losses on divestitures of long-lived assets			(54)	(335)	(6)
Gain on sale of equity investment interests			(10)	0	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]
Impairment of goodwill	$ 600		600	0	0
Impairments of long-lived assets	$ 350		350	74	79
(Gains) losses on divestitures of long-lived assets			0	2	0
Kinder Morgan Canada
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gains) losses on divestitures of long-lived assets					$ (595)
Kinder Morgan Canada | Trans Mountain and Trans Mountain Expansion Project
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gains) losses on divestitures of long-lived assets			$ 0	2
Ruby
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of equity investments				650
Ruby | Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairments of equity investments				$ 650

Impairments and Losses and Ga_4

Impairments and Losses and Gains on Divestiture Long-lived Assets (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2020	Jun. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Impairments of long-lived and intangible assets			$ 376
Ruby Pipeline Holding Company LLC [Member]
Property, Plant and Equipment [Line Items]
Impairments of equity investments				$ 650
Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Impairments of equity investments			$ 0	650	$ 270
Impairments of long-lived and intangible assets		$ 600		290
Natural Gas Pipelines | Ruby Pipeline Holding Company LLC [Member]
Property, Plant and Equipment [Line Items]
Impairments of equity investments				$ 650
Oil and Gas Properties [Member] | CO2
Property, Plant and Equipment [Line Items]
Asset Impairment Charges	$ 350
Oil and Gas Properties [Member] | CO2 | Valuation Technique, Discounted Cash Flow [Member]
Property, Plant and Equipment [Line Items]
Estimated Weighted Average Cost Of Capital	10.50%

Impairments and Losses and Ga_5

Impairments and Losses and Gains on Divestiture Goodwill Impairments (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2020	Jun. 30, 2020	Dec. 31, 2020
Goodwill [Line Items]
Impairment of goodwill			$ 1,600
Natural Gas Pipelines - Nonregulated [Member]
Goodwill [Line Items]
Impairment of goodwill		$ 1,000	$ 1,000
Natural Gas Pipelines - Nonregulated [Member] | Valuation, Market Approach [Member]
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 - Nonregulated [Member] | Valuation Technique, Discounted Cash Flow [Member]
Goodwill [Line Items]
Estimated Weighted Average Cost Of Capital			8.00%
Period Used For Projection			6 years 6 months
Natural Gas Pipelines - Nonregulated [Member] | Weighted Market Approach and Income Approach [Member]
Goodwill [Line Items]
Enterprise Value to EBITDA Multiple Valuation			11
Natural Gas Pipelines - Nonregulated [Member] | Valuation, Income Approach [Member]
Goodwill [Line Items]
Fair Value Measurement Inputs and Valuation Techniques, Weighting Of Approach			0.75
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 [Member]
Goodwill [Line Items]
Estimated Weighted Average Cost Of Capital	9.25%
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, Pipelines [Member]
Goodwill [Line Items]
Impairment of goodwill			$ 0
Products Pipelines, Pipelines [Member] | Maximum
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount			10.00%

Divestitures - Sale of U.S. Por

Divestitures - Sale of U.S. Portion of Cochin Pipeline System and KML (Details) $ in Millions	Jan. 09, 2020USD ($)	Dec. 16, 2019USD ($)transactionsshares	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	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			$ 1,932	$ (942)	$ 167
Marketable securities at fair value			$ 0	925
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%

Divestitures - Sale of Trans Mo

Divestitures - Sale of Trans Mountain Pipeline System and ts Expansion Project (Details) $ in Millions, $ in Millions	Jan. 03, 2019USD ($)	Jan. 03, 2019CAD ($)	Feb. 28, 2019USD ($)	Mar. 31, 2019USD ($)	Mar. 31, 2019CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 16, 2019	Aug. 31, 2018USD ($)	Aug. 31, 2018CAD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss (gain) on divestitures and impairments, net						$ 1,932	$ (942)	$ 167
Settlement of working capital adjustments						0	28
Payments to noncontrolling interests	$ 900	$ 1,200				0	879	0
Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments								2,998
Repayments of commercial paper	400
Repayments of debt						$ 3,996	$ 11,224	14,591
Trans Mountain and Trans Mountain Expansion Project
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration										$ 3,400	$ 4,430
Contractual purchase price											$ 4,500
Loss (gain) on divestitures and impairments, net								$ (595)
Settlement of working capital adjustments				$ 28	$ 37
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	$ 2,500
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%

Income Taxes - Income Before In

Income Taxes - Income Before Income Taxes and Income Tax Provision (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Components of Income Before Income Taxes
U.S.	$ 663	$ 2,482	$ 1,739
Foreign	(2)	683	767
Income Before Income Taxes	661	3,165	2,506
Current tax expense (benefit)
Federal	(20)	(2)	(22)
State	9	10	(45)
Foreign(a)	147	201	249
Total	136	209	182
Deferred tax expense (benefit)
Federal	440	682	425
State	49	66	55
Foreign(a)	(144)	(31)	(75)
Total	345	717	405
Total	481	926	587
Canada
Components of Income Tax Provision
Foreign income tax expense	$ (4)	$ 165	$ 168

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Amount:
Federal income tax	$ 139	$ 665	$ 526
Taxes on foreign earnings, net of federal benefit	2	139	131
Net effects of noncontrolling interests	(13)	(10)	(65)
State income tax, net of federal benefit	52	68	46
Dividend received deduction	(27)	(39)	(31)
Adjustments to uncertain tax positions	3	(5)	(47)
Nondeductible goodwill	336	108	58
General business credit	0	0	(64)
Federal refunds	(20)	0	0
Other	9	0	33
Total	$ 481	$ 926	$ 587
Percent:
Federal income tax, percent	21.00%	21.00%	21.00%
Taxes on foreign earnings, net of federal benefit, percent	0.30%	4.40%	5.20%
Net effects of noncontrolling interests, percent	(2.00%)	(0.30%)	(2.60%)
State income tax, net of federal benefit, percent	7.90%	2.10%	1.80%
Dividend received deduction, percent	(4.10%)	(1.10%)	(1.20%)
Adjustments to uncertain tax positions, percent	0.50%	(0.20%)	(1.90%)
Nondeductible goodwill, percent	50.80%	3.40%	2.30%
General business credit, percent	0.00%	0.00%	(2.60%)
Federal refunds, percent	(3.00%)	0.00%	0.00%
Other, percent	1.40%	0.00%	1.40%
Total, percent	72.80%	29.30%	23.40%

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets
Employee benefits	$ 224	$ 208
Net operating loss carryforwards	1,484	1,261
Tax credit carryforwards	257	258
Other	242	241
Valuation allowances	(138)	(155)
Total deferred tax assets	2,069	1,813
Deferred tax liabilities
Property, plant and equipment	414	385
Investments	1,084	529
Other	35	42
Total deferred tax liabilities	1,533	956
Net deferred tax assets	$ 536	$ 857

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Valuation Allowances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Valuation Allowance [Line Items]
Net operating loss carryforwards	$ 1,484	$ 1,261
Tax credit carryforwards	257	258
Valuation allowance related to deferred tax assets	138	155
Change in valuation allowances	(17)
Net Operating Loss Carryovers Tax Credits and Capital Losses
Valuation Allowance [Line Items]
Valuation allowance related to deferred tax assets	100	$ 117
Operating Loss Carryforward | State and Local Jurisdiction
Valuation Allowance [Line Items]
Change in valuation allowances	(9)
Operating Loss Carryforward | Foreign Tax Authority
Valuation Allowance [Line Items]
Change in valuation allowances	$ (8)

Income Taxes - Expiration Perio

Income Taxes - Expiration Periods for Deferred Tax Assets (Details) $ in Millions	Dec. 31, 2020USD ($)
State and Local Jurisdiction
Income Tax Examination [Line Items]
Net operating loss carryforwards	$ 3,800
Foreign Tax Authority
Income Tax Examination [Line Items]
Net operating loss carryforwards	83
Tax credit carryforwards	17
Indefinite Tax Period | Domestic Tax Authority
Income Tax Examination [Line Items]
Net operating loss carryforwards	2,600
Expires from 2021 - 2037 | Domestic Tax Authority
Income Tax Examination [Line Items]
Net operating loss carryforwards	3,400
General Business Tax Credit Carryforward
Income Tax Examination [Line Items]
Tax credit carryforwards	$ 240

Income Taxes - Unrecognized Tax

Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Unrecognized Tax Benefits
Gross unrecognized tax benefit balances	$ 18	$ 16	$ 34
Reductions based on settlements with taxing authority	0	$ (21)	$ (73)
Unrecognized Tax Benefits, Other Disclosures
Unrecognized tax benefits, if recognized, which would affect effective tax rate	18
Estimate of decrease in unrecognized tax benefits in next year	1
Unrecognized tax benefits balance reasonably possible next year	$ 17

Property, Plant and Equipment C

Property, Plant and Equipment Classes and Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Accumulated depreciation, depletion and amortization	$ (17,818)	$ (16,950)
Property, Plant and Equipment, Net, Excluding Nondepreciable Assets	33,851	34,057
Property, plant and equipment, net	35,836	36,419
Depreciation, Depletion and Amortization, Property, Plant and Equipment	1,928	2,176	$ 2,057
Pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	20,339	19,856
Equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	26,142	25,791
Other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	5,188	5,360
Land and land rights-of-way
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,403	1,356
Construction work in process
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	582	1,006
Natural Gas Pipelines Regulated
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 12,160	$ 12,229

Property, Plant and Equipment A

Property, Plant and Equipment Asset Retirement Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	$ 214	$ 218
Asset Retirement Obligation, Current	$ 4	$ 4

Investments Equity investments

Investments Equity investments (Details) - USD ($) $ in Millions	Oct. 01, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Equity Investments		$ 7,917	$ 7,759
Earnings (Loss) from Equity Investments		780	101	$ 617
Amortization of excess cost of equity investments		(140)	(83)	(95)
Issuances of debt		$ 3,888	8,036	14,751
Citrus Corporation
Schedule of Equity Method Investments [Line Items]
Ownership Interest		50.00%
Equity Investments		$ 1,849	1,856
Earnings (Loss) from Equity Investments		$ 165	157	169
SNG
Schedule of Equity Method Investments [Line Items]
Ownership Interest		50.00%
Equity Investments		$ 1,532	1,473
Earnings (Loss) from Equity Investments		$ 129	140	141
NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest		50.00%
Equity Investments		$ 803	721
Earnings (Loss) from Equity Investments		116	81	66
Notes Receivable, Related Parties, Noncurrent		$ 500
Issuances of debt	$ 500
Debt Instrument, Interest Rate, Stated Percentage		6.75%
NGPL Holdings, LLC | Earnings from Equity Investments
Schedule of Equity Method Investments [Line Items]
Interest		$ 34	8
Gulf Coast Express LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest		34.00%
Equity Investments		$ 638	656
Earnings (Loss) from Equity Investments		$ 90	37	2
Permian Highway Pipeline
Schedule of Equity Method Investments [Line Items]
Ownership Interest		27.00%
Equity Investments		$ 632	309
Earnings (Loss) from Equity Investments		$ 0	0	0
MEP
Schedule of Equity Method Investments [Line Items]
Ownership Interest		50.00%
Equity Investments		$ 416	439
Earnings (Loss) from Equity Investments		$ (6)	15	31
Gulf LNG Holdings Group LLC
Schedule of Equity Method Investments [Line Items]
Ownership Interest		50.00%
Equity Investments		$ 361	361
Earnings (Loss) from Equity Investments		$ 19	17	(61)
Impairments of equity investments				270
Plantation Pipe Line Company
Schedule of Equity Method Investments [Line Items]
Ownership Interest		51.00%
Equity Investments		$ 357	348
Earnings (Loss) from Equity Investments		$ 43	58	55
Utopia Holding L.L.C.
Schedule of Equity Method Investments [Line Items]
Ownership Interest		50.00%
Equity Investments		$ 329	335
Earnings (Loss) from Equity Investments		$ 20	20	14
EagleHawk
Schedule of Equity Method Investments [Line Items]
Ownership Interest		25.00%
Equity Investments		$ 275	285
Earnings (Loss) from Equity Investments		17	17	7
Watco Companies, LLC
Schedule of Equity Method Investments [Line Items]
Equity Investments		70	185
Earnings (Loss) from Equity Investments		$ 16	19	21
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]
Gain (Loss) on Sale of Equity Investments		$ 10
Cortez Pipeline Company
Schedule of Equity Method Investments [Line Items]
Ownership Interest		53.00%
Equity Investments		$ 25	26
Earnings (Loss) from Equity Investments		$ 24	35	36
FEP
Schedule of Equity Method Investments [Line Items]
Ownership Interest		50.00%
Equity Investments		$ 16	102
Earnings (Loss) from Equity Investments		$ 70	59	55
Ruby
Schedule of Equity Method Investments [Line Items]
Ownership Interest		50.00%
Equity Investments		$ 1	41
Earnings (Loss) from Equity Investments		15	(609)	26
Impairments of equity investments			650
All others
Schedule of Equity Method Investments [Line Items]
Equity Investments		613	622
Earnings (Loss) from Equity Investments		$ 62	$ 55	$ 55

Investments Summary of Signific

Investments Summary of Significant Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Revenues	$ 11,700	$ 13,209	$ 14,144
Costs and Expenses	10,140	8,336	10,350
Net Income	180	2,239	1,919
Current assets	3,203	3,238
Current liabilities	5,074	5,100
Non-current liabilities	34,333	34,168
Partners’/owners’ equity	31,436	33,742
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Schedule of Equity Method Investments [Line Items]
Revenues	5,076	4,906	4,898
Costs and Expenses	4,249	3,508	3,245
Net Income	827	1,398	$ 1,653
Current assets	1,013	1,195
Non-current assets	25,069	24,743
Current liabilities	1,787	2,125
Non-current liabilities	9,734	9,670
Partners’/owners’ equity	$ 14,561	$ 14,143

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2020	Jun. 30, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Goodwill [Line Items]
Gross goodwill			$ 26,637		$ 27,151
Accumulated impairment losses			(6,786)		(5,186)
Goodwill			19,851	$ 21,451	21,965
Divestitures				(514)
Transfer			0	0
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
Divestitures				0
Transfer			0	0
Impairments			0
Natural Gas Pipelines Non-regulated
Goodwill [Line Items]
Gross goodwill			4,940		5,812
Accumulated impairment losses			(2,597)		(1,597)
Goodwill			2,343	3,343	4,215
Divestitures				(422)
Transfer			0	(450)
Impairments		$ (1,000)	(1,000)
CO2
Goodwill [Line Items]
Gross goodwill			1,528		1,528
Accumulated impairment losses			(600)		0
Goodwill			928	1,528	1,528
Divestitures				0
Transfer			0	0
Impairments	$ (600)		(600)
Products Pipelines
Goodwill [Line Items]
Gross goodwill			2,575		2,125
Accumulated impairment losses			(1,197)		(1,197)
Goodwill			1,378	1,378	928
Divestitures				0
Transfer			0	450
Impairments			0
Products Pipelines Terminals
Goodwill [Line Items]
Gross goodwill			221		221
Accumulated impairment losses			(70)		(70)
Goodwill			151	151	151
Divestitures				0
Transfer			0	0
Impairments			0
Terminals
Goodwill [Line Items]
Gross goodwill			1,481		1,573
Accumulated impairment losses			(679)		(679)
Goodwill			802	802	$ 894
Divestitures				(92)
Transfer			0	0
Impairments			$ 0
KML and U.S. Portion of Cochin Pipeline System
Goodwill [Line Items]
Divestitures				$ (514)

Debt - Schedule of Debt (Detail

Debt - Schedule of Debt (Details) - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2020	Aug. 05, 2020	Feb. 24, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries	$ 33,396			$ 33,360
Less: Current portion of debt	2,558			2,477
Total long-term debt – KMI and Subsidiaries	30,838			30,883
Credit facility and commercial paper borrowings(a)
Debt Instrument [Line Items]
Less: Current portion of debt	$ 0			37
EPC Building, LLC, promissory note, 3.967%, due January 2020 through December 2035 | EPC Building LLC
Debt Instrument [Line Items]
Interest rate, stated percentage	3.967%
Total debt – KMI and Subsidiaries	$ 380			395
Trust I Preferred Securities, 4.75%, due March 2028(h) | Capital Trust I
Debt Instrument [Line Items]
Interest rate, stated percentage	4.75%
Liquidation preference	$ 50
Total debt – KMI and Subsidiaries	$ 221			221
Less: Current portion of debt	111			$ 111
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(i) | Kinder Morgan G.P., Inc.
Debt Instrument [Line Items]
Liquidation preference				$ 1,000
Total debt – KMI and Subsidiaries	0			$ 100
Less: Current portion of debt	0			100
Other miscellaneous debt(j)
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries	254			258
Less: Current portion of debt	47			$ 45
Senior Notes | 6.85%, due February 2020
Debt Instrument [Line Items]
Interest rate, stated percentage				6.85%
Total debt – KMI and Subsidiaries	0			$ 700
Less: Current portion of debt	0			$ 700
Senior Notes | 6.50%, due April 2020
Debt Instrument [Line Items]
Interest rate, stated percentage				6.50%
Total debt – KMI and Subsidiaries	0			$ 535
Less: Current portion of debt	0			$ 535
Senior Notes | 5.30%, due September 2020
Debt Instrument [Line Items]
Interest rate, stated percentage				5.30%
Total debt – KMI and Subsidiaries	0			$ 600
Less: Current portion of debt	0			$ 600
Senior Notes | 6.50%, due September 2020
Debt Instrument [Line Items]
Interest rate, stated percentage				6.50%
Total debt – KMI and Subsidiaries	0			$ 349
Less: Current portion of debt	$ 0			349
Senior Notes | 5.00%, due February 2021
Debt Instrument [Line Items]
Interest rate, stated percentage	5.00%
Total debt – KMI and Subsidiaries	$ 750			750
Less: Current portion of debt	$ 750			0
Senior Notes | 3.50%, due March 2021(c)
Debt Instrument [Line Items]
Interest rate, stated percentage	3.50%
Total debt – KMI and Subsidiaries	$ 750			750
Less: Current portion of debt	$ 750			0
Senior Notes | 5.80%, due March 2021
Debt Instrument [Line Items]
Interest rate, stated percentage	5.80%
Total debt – KMI and Subsidiaries	$ 400			400
Less: Current portion of debt	$ 400			0
Senior Notes | 5.00%, due October 2021
Debt Instrument [Line Items]
Interest rate, stated percentage	5.00%
Total debt – KMI and Subsidiaries	$ 500			500
Less: Current portion of debt	$ 500			0
Senior Notes | 4.15%, due March 2022
Debt Instrument [Line Items]
Interest rate, stated percentage	4.15%
Total debt – KMI and Subsidiaries	$ 375			375
Senior Notes | 1.50%, due March 2022(d)
Debt Instrument [Line Items]
Interest rate, stated percentage	1.50%
Total debt – KMI and Subsidiaries	$ 917			841
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
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 | 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	$ 611			561
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(f)
Debt Instrument [Line Items]
Interest rate, stated percentage	2.00%	2.00%
Total debt – KMI and Subsidiaries	$ 750	$ 750		0
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(f)
Debt Instrument [Line Items]
Interest rate, stated percentage	3.25%	3.25%
Total debt – KMI and Subsidiaries	$ 500	$ 500		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(g) | TGP
Debt Instrument [Line Items]
Interest rate, stated percentage	2.90%		2.90%
Total debt – KMI and Subsidiaries	$ 1,000		$ 1,000	0
Senior Notes | 8.375%, due June 2032 | TGP
Debt Instrument [Line Items]
Interest rate, stated percentage	8.375%
Total debt – KMI and Subsidiaries	$ 240			240
Senior Notes | 7.625%, due April 2037 | TGP
Debt Instrument [Line Items]
Interest rate, stated percentage	7.625%
Total debt – KMI and Subsidiaries	$ 300			300
Senior Notes | 8.625%, due January 2022 | EPNG
Debt Instrument [Line Items]
Interest rate, stated percentage	8.625%
Total debt – KMI and Subsidiaries	$ 260			260
Senior Notes | 7.50%, due November 2026 | EPNG
Debt Instrument [Line Items]
Interest rate, stated percentage	7.50%
Total debt – KMI and Subsidiaries	$ 200			200
Senior Notes | 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, $ in Millions	Jan. 04, 2021USD ($)	Aug. 05, 2020USD ($)	Feb. 24, 2020USD ($)	Dec. 31, 2020USD ($)$ / shares$ / €shares	Dec. 31, 2019USD ($)$ / shares$ / €shares	Dec. 31, 2018USD ($)
Debt Instrument [Line Items]
Aggregate principal amount				$ 33,396	$ 33,360
Repayments of debt				3,996	11,224	$ 14,591
Issuances of debt				$ 3,888	$ 8,036	$ 14,751
Exchange rate | $ / €				1.2216	1.1213
Debt fair value adjustments				$ 1,293	$ 1,032
Capital Trust I
Debt Instrument [Line Items]
Ownership percentage				100.00%
Senior Notes
Debt Instrument [Line Items]
Redemption Price				100.00%
Issuances of debt		$ 1,226
3.50%, due March 2021(c) | Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage				3.50%
Aggregate principal amount				$ 750	750
3.50%, due March 2021(c) | Senior Notes | Subsequent Event
Debt Instrument [Line Items]
Repayments of debt	$ 750
2.00%, due February 2031(f) | Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage		2.00%		2.00%
Aggregate principal amount		$ 750		$ 750	0
1.50%, due March 2022 | Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage				1.50%
Aggregate principal amount				$ 917	841
Change to debt as a result of changes in exchange rate				$ 102	26
2.25%, due March 2027 | Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage				2.25%
Aggregate principal amount				$ 611	561
Change to debt as a result of changes in exchange rate				$ 68	18
Trust I Preferred Securities, 4.75%, due March 2028(h) | Capital Trust I
Debt Instrument [Line Items]
Interest rate, stated percentage				4.75%
Aggregate principal amount				$ 221	221
Trust Convertible Preferred Securities Outstanding | shares				4,400,000
Liquidation preference | $ / shares				$ 50
Conversion price | $ / shares				$ 25.18
Trust I Preferred Securities, 4.75%, due March 2028(h) | Capital Trust I | Class P
Debt Instrument [Line Items]
Conversion rate				0.7197
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(i) | Kinder Morgan G.P., Inc.
Debt Instrument [Line Items]
Aggregate principal amount				$ 0	$ 100
Liquidation preference | $ / shares					$ 1,000
Preferred stock, shares outstanding | shares					100,000
3.25%, due August 2050 | Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage		3.25%		3.25%
Aggregate principal amount		$ 500		$ 500	$ 0
2.90%, due March 2030 | Senior Notes | TGP
Debt Instrument [Line Items]
Interest rate, stated percentage			2.90%	2.90%
Aggregate principal amount			$ 1,000	$ 1,000	$ 0
Issuances of debt			$ 991

Debt - Schedule of Current Port

Debt - Schedule of Current Portion of Debt (Details) - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Current portion of debt	$ 2,558	$ 2,477
Debt, weighted average interest rate	4.86%	5.27%
$4 billion credit facility due November 16, 2023
Debt Instrument [Line Items]
Current portion of debt	$ 0	$ 0
Maximum borrowing capacity	4,000
Commercial Paper
Debt Instrument [Line Items]
Current portion of debt	0	$ 37
Maximum borrowing capacity	4,000
Debt, weighted average interest rate		1.90%
6.85%, due February 2020 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 700
Interest rate, stated percentage		6.85%
6.50%, due April 2020 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 535
Interest rate, stated percentage		6.50%
5.30%, due September 2020 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 600
Interest rate, stated percentage		5.30%
6.50%, due September 2020 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	0	$ 349
Interest rate, stated percentage		6.50%
5.00%, due February 2021 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 750	$ 0
Interest rate, stated percentage	5.00%
3.50%, due March 2021(b) | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 750	0
Interest rate, stated percentage	3.50%
5.80%, due March 2021 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 400	0
Interest rate, stated percentage	5.80%
5.00%, due October 2021 | Senior Notes
Debt Instrument [Line Items]
Current portion of debt	$ 500	0
Interest rate, stated percentage	5.00%
Trust I Preferred Securities, 4.75% due March 2028(c) | Capital Trust I
Debt Instrument [Line Items]
Current portion of debt	$ 111	111
Interest rate, stated percentage	4.75%
Liquidation preference	$ 50
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(d) | Kinder Morgan G.P., Inc.
Debt Instrument [Line Items]
Current portion of debt	$ 0	$ 100
Liquidation preference		$ 1,000
Other debt
Debt Instrument [Line Items]
Current portion of debt	$ 47	$ 45

Debt - Credit Facilities and Re

Debt - Credit Facilities and Restrictive Covenants (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Line of Credit Facility [Line Items]
Current portion of debt	$ 2,558	$ 2,477
$4 billion credit facility due November 16, 2023
Line of Credit Facility [Line Items]
Maximum borrowing capacity	4,000
Remaining borrowing capacity	$ 3,900
Maximum ratio of consolidated total funded debt to consolidated earnings before interest income taxes DDA	5.50
Current portion of debt	$ 0	0
Letters of credit outstanding	$ 82
$4 billion credit facility due November 16, 2023 | Minimum
Line of Credit Facility [Line Items]
Standby fee rate	0.10%
$4 billion credit facility due November 16, 2023 | Maximum
Line of Credit Facility [Line Items]
Standby fee rate	0.30%
$4 billion credit facility due November 16, 2023 | LIBOR Alternate Base Rate | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.10%
$4 billion credit facility due November 16, 2023 | LIBOR Alternate Base Rate | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
$4 billion 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%
$4 billion 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%
$4 billion credit facility due November 16, 2023 | Federal Funds Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
$4 billion credit facility due November 16, 2023 | Eurodollar
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Commercial Paper
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 4,000
Debt term	270 days
Current portion of debt	$ 0	$ 37

Debt - Schedule of Maturities o

Debt - Schedule of Maturities of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
2021	$ 2,558
2022	2,575
2023	3,250
2024	1,925
2025	1,566
Thereafter	21,522
Total debt – KMI and Subsidiaries	$ 33,396	$ 33,360

Debt - Schedule of Debt Fair Va

Debt - Schedule of Debt Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
Purchase accounting debt fair value adjustments	$ 546	$ 599
Carrying value adjustment to hedged debt	702	359
Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a)	240	257
Unamortized debt discounts, net	(76)	(67)
Unamortized debt issuance costs	(119)	(116)
Total debt fair value adjustments	$ 1,293	$ 1,032
Weighted-average amortization period of the unamortized premium from the termination of interest rate swaps	14 years

Debt - Schedule of Fair Value o

Debt - Schedule of Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Carrying value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	$ 34,689	$ 34,392
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total debt	$ 39,622	$ 38,016

Debt - Interest Rates, Interest

Debt - Interest Rates, Interest Rate Swaps and Contingent Debt (Details)	Dec. 31, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt, weighted average interest rate	4.86%	5.27%

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, 2020	Dec. 31, 2019	Dec. 31, 2018
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	250,000
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)	14,570	23,100	25,800
Value of shares granted	$ 0.3	$ 0.4	$ 0.5
Award vesting period	6 months
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan
Share-based Compensation
Shares of Class P common stock authorized under the plan	33,000,000
Grants during the period (shares)	4,532,000
Intrinsic value of restricted stock vested	$ 59	87	42
Expense related to restricted stock awards	73	62	63
Amounts capitalized related to restricted stock awards	11	$ 12	$ 13
Unrecognized compensation costs	$ 102
Unrecognized compensation costs, weighted average remaining amortization period	2 years 29 days
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan | Minimum
Share-based Compensation
Award vesting period	1 year
Kinder Morgan Inc 2015 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, 2020	Dec. 31, 2019	Dec. 31, 2018
Shares
Outstanding at end of period (shares)	13,000
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan
Shares
Outstanding at beginning of period (shares)	12,414
Granted (shares)	4,532
Vested (shares)	(4,035)
Forfeited (shares)	(229)
Outstanding at end of period (shares)	12,682	12,414
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (dollars per share)	$ 20.07
Granted (dollars per share)	15.10	$ 20.46	$ 17.73
Vested (dollars per share)	21.71
Forfeited (dollars per share)	18.99
Outstanding at end of period (dollars per share)	$ 17.79	$ 20.07

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, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	13,000
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	12,682	12,414
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan | 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	4,216
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan | 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	3,051
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan | 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	4,775
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan | 2024
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	127
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan | 2025
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	513

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, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 53	$ 50	$ 48
Pension Benefits
Pension and Other Postretirement Benefit Plans
Percentage of employees covered	100.00%
Vesting period	3 years
Accumulated benefit obligation	$ 2,804	2,659
Expected Payment of Future Benefits and Employer Contributions
Expected employer contributions in next year	$ 56
Pension Benefits | Minimum | Equities
Plan Assets
Target allocation percentage	31.00%
Pension Benefits | Minimum | Fixed Income Securities
Plan Assets
Target allocation percentage	37.00%
Pension Benefits | Minimum | Cash
Plan Assets
Target allocation percentage	0.00%
Pension Benefits | Minimum | Alternative Investments
Plan Assets
Target allocation percentage	0.00%
Pension Benefits | Minimum | Company Securities
Plan Assets
Target allocation percentage	0.00%
Pension Benefits | Maximum | Equities
Plan Assets
Target allocation percentage	55.00%
Pension Benefits | Maximum | Fixed Income Securities
Plan Assets
Target allocation percentage	57.00%
Pension Benefits | Maximum | Cash
Plan Assets
Target allocation percentage	5.00%
Pension Benefits | Maximum | Alternative Investments
Plan Assets
Target allocation percentage	2.00%
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	$ 255	288
Accumulated benefit obligation whose accumulated benefit obligations exceeded the fair value of plan assets, fair value of plan assets	48	$ 57
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	5.80%
Ultimate health care cost trend rate	4.50%
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$ 2,696	$ 2,566
Service cost	59	53	$ 52
Interest cost	71	96	84
Actuarial loss (gain)	198	159
Benefits paid	(180)	(178)
Participant contributions	0	0
Medicare Part D subsidy receipts	0	0
Benefit obligation at end of period	2,844	2,696	2,566
Change in plan assets:
Fair value of plan assets at beginning of period	2,076	1,864
Actual return on plan assets	178	330
Employer contributions	125	60
Participant contributions	0	0
Medicare Part D subsidy receipts	0	0
Benefits paid	(180)	(178)
Fair value of plan assets at end of period	2,199	2,076	1,864
Funded status - net (liability) asset at December 31,	(645)	(620)
OPEB
Change in benefit obligation:
Benefit obligation at beginning of period	333	339
Service cost	1	1	1
Interest cost	8	12	12
Actuarial loss (gain)	(17)	10
Benefits paid	(29)	(32)
Participant contributions	2	2
Medicare Part D subsidy receipts	1	1
Benefit obligation at end of period	299	333	339
Change in plan assets:
Fair value of plan assets at beginning of period	333	306
Actual return on plan assets	47	49
Employer contributions	7	7
Participant contributions	2	2
Medicare Part D subsidy receipts	1	1
Benefits paid	(29)	(32)
Fair value of plan assets at end of period	361	333	$ 306
Funded status - net (liability) asset at December 31,	$ 62	$ 0

Share-based Compensation and _8

Share-based Compensation and Employee Benefits - Components of Funded Status (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-current benefit asset	$ 0	$ 0
Current benefit liability	0	0
Non-current benefit liability	(645)	(620)
Funded status - net (liability) asset at December 31,	(645)	(620)
OPEB
Defined Benefit Plan Disclosure [Line Items]
Non-current benefit asset	269	231
Current benefit liability	(19)	(18)
Non-current benefit liability	(188)	(213)
Funded status - net (liability) asset at December 31,	62	0
OPEB | Other Affiliates
Defined Benefit Plan Disclosure [Line Items]
Non-current benefit asset	$ 46	$ 39

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, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Unrecognized net actuarial (loss) gain	$ (674)	$ (557)
Unrecognized prior service (cost) credit	(2)	(3)
Accumulated other comprehensive (loss) income	(676)	(560)
OPEB
Defined Benefit Plan Disclosure [Line Items]
Unrecognized net actuarial (loss) gain	153	123
Unrecognized prior service (cost) credit	9	12
Accumulated other comprehensive (loss) income	$ 162	$ 135

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 2,199	$ 2,076	$ 1,864
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	762	763
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	249	296
Pension Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	513	467
Pension Benefits | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	1,437	1,313
Pension Benefits | Short-term Investment Funds | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	77	50
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	77	50
Pension Benefits | Equities | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	249	296
Pension Benefits | Equities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	249	296
Pension Benefits | Equities | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits | Fixed Income Securities | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	425	405
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	425	405
Amount of KMI securities invested in	1	1
Pension Benefits | Derivatives | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	11	12
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	11	12
Pension Benefits | Common/Collective Trusts | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 1,184	$ 1,069
Pension Benefits | Common/Collective Trusts Invested in Equity Securities | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	71.00%	68.00%
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	29.00%	32.00%
Pension Benefits | Private Investment Funds | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 208	$ 200
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	71.00%	73.00%
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%	27.00%
Pension Benefits | Private Limited Partnerships | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 45	$ 44
OPEB
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	361	333	$ 306
OPEB | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	5	59
OPEB | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	37
OPEB | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	5	22
OPEB | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	356	274
OPEB | Cash | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	1
OPEB | Cash | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	1
OPEB | Cash | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB | Short-term Investment Funds | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	5	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	5	5
OPEB | Equities | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	25
OPEB | Equities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	25
OPEB | Equities | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB | Fixed Income Securities | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	17
OPEB | Fixed Income Securities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB | Fixed Income Securities | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	17
OPEB | Mutual Funds | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	11
OPEB | Mutual Funds | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	11
OPEB | Mutual Funds | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB | Common/Collective Trusts | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 356	$ 274
OPEB | Common/Collective Trusts Invested in Equity Securities | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	65.00%	64.00%
OPEB | Common/Collective Trusts Invested in Fixed Income Securities | Measured at NAV
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	35.00%	36.00%
Class P | Pension Benefits | Equities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Amount of KMI securities invested in	$ 83	$ 129

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, 2020USD ($)
Pension Benefits
Expected Future Benefit Payments:
2021	$ 239
2022	238
2023	225
2024	219
2025	211
2026 - 2030	902
OPEB
Expected Future Benefit Payments:
2021	30
2022	28
2023	27
2024	25
2025	23
2026 - 2030	94
Expected Future Reductions Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003:
2021	1
2022	1
2023	1
2024	1
2025	1
2026 - 2030	$ 6

Share-based Compensation and_12

Share-based Compensation and Employee Benefits - Schedule of Weighted-Average Actuarial Assumptions (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Assumptions related to benefit obligations:
Discount rate	2.27%	3.17%	4.26%
Rate of compensation increase	3.50%	3.50%	3.50%
Interest crediting rate	2.57%	3.71%	3.90%
Assumptions related to benefit costs:
Expected return on plan assets	6.75%	7.25%	7.25%
Rate of compensation increase	3.50%	3.50%	3.50%
Interest crediting rate	3.71%	3.90%	2.71%
OPEB
Defined Benefit Plan Disclosure [Line Items]
UBIT rate	27.00%	27.00%	21.00%
Assumptions related to benefit obligations:
Discount rate	2.08%	3.03%	4.16%
Assumptions related to benefit costs:
Expected return on plan assets	6.50%	6.50%	7.08%
Benefit obligation | Pension Benefits
Assumptions related to benefit costs:
Discount rate	3.17%	4.26%	3.56%
Benefit obligation | OPEB
Assumptions related to benefit costs:
Discount rate	3.03%	4.16%	3.48%
Discount rate for interest on benefit obligations | Pension Benefits
Assumptions related to benefit costs:
Discount rate	2.71%	3.89%	3.13%
Discount rate for interest on benefit obligations | OPEB
Assumptions related to benefit costs:
Discount rate	2.63%	3.83%	3.08%
Discount rate for service cost | Pension Benefits
Assumptions related to benefit costs:
Discount rate	3.24%	4.28%	3.56%
Discount rate for service cost | OPEB
Assumptions related to benefit costs:
Discount rate	3.48%	4.51%	3.82%
Discount rate for interest on service cost | Pension Benefits
Assumptions related to benefit costs:
Discount rate	2.80%	3.93%	3.14%
Discount rate for interest on service cost | OPEB
Assumptions related to benefit costs:
Discount rate	3.39%	4.46%	3.76%

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Components of net benefit cost (credit):
Service cost	$ 59	$ 53	$ 52
Interest cost	71	96	84
Expected return on assets	(137)	(129)	(149)
Amortization of prior service cost (credit)	1	0	0
Amortization of net actuarial loss (gain)	40	54	40
Net benefit cost (credit)	34	74	27
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net loss (gain) arising during period	157	(42)	105
Amortization or settlement recognition of net actuarial (loss) gain	(40)	(54)	(87)
Amortization of prior service (cost) credit	(1)	0	(1)
Total recognized in total other comprehensive loss (income)(a)	116	(96)	17
Total recognized in net benefit cost (credit) and other comprehensive loss (income)	150	(22)	44
Pension Benefits | Retirement Plan Name, Other
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Total recognized in total other comprehensive loss (income)(a)	2
OPEB
Components of net benefit cost (credit):
Service cost	1	1	1
Interest cost	8	12	12
Expected return on assets	(16)	(16)	(20)
Amortization of prior service cost (credit)	(5)	(4)	(4)
Amortization of net actuarial loss (gain)	(13)	(11)	(6)
Net benefit cost (credit)	(25)	(18)	(17)
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net loss (gain) arising during period	(43)	(17)	(32)
Amortization or settlement recognition of net actuarial (loss) gain	13	11	3
Amortization of prior service (cost) credit	3	2	3
Total recognized in total other comprehensive loss (income)(a)	(27)	(4)	(26)
Total recognized in net benefit cost (credit) and other comprehensive loss (income)	$ (52)	$ (22)	$ (43)

Share-based Compensation and_14

Share-based Compensation and Employee Benefits - Other Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Multiemployer Plans
Amounts charged to expense	$ 6	$ 8	$ 8

Stockholders' Equity - Mandator

Stockholders' Equity - Mandatory Convertible Preferred Stock (Details) - $ / shares	Oct. 26, 2018	Dec. 31, 2018
9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference
Class of Stock [Line Items]
Preferred stock, shares issued (in shares)	1,600,000
Preferred Stock, Dividend Rate, Percentage	9.75%
Liquidation preference	$ 1,000
Common stock
Class of Stock [Line Items]
Mandatory conversion of preferred shares (shares)		58,000,000
Common stock | Mandatorily Redeemable Preferred Stock
Class of Stock [Line Items]
Mandatory conversion of preferred shares (shares)		58,000,000

Stockholders' Equity - Common E

Stockholders' Equity - Common Equity (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 20, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	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		$ 50	$ 2	$ 273	$ 575
Common share buy-back program, average price per share					$ 17.71
Per common share cash dividend declared for the period		$ 1.05	$ 1	$ 0.80
Per common share cash dividend paid in the period		$ 1.0375	$ 0.95	$ 0.725
Subsequent Event
Class of Stock [Line Items]
Per common share cash dividend declared for the period	$ 0.2625
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		4,000,000	100,000	15,000,000	32,000,000

Stockholders' Equity - Accumula

Stockholders' Equity - Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	$ 34,086	$ 34,531	$ 35,124
Balance	31,838	34,086	34,531
Net unrealized gains/(losses) on cash flow hedge derivatives
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(7)	164	(27)
Other comprehensive (loss) gain before reclassifications	249	(177)	111
Losses (gains) reclassified from accumulated other comprehensive loss	(255)	6	84
Impact of adoption of ASU 2018-02 (see below)			(4)
Net current-period change in accumulated other comprehensive (loss) income	(6)	(171)	191
Balance	(13)	(7)	164
Foreign currency translation adjustments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	0	(91)	(189)
Other comprehensive (loss) gain before reclassifications	0	0	(89)
Losses (gains) reclassified from accumulated other comprehensive loss	0	91	223
Impact of adoption of ASU 2018-02 (see below)			(36)
Net current-period change in accumulated other comprehensive (loss) income	0	91	98
Balance	0	0	(91)
Pension and other postretirement liability adjustments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(326)	(403)	(325)
Other comprehensive (loss) gain before reclassifications	(68)	77	(31)
Losses (gains) reclassified from accumulated other comprehensive loss	0	0	22
Impact of adoption of ASU 2018-02 (see below)			(69)
Net current-period change in accumulated other comprehensive (loss) income	(68)	77	(78)
Balance	(394)	(326)	(403)
Total Accumulated other comprehensive loss
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance	(333)	(330)	(541)
Other comprehensive (loss) gain before reclassifications	181	(100)	(9)
Losses (gains) reclassified from accumulated other comprehensive loss	(255)	97	329
Impact of adoption of ASU 2018-02 (see below)			(109)
Net current-period change in accumulated other comprehensive (loss) income	(74)	(3)	211
Balance	$ (407)	$ (333)	$ (330)

Stockholders' Equity - Noncontr

Stockholders' Equity - Noncontrolling Interests (Details) $ in Millions, $ in Billions	Jan. 03, 2019USD ($)	Jan. 03, 2019CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)shares
Cash distributions paid in the period to the public			$ 2,362	$ 2,163	$ 1,618
Dividends, Preferred Stock, Cash					128
Payments to noncontrolling interests	$ 900	$ 1.2	$ 0	879	0
Kinder Morgan Canada Limited
Cash distributions paid in the period to the public				17	38
Value of Restricted Shares Issued in Lieu of Cash Dividends					$ 14
Common Stock Dividends, Shares | shares					1,092,791
Dividends, Preferred Stock, Cash				22	$ 21
Restricted Voting Shares | Kinder Morgan Canada Limited
Total value of distributions paid in the period				$ 17	$ 52

Stockholders' Equity - New Acco

Stockholders' Equity - New Accounting Pronouncements (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity	$ 31,838	$ 34,086	$ 34,531	$ 35,124
Impact of Adoption of ASU
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity			(4)	66
Accumulated deficit
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity	(9,936)	(7,693)	(7,716)	(7,754)
Accumulated deficit | Impact of Adoption of ASU
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity			(4)	175
Accumulated other comprehensive loss
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity	$ (407)	$ (333)	$ (330)	(541)
Accumulated other comprehensive loss | Impact of Adoption of ASU
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity				(109)
Accounting Standards Update 2017-05 | Accumulated deficit | Impact of Adoption of ASU
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity				66
Accounting Standards Update 2018-02 | Accumulated deficit | Impact of Adoption of ASU
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity				109
Accounting Standards Update 2018-02 | Accumulated other comprehensive loss | Impact of Adoption of ASU
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity				$ (109)

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
RELATED PARTY ASSETS
Accounts receivable	$ 41	$ 38
Other current assets	6	0
Deferred charges and other assets	109	86
Total Assets	156	124
RELATED PARTY LIABILITIES
Current portion of debt	6	6
Accounts payable	25	23
Other current liabilities	4	3
Long-term debt	154	157
Other long-term liabilities and deferred credits	48	41
Total Liabilities	237	230
RELATED PARTY REVENUES
Revenues	11,700	13,209	$ 14,144
RELATED PARTY OPERATING COSTS, EXPENSES AND OTHER
Cost of Sales	2,545	3,263	4,421
Other operating expenses	(2)	(3)	(3)
Affiliated Entity [Member]
RELATED PARTY REVENUES
Revenues	206	269	265
RELATED PARTY OPERATING COSTS, EXPENSES AND OTHER
Cost of Sales	116	75	63
Other operating expenses	$ 119	$ 132	$ 91

Commitments and Contingent Li_2

Commitments and Contingent Liabilities Rights-of-way obligations (Details) $ in Millions	Dec. 31, 2020USD ($)
Class of Warrant or Right [Line Items]
Lessee, Operating Lease, Liability, Payments, Due	$ 412
ROW
Class of Warrant or Right [Line Items]
Lessee, Operating Lease, Liability, Payments, Due	$ 172

Commitments and Contingent Li_3

Commitments and Contingent Liabilities Contingent Debt (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Indirect Guarantee of Indebtedness [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 217	$ 330
Number of equity investees subject to contingent obligation	3	3
Cortez Pipeline Company
Guarantor Obligations [Line Items]
Percentage of Debt Guaranteed	100.00%	100.00%
Long-term Debt | Indirect Guarantee of Indebtedness [Member] | Cortez Pipeline Company
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 122	$ 128

Commitments and Contingent Li_4

Commitments and Contingent Liabilities Guarantees and Indemnifications (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Guarantor Obligations [Line Items]
Commitments and contingencies (Notes 9, 13, 17 and 18)
SNG
Guarantor Obligations [Line Items]
Short-term Debt	300
SNG | Short-term Debt [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 150

Risk Management - Energy Commod

Risk Management - Energy Commodity Price Risk Management (Details) - Short - Energy commodity derivative contracts	12 Months Ended
	Dec. 31, 2020MMBblsBcf
Designated as Hedging Instrument | Crude Oil Fixed Price
Derivative [Line Items]
Net open position	(20.4)
Designated as Hedging Instrument | Crude Oil Basis
Derivative [Line Items]
Net open position	(2.2)
Designated as Hedging Instrument | Natural Gas Fixed Price
Derivative [Line Items]
Net open position | Bcf	(30.1)
Designated as Hedging Instrument | Natural Gas Basis
Derivative [Line Items]
Net open position | Bcf	(20)
Designated as Hedging Instrument | NGL Fixed Price
Derivative [Line Items]
Net open position	(1.1)
Not Designated as Hedging Instrument | Crude Oil Fixed Price
Derivative [Line Items]
Net open position	(5.6)
Not Designated as Hedging Instrument | Crude Oil Basis
Derivative [Line Items]
Net open position	(6.8)
Not Designated as Hedging Instrument | Natural Gas Fixed Price
Derivative [Line Items]
Net open position | Bcf	(6.7)
Not Designated as Hedging Instrument | Natural Gas Basis
Derivative [Line Items]
Net open position | Bcf	(5.5)
Not Designated as Hedging Instrument | NGL Fixed Price
Derivative [Line Items]
Net open position	(1)

Risk Management - Interest Rate

Risk Management - Interest Rate Risk Management (Details) $ in Millions	Dec. 31, 2020USD ($)
Fair Value Hedging | Fixed-To-Variable Interest Rate Contracts [Member] | Designated as Hedging Instrument
Derivative [Line Items]
Notional amount	$ 7,625
Fair Value Hedging | Floating-To-Fixed Interest Rate Contracts [Member] | Not Designated as Hedging Instrument
Derivative [Line Items]
Notional amount	2,500
Cash Flow Hedging | Floating-To-Fixed Interest Rate Contracts [Member] | Designated as Hedging Instrument
Derivative [Line Items]
Notional amount	250
Current Portion of Debt | Fixed-To-Variable Interest Rate Contracts [Member]
Derivative [Line Items]
Principal amount of hedged senior notes	900
Long-term Debt | Fixed-To-Variable Interest Rate Contracts [Member]
Derivative [Line Items]
Principal amount of hedged senior notes	$ 6,725

Risk Management - Foreign Curre

Risk Management - Foreign Currency Risk Management (Details) $ in Millions	Dec. 31, 2020USD ($)
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, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Asset derivatives	$ 931	$ 460
Liability derivatives	(78)	(65)
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	99	56
Liability derivatives	(63)	(58)
Interest rate contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	694	358
Liability derivatives	(10)	(1)
Foreign currency contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	138	46
Liability derivatives	(6)	(6)
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Asset derivatives	907	452
Liability derivatives	(57)	(58)
Designated as Hedging Instrument | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	75	48
Liability derivatives	(41)	(51)
Designated as Hedging Instrument | Energy commodity derivative contracts | Fair Value of Derivatives Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	42	31
Designated as Hedging Instrument | Energy commodity derivative contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liability derivatives	(33)	(43)
Designated as Hedging Instrument | Energy commodity derivative contracts | Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	33	17
Designated as Hedging Instrument | Energy commodity derivative contracts | Other Long-Term Liabilities and Deferred Credits
Derivatives, Fair Value [Line Items]
Liability derivatives	(8)	(8)
Designated as Hedging Instrument | Interest rate contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	694	358
Liability derivatives	(10)	(1)
Designated as Hedging Instrument | Interest rate contracts | Fair Value of Derivatives Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	119	45
Designated as Hedging Instrument | Interest rate contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liability derivatives	(3)	0
Designated as Hedging Instrument | Interest rate contracts | Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	575	313
Designated as Hedging Instrument | Interest rate contracts | Other Long-Term Liabilities and Deferred Credits
Derivatives, Fair Value [Line Items]
Liability derivatives	(7)	(1)
Designated as Hedging Instrument | Foreign currency contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	138	46
Liability derivatives	(6)	(6)
Designated as Hedging Instrument | Foreign currency contracts | Fair Value of Derivatives Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Designated as Hedging Instrument | Foreign currency contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liability derivatives	(6)	(6)
Designated as Hedging Instrument | Foreign currency contracts | Deferred Charges and Other Assets
Derivatives, Fair Value [Line Items]
Asset derivatives	138	46
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 | Energy commodity derivative contracts | Fair Value of Derivatives Contracts
Derivatives, Fair Value [Line Items]
Asset derivatives	24	8
Not Designated as Hedging Instrument | Energy commodity derivative contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Liability derivatives	$ (21)	$ (7)

Risk Management - FV Input Leve

Risk Management - FV Input Level - Assets (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Gross amount	$ 931	$ 460
Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	99	56
Contracts available for netting	(35)	(19)
Cash collateral held(b)	0	(21)
Net amount	64	16
Interest rate contracts
Derivative [Line Items]
Gross amount	694	358
Contracts available for netting	(2)	0
Cash collateral held(b)	0	0
Net amount	692	358
Foreign currency contracts
Derivative [Line Items]
Gross amount	138	46
Contracts available for netting	(6)	(6)
Cash collateral held(b)	0	0
Net amount	132	40
Level 1 | Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	6	19
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	93	37
Level 2 | Interest rate contracts
Derivative [Line Items]
Gross amount	694	358
Level 2 | Foreign currency contracts
Derivative [Line Items]
Gross amount	138	46
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, 2020	Dec. 31, 2019
Derivative [Line Items]
Gross amount	$ (78)	$ (65)
Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	(63)	(58)
Contracts available for netting	35	19
Collateral posted(b)	(8)	0
Net amount	(36)	(39)
Interest rate contracts
Derivative [Line Items]
Gross amount	(10)	(1)
Contracts available for netting	2	0
Collateral posted(b)	0	0
Net amount	(8)	(1)
Foreign currency contracts
Derivative [Line Items]
Gross amount	(6)	(6)
Contracts available for netting	6	6
Collateral posted(b)	0	0
Net amount	0	0
Level 1 | Energy commodity derivative contracts
Derivative [Line Items]
Gross amount	(7)	(3)
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	(56)	(55)
Level 2 | Interest rate contracts
Derivative [Line Items]
Gross amount	(10)	(1)
Level 2 | Foreign currency contracts
Derivative [Line Items]
Gross amount	(6)	(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, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Cumulative amount of fair value hedging adjustments to hedged fixed rate debt	$ 702	$ 359
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	702
Designated as Hedging Instrument | Fair Value Hedging | Interest, net [Member] | Interest Rate Contract
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives and related hedged item	335	340	$ (122)
Designated as Hedging Instrument | Fair Value Hedging | Interest, net [Member] | Hedged Fixed Rate Debt
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives and related hedged item	$ (343)	$ (353)	$ 113

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	$ 324	$ (229)	$ 145
Gain/(loss) reclassified from Accumulated OCI into income	333	(8)	(109)
Loss to be reclassified within twelve months	9
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	240	(168)	201
Energy commodity derivative contracts | Commodity Sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	222	16	(59)
Energy commodity derivative contracts | Cost of Sales
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	(14)	5	21
Energy commodity derivative contracts | Write-Down Of Hedged Inventory
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income		12	21
Energy commodity derivative contracts | Earnings from Equity Investments
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net			3
Interest rate contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	(8)	(1)	3
Interest rate contracts | Earnings from Equity Investments
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	0	2	(4)
Foreign currency contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative	92	(60)	(59)
Foreign currency contracts | Other, Net
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income	$ 125	$ (31)	$ (67)

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	$ 0	$ (8)	$ 91
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	83	26
Foreign Exchange Contract [Member]
Derivative [Line Items]
Gain/(loss) recognized in OCI on derivative	0	(8)	91
Loss (gain) on impairments and divestitures, net | Foreign Exchange Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 0	83	26
KML and U.S. Portion of Cochin Pipeline System | Foreign Exchange Contract [Member]
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income		$ 83
Trans Mountain and Trans Mountain Expansion Project | Foreign Exchange Contract [Member]
Derivative [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income			$ 26

Risk Management - Not Designate

Risk Management - Not Designated as Hedges Effect on Income Statements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ 24	$ 29	$ (7)
Energy commodity derivative contracts
Derivative [Line Items]
Loss on Derivative Instruments		8	4
Gain on Derivative Instruments	11
Commodity Sales | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	(1)	33	(9)
Cost of Sales | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	25	(7)	2
Earnings from Equity Investments | Energy commodity derivative contracts
Derivative [Line Items]
Gain/(loss) recognized in income on derivatives	$ 0	$ 3	$ 0

Risk Management - Credit Risks

Risk Management - Credit Risks (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	$ 6
Energy commodity derivative contracts
Credit Derivatives [Line Items]
Letters of credit outstanding	0	$ 0
Initial Margin Requirements	11
Variation Margin Requirements	8
Other Current Liabilities | Contract and Over the Counter | Energy commodity derivative contracts
Credit Derivatives [Line Items]
Derivative, Collateral, Obligation to Return Cash	$ 3	$ 15

Revenue Recognition - Schedule

Revenue Recognition - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 10,097	$ 12,080	$ 13,318
Leasing services	1,236	951	868
Other	146	129	91
Total other revenues	1,603	1,129	826
Total revenues	11,700	13,209	14,144
Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,370	4,877	4,746
Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,056	2,416	2,466
Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,426	7,293	7,212
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,032	2,595	3,318
Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,639	2,192	2,788
Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,671	4,787	6,106
Total revenues	3,891	4,811	5,987
Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	7,222	8,128	8,807
Products Pipelines
Disaggregation of Revenue [Line Items]
Total revenues	1,721	1,831	1,887
Terminals
Disaggregation of Revenue [Line Items]
Total revenues	1,719	2,031	2,025
CO2
Disaggregation of Revenue [Line Items]
Total revenues	1,038	1,219	1,255
Kinder Morgan Canada
Disaggregation of Revenue [Line Items]
Total revenues	0	0	170
Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,659	7,737	8,596
Leasing services	466	273	220
Other	116	90	64
Total other revenues	600	433	259
Total revenues	7,259	8,170	8,855
Operating Segments | Natural Gas Pipelines | Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,345	3,549	3,387
Operating Segments | Natural Gas Pipelines | Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	714	780	692
Operating Segments | Natural Gas Pipelines | Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,059	4,329	4,079
Operating Segments | Natural Gas Pipelines | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,038	2,603	3,327
Operating Segments | Natural Gas Pipelines | Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	562	805	1,190
Operating Segments | Natural Gas Pipelines | Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,600	3,408	4,517
Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,534	1,624	1,725
Leasing services	166	182	158
Other	21	25	4
Total other revenues	187	207	162
Total revenues	1,721	1,831	1,887
Operating Segments | Products Pipelines | Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	271	319	376
Operating Segments | Products Pipelines | Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	905	1,016	956
Operating Segments | Products Pipelines | Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,176	1,335	1,332
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	358	289	393
Operating Segments | Products Pipelines | Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	358	289	393
Operating Segments | Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,165	1,592	1,587
Leasing services	557	442	440
Other	0	0	0
Total other revenues	557	442	440
Total revenues	1,722	2,034	2,027
Operating Segments | Terminals | Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	756	1,012	983
Operating Segments | Terminals | Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	395	560	584
Operating Segments | Terminals | Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,151	1,572	1,567
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	14	20	20
Operating Segments | Terminals | Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	14	20	20
Operating Segments | CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	779	1,173	1,293
Leasing services	47	54	48
Other	9	13	22
Total other revenues	259	46	(38)
Total revenues	1,038	1,219	1,255
Operating Segments | CO2 | Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1	1	2
Operating Segments | CO2 | Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	42	60	67
Operating Segments | CO2 | Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	43	61	69
Operating Segments | CO2 | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1	1	2
Operating Segments | CO2 | Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	735	1,111	1,222
Operating Segments | CO2 | Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	736	1,112	1,224
Operating Segments | Kinder Morgan Canada
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers			167
Leasing services			2
Other			1
Total other revenues			3
Total revenues			170
Operating Segments | Kinder Morgan Canada | Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers			0
Operating Segments | Kinder Morgan Canada | Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers			167
Operating Segments | Kinder Morgan Canada | Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers			167
Operating Segments | Kinder Morgan Canada | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers			0
Operating Segments | Kinder Morgan Canada | Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers			0
Operating Segments | Kinder Morgan Canada | Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers			0
Corporate and Eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(40)	(46)	(50)
Leasing services	0	0	0
Other	0	1	0
Total other revenues	0	1	0
Total revenues	(40)	(45)	(50)
Corporate and Eliminations | Firm services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(3)	(4)	(2)
Corporate and Eliminations | Fee-based services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Corporate and Eliminations | Total services
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(3)	(4)	(2)
Corporate and Eliminations | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(7)	(9)	(11)
Corporate and Eliminations | Product sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(30)	(33)	(37)
Corporate and Eliminations | Total commodity sales
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(37)	(42)	(48)
Sales
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	221	49	(133)
Sales | Operating Segments | Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	18	70	(25)
Sales | Operating Segments | Products Pipelines
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales	0	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	203	(21)	(108)
Sales | Operating Segments | Kinder Morgan Canada
Disaggregation of Revenue [Line Items]
Derivatives adjustments on commodity sales			0
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, 2020	Dec. 31, 2019
Contract Assets
Contract assets balances	$ 20	$ 27
Transfer to accounts receivable	24
Contract Liabilities
Contract liability balances	239	$ 232
Transfer to revenues	$ 65

Revenue Recognition - Revenue A

Revenue Recognition - Revenue Allocated to Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2020USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated Revenue	$ 28,403
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Estimated Revenue	$ 4,281
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	$ 3,500
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	$ 2,824
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	$ 2,439
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	$ 2,073
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
Estimated Revenue	$ 13,286

Reportable Segments Revenues (D

Reportable Segments Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Revenues	$ 11,700	$ 13,209	$ 14,144
Other
Segment Reporting Information [Line Items]
Revenues	(40)	(45)	(50)
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(40)	(45)	(50)
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Revenues	7,222	8,128	8,807
Natural Gas Pipelines | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(37)	(42)	(48)
Products Pipelines
Segment Reporting Information [Line Items]
Revenues	1,721	1,831	1,887
Terminals
Segment Reporting Information [Line Items]
Revenues	1,719	2,031	2,025
Terminals | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(3)	(3)	(2)
CO2
Segment Reporting Information [Line Items]
Revenues	1,038	1,219	1,255
Kinder Morgan Canada
Segment Reporting Information [Line Items]
Revenues	$ 0	$ 0	$ 170
Revenues from External Customers [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	10.00%	10.00%	10.00%
Single customer exceeding 10% of total [Member]
Segment Reporting Information [Line Items]
Revenues	$ 0	$ 0	$ 0

Reportable Segments Operating e

Reportable Segments Operating expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Operating expenses(a)	$ 5,398	$ 6,280	$ 7,288
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Operating expenses(a)	3,457	4,213	5,218
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Operating expenses(a)	779	684	748
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Operating expenses(a)	762	888	823
Operating Segments | CO2
Segment Reporting Information [Line Items]
Operating expenses(a)	404	496	453
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Operating expenses(a)	0	0	72
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating expenses(a)	$ (4)	$ (1)	$ (26)

Reportable Segments Other expen

Reportable Segments Other expense (income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Other expense (income)(b)	$ 1,930	$ (945)	$ 164
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other expense (income)(b)	1,009	(680)	629
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Other expense (income)(b)	21	0	(2)
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Other expense (income)(b)	(50)	(342)	54
Operating Segments | CO2
Segment Reporting Information [Line Items]
Other expense (income)(b)	950	77	79
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Other expense (income)(b)	0	2	(596)
Other
Segment Reporting Information [Line Items]
Other expense (income)(b)	$ 0	$ (2)	$ 0

Reportable Segments Depreciatio

Reportable Segments Depreciation, depletion and amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
DD&A	$ 2,164	$ 2,411	$ 2,297
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
DD&A	1,062	1,005	955
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
DD&A	347	338	326
Operating Segments | Terminals
Segment Reporting Information [Line Items]
DD&A	438	494	489
Operating Segments | CO2
Segment Reporting Information [Line Items]
DD&A	291	548	473
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
DD&A	0	0	29
Other
Segment Reporting Information [Line Items]
DD&A	$ 26	$ 26	$ 25

Reportable Segments Earnings (l

Reportable Segments Earnings (loss) from equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 640	$ 18	$ 522
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	551	(101)	410
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	45	63	56
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	22	23	22
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	$ 22	$ 33	$ 34

Reportable Segments Other, net-

Reportable Segments Other, net-income(expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Other, net	$ 56	$ 75	$ 107
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other, net	11	53	39
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Other, net	1	6	2
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Other, net	13	(5)	3
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Other, net	0	0	26
Other
Segment Reporting Information [Line Items]
Other, net	$ 31	$ 21	$ 37

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
DD&A	$ (2,164)	$ (2,411)	$ (2,297)
Amortization of excess cost of equity investments	(140)	(83)	(95)
General and administrative and corporate charges	(648)	(590)	(601)
Interest, net	(1,595)	(1,801)	(1,917)
Income tax expense	(481)	(926)	(587)
Net Income	180	2,239	1,919
Total Segments EBDA(e)
Segment Reporting Information [Line Items]
Segment EBDA(c)	5,213	8,071	7,403
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(c)	3,483	4,661	3,540
DD&A	(1,062)	(1,005)	(955)
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(c)	977	1,225	1,209
DD&A	(347)	(338)	(326)
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Segment EBDA(c)	1,045	1,506	1,175
DD&A	(438)	(494)	(489)
Operating Segments | CO2
Segment Reporting Information [Line Items]
Segment EBDA(c)	(292)	681	759
DD&A	(291)	(548)	(473)
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Segment EBDA(c)	0	(2)	720
DD&A	0	0	(29)
Other
Segment Reporting Information [Line Items]
DD&A	(26)	(26)	(25)
General and administrative and corporate charges	$ (653)	$ (611)	$ (588)

Reportable Segments Capital exp

Reportable Segments Capital expenditures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Capital expenditures	$ 1,707	$ 2,270	$ 2,904
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	945	1,377	1,565
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	122	175	199
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Capital expenditures	433	347	386
Operating Segments | CO2
Segment Reporting Information [Line Items]
Capital expenditures	186	349	397
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Capital expenditures	0	0	332
Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 21	$ 22	$ 25

Reportable Segments Investments

Reportable Segments Investments (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Investments	$ 7,917	$ 7,759
Natural Gas Pipelines | Operating Segments
Segment Reporting Information [Line Items]
Investments	7,262	6,991
Products Pipelines | Operating Segments
Segment Reporting Information [Line Items]
Investments	494	491
Terminals | Operating Segments
Segment Reporting Information [Line Items]
Investments	136	251
CO2 | Operating Segments
Segment Reporting Information [Line Items]
Investments	$ 25	$ 26

Reportable Segments Assets (Det

Reportable Segments Assets (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Assets	$ 71,973	$ 74,157
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets	48,597	50,310
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Assets	9,182	9,468
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Assets	8,639	8,890
Operating Segments | CO2
Segment Reporting Information [Line Items]
Assets	2,478	3,523
Other
Segment Reporting Information [Line Items]
Assets	$ 3,077	$ 1,966

Reportable Segments Geographica

Reportable Segments Geographical information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Revenues	$ 11,700	$ 13,209	$ 14,144
Long-term assets, excluding goodwill and other intangibles	46,466	46,792	48,299
U.S.
Segment Reporting Information [Line Items]
Revenues	11,625	12,833	13,596
Long-term assets, excluding goodwill and other intangibles	46,384	46,709	47,468
Canada
Segment Reporting Information [Line Items]
Revenues	0	300	447
Long-term assets, excluding goodwill and other intangibles	1	1	748
Mexico and other foreign
Segment Reporting Information [Line Items]
Revenues	75	76	101
Long-term assets, excluding goodwill and other intangibles	$ 81	$ 82	$ 83

Leases - Lessee (Details)

Leases - Lessee (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lease, Cost [Abstract]
Operating leases	$ 55	$ 136
Short-term and variable leases	101	92
Total lease cost(a)	156	228
Lease Costs Capitalized	25	46
Lessee, Operating Lease, Description [Abstract]
Operating cash flows from operating leases	(131)	(182)
Investing cash flows from operating leases	(25)	(46)
ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion	20	399
Amortization of ROU assets	$ 46	$ 75
Weighted average remaining lease term	11 years 6 months 21 days	13 years 4 months 24 days
Weighted average discount rate	4.27%	4.31%
Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:OtherAssetsNoncurrent	us-gaap:OtherAssetsNoncurrent
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:OtherAccruedLiabilitiesCurrent	us-gaap:OtherAccruedLiabilitiesCurrent
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:DeferredCreditsAndOtherLiabilitiesNoncurrent	us-gaap:DeferredCreditsAndOtherLiabilitiesNoncurrent
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:PropertyPlantAndEquipmentNet	us-gaap:PropertyPlantAndEquipmentNet
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:LongTermDebtNoncurrent	us-gaap:LongTermDebtNoncurrent
ROU assets	$ 303	$ 329
Short-term lease liability	40	40
Long-term lease liability	263	289
Finance lease assets	1	2
Finance lease liabilities	1	2
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2021	53
2022	46
2023	38
2024	34
2025	30
Thereafter	211
Total lease payments	412
Less: Interest	(109)
Present value of lease liabilities	303
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	0	(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	$ 20	$ 102

Litigation and Environmental -

Litigation and Environmental - Federal Energy Regulatory Commission Proceedings (Details) - Federal Energy Regulatory Commission - Unfavorable Regulatory Action - Pending Litigation $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)claims
SFPP | Rate Refunds, and Reductions Not Resolved in East Line Settlement
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value | $	$ 50
EPNG
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number | claims	2
Reparations, Refunds and Rate Reductions | SFPP
Loss Contingencies [Line Items]
Loss Contingency Period of Time Litigation Concerns	2 years

Litigation and Environmental _2

Litigation and Environmental - Other Commercial Matters (Details) - Hiland Partners Holdings, LLC - Pending Litigation $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)	Jun. 01, 2018projects
Loss Contingencies [Line Items]
Infrastructures to Build for Settlement | projects		10
Loss Contingency, Damages Sought, Value | $	$ 225

Litigation and Environmental _3

Litigation and Environmental - General (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Loss Contingency, Information about Litigation Matters [Abstract]
Estimated Litigation Liability	$ 273	$ 203

Litigation and Environmental _4

Litigation and Environmental - Portland (Details) - Environmental Protection Agency - Portland Harbor Superfund Site, Willamette River, Portland, Oregon $ in Billions	Jan. 06, 2017USD ($)	Dec. 31, 2020TerminalsParties
GATX Terminals Corporation (n/k/a KMLT)
Accrual for Environmental Loss Contingencies, Gross | $	$ 1.1
Estimated Remedy Implementation Period	13 years
Number of Parties Involved In Site Cleanup Allocation Negotiations | Parties		90
Number of Liquid Terminals		2
KMBT
Number of Liquid Terminals		2

Litigation and Environmental _5

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

Litigation and Environmental _6

Litigation and Environmental - Lower Passaic River (Details) - Pending Litigation $ in Millions	Oct. 05, 2016USD ($)mi	Mar. 04, 2016USD ($)mi	Dec. 31, 2020miParties
Lower Passaic River Study Area
Site Contingency [Line Items]
Miles of river | mi			17
Number of Parties at a Joint Defense Group | Parties			44
Lower Passaic River Study Area | EPA preferred alternative estimate
Site Contingency [Line Items]
Environmental Remediation Expense | $		$ 1,700
Lower Passaic River Study Area | AOC required engineering and design work
Site Contingency [Line Items]
Environmental Remediation Expense | $	$ 165
Lower Passaic River Study Area | Design
Site Contingency [Line Items]
Estimated Remedy Implementation Period	4 years
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 | mi	8	8	8

Litigation and Environmental _7

Litigation and Environmental - Louisiana Governmental (Details) - Coastal Zone	Mar. 29, 2019Parties	Nov. 08, 2013Parties	Dec. 31, 2020cases
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 _8

Litigation and Environmental - Louisiana Landowner (Details) - Judicial District of Louisiana - Louisiana Landowner Coastal Erosion Litigation	Jan. 31, 2015
TGP
Loss Contingency, Pending Claims, Number	2
SNG
Loss Contingency, Pending Claims, Number	2
TGP and SNG
Loss Contingency, Pending Claims, Number	2

Litigation and Environmental _9

Litigation and Environmental - Environmental Matters - General (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Loss Contingency, Information about Litigation Matters [Abstract]
Accrual for Environmental Loss Contingencies	$ 250	$ 259
Recorded Third-Party Environmental Recoveries Receivable	$ 12	$ 15

Uncategorized Items - kmi-20201

Label	Element	Value
Accounting Standards Update [Extensible List]	us-gaap_AccountingStandardsUpdateExtensibleList	us-gaap:AccountingStandardsUpdate201705Member us-gaap:AccountingStandardsUpdate201802Member