Kinder Morgan (KMI) 10-K 8 Feb 19 2018 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 07, 2019	Jun. 29, 2018
Entity [Abstract]
Entity Registrant Name	Kinder Morgan, Inc.
Entity Central Index Key	1,506,307
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Shell Company	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 33,499,494,320
Entity Common Stock, Shares Outstanding		2,263,656,419
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues
Total Revenues	$ 14,144	$ 13,705	$ 13,058
Operating Costs, Expenses and Other
Costs of sales	4,421	4,345	3,429
Operations and maintenance	2,522	2,472	2,372
Depreciation, depletion and amortization	2,297	2,261	2,209
General and administrative	601	688	703
Taxes, other than income taxes	345	398	421
Loss on impairments and divestitures, net	167	13	387
Other income, net	(3)	(1)	(1)
Total Operating Costs, Expenses and Other	10,350	10,176	9,520
Operating Income	3,794	3,529	3,538
Other Income (Expense)
Earnings from equity investments	887	578	497
Loss on impairments and divestitures of equity investments, net	(270)	(150)	(610)
Amortization of excess cost of equity investments	(95)	(61)	(59)
Interest, net	(1,917)	(1,832)	(1,806)
Other, net	107	97	78
Total Other Expense	(1,288)	(1,368)	(1,900)
Income Before Income Taxes	2,506	2,161	1,638
Income Tax Expense	(587)	(1,938)	(917)
Net Income	1,919	223	721
Net Income Attributable to Noncontrolling Interests	(310)	(40)	(13)
Net Income Attributable to Kinder Morgan, Inc.	1,609	183	708
Preferred Stock Dividends	(128)	(156)	(156)
Net Income Available to Common Stockholders	$ 1,481	$ 27	$ 552
Class P Shares
Basic and Diluted Earnings Per Common Share	$ 0.66	$ 0.01	$ 0.25
Basic and Diluted Weighted Average Common Shares Outstanding	2,216	2,230	2,230
Dividends Per Common Share Declared for the Period	$ 0.8	$ 0.5	$ 0.5
Natural gas sales [Member]
Revenues
Total Revenues	$ 3,281	$ 3,053	$ 2,454
Services [Member]
Revenues
Total Revenues	7,931	7,901	8,146
Revenues—Product sales and other
Revenues
Total Revenues	$ 2,932	$ 2,751	$ 2,458

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net income	$ 1,919	$ 223	$ 721
Other comprehensive income (loss), net of tax
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(34), $(82) and $60, respectively)	111	145	(104)
Reclassification of change in fair value of derivatives to net income (net of tax (expense) benefit of $(25), $97 and $67, respectively)	84	(171)	(116)
Foreign currency translation adjustments (net of tax expense of $16, $56 and $20, respectively)	141	101	34
Benefit plan adjustments (net of tax (expense) benefit of $(11), $(27) and $19, respectively)	2	40	(14)
Total other comprehensive income (loss)	338	115	(200)
Comprehensive income	2,257	338	521
Comprehensive income attributable to noncontrolling interests	(328)	(86)	(13)
Comprehensive income attributable to KMI	$ 1,929	$ 252	$ 508

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME, TAX (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Total, Tax
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(34), $(82) and $60, respectively)	$ (34)	$ (82)	$ 60
Reclassification of change in fair value of derivatives to net income (net of tax (expense) benefit of $(25), $97 and $67, respectively)	(25)	97	67
Foreign currency translation adjustments (net of tax expense of $16, $56 and $20, respectively)	(16)	(56)	(20)
Benefit plan adjustments (net of tax (expense) benefit of $(11), $(27) and $19, respectively)	$ (11)	$ (27)	$ 19

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 3,280	$ 264
Restricted deposits	51	62
Accounts receivable, net	1,498	1,448
Fair value of derivative contracts	260	114
Inventories	385	424
Income tax receivable	23	165
Other current assets	225	238
Total current assets	5,722	2,715
Property, plant and equipment, net	37,897	40,155
Investments	7,481	7,298
Goodwill	21,965	22,162
Other intangibles, net	2,880	3,099
Deferred income taxes	1,566	2,044
Deferred charges and other assets	1,355	1,582
Total Assets	78,866	79,055
Current liabilities
Current portion of debt	3,388	2,828
Accounts payable	1,337	1,340
Distributions payable to KML noncontrolling interests	876	0
Accrued interest	579	621
Accrued taxes	483	256
Accrued contingencies	88	291
Other current liabilities	806	845
Total current liabilities	7,557	6,181
Long-term debt
Outstanding	33,105	33,988
Preferred interest in general partner of KMP	100	100
Debt fair value adjustments	731	927
Total long-term debt	33,936	35,015
Other long-term liabilities and deferred credits	2,176	2,735
Total long-term liabilities and deferred credits	36,112	37,750
Total Liabilities	43,669	43,931
Commitments and contingencies (Notes 9, 13 and 18)
Redeemable Noncontrolling Interest	666	0
Stockholders’ Equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference, - and 1,600,000 shares, respectively, issued and outstanding	0	0
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,262,165,783 and 2,217,110,072 shares, respectively, issued and outstanding	23	22
Additional paid-in capital	41,701	41,909
Retained deficit	(7,716)	(7,754)
Accumulated other comprehensive loss	(330)	(541)
Total Kinder Morgan, Inc.’s stockholders’ equity	33,678	33,636
Noncontrolling interests	853	1,488
Total Stockholders’ Equity	34,531	35,124
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$ 78,866	$ 79,055

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Stockholders’ Equity
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (in shares)	10,000,000	10,000,000
Preferred stock, shares issued (in shares)	0	1,600,000
Preferred stock, shares outstanding (in shares)	0	1,600,000
9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference	$ 1,000	$ 1,000
9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference	9.75%	9.75%
Class P
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)	2,262,165,783	2,217,110,072
Common stock, shares outstanding (in shares)	2,262,165,783	2,217,110,072

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flows From Operating Activities
Net income	$ 1,919	$ 223	$ 721
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	2,297	2,261	2,209
Deferred income taxes	405	2,073	1,087
Amortization of excess cost of equity investments	95	61	59
Change in fair market value of derivative contracts	77	40	64
Loss (gain) on early extinguishment of debt	0	4	(45)
Loss on impairments and divestitures, net (Note 4)	167	13	387
Loss on impairments and divestitures of equity investments, net (Note 4)	270	150	610
Earnings from equity investments	(887)	(578)	(497)
Distributions of equity investment earnings	499	426	431
Changes in components of working capital, net of the effects of acquisitions and dispositions
Accounts receivable, net	(50)	(78)	(107)
Income tax receivable	137	7	(148)
Inventories	15	(90)	49
Other current assets	(16)	(25)	(81)
Accounts payable	21	73	144
Accrued interest, net of interest rate swaps	(22)	10	(18)
Accrued taxes	241	(37)	31
Accrued contingencies and other current liabilities	73	138	11
Rate reparations, refunds and other litigation reserve adjustments	(202)	(100)	(32)
Other, net	4	30	(117)
Net Cash Provided by Operating Activities	5,043	4,601	4,758
Cash Flows From Investing Activities
Proceeds from the TMPL Sale, net of cash disposed (Note 3)	2,998	0	0
Acquisitions of assets and investments	(39)	(4)	(333)
Capital expenditures	(2,904)	(3,188)	(2,882)
Proceeds from sale of equity interests in subsidiaries, net	0	0	1,401
Proceeds from sales of equity investments	124	0	0
Sales of property, plant and equipment, investments, and other net assets, net of removal costs	(20)	118	330
Contributions to investments	(433)	(684)	(408)
Distributions from equity investments in excess of cumulative earnings	237	374	231
Loans (to) from related parties	(31)	(23)
Loans (to) from related parties			35
Other, net	0	4	1
Net Cash Used in Investing Activities	(68)	(3,403)	(1,625)
Cash Flows From Financing Activities
Issuances of debt	14,751	8,868	8,629
Payments of debt	(14,591)	(11,064)	(10,060)
Debt issue costs	(42)	(70)	(19)
Cash dividends - common shares (Note 11)	(1,618)	(1,120)	(1,118)
Cash dividends - preferred shares (Note 11)	(156)	(156)	(154)
Repurchases of common shares (Note 11)	(273)	(250)	0
Contributions from investment partner	181	485	0
Contributions from noncontrolling interests - net proceeds from KML IPO (Note 3)	0	1,245	0
Contributions from noncontrolling interests - net proceeds from KML preferred share issuances (Note 11)	0	420	0
Contributions from noncontrolling interests - other	19	12	117
Distributions to noncontrolling interests	(78)	(42)	(24)
Other, net	(17)	(9)	(8)
Net Cash Used in Financing Activities	(1,824)	(1,681)	(2,637)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	(146)	22	2
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	3,005	(461)	498
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	326	787	289
Cash, Cash Equivalents, and Restricted Deposits, end of period	3,331	326	787
Cash and Cash Equivalents, beginning of period	264	684	229
Cash and Cash Equivalents, end of period	3,280	264	684
Restricted Cash Equivalents, beginning of period	62	103	60
Restricted Cash Equivalents, end of period	51	62	103
Noncash Investing and Financing Activities
Assets acquired by the assumption or incurrence of liabilities	0	0	43
Net assets contributed to equity investments	0	0	37
Increase in property, plant and equipment from both accruals and contractor retainage	30	14
Decrease in noncontrolling interests for distribution accrual	905	0	0
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,879	1,854	2,050
Cash (refunded) paid during the period for income taxes, net	$ (109)	$ (140)	$ 4

CONSOLIDATED STATEMENT OF STOCK

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Common stock	Preferred stock	Additional paid-in capital	Retained deficit	Accumulated other comprehensive loss	Stockholders’ equity attributable to KMI	Non-controlling interests	Mandatorily Redeemable Preferred Stock [Member]Common stock	Mandatorily Redeemable Preferred Stock [Member]Preferred stock	Mandatorily Redeemable Preferred Stock [Member]Additional paid-in capital
Common stock, shares outstanding (in shares) at Dec. 31, 2015		2,229,000,000
Preferred stock, shares outstanding (in shares) at Dec. 31, 2015			2,000,000
Balance at Dec. 31, 2015	$ 35,403	$ 22	$ 0	$ 41,661	$ (6,103)	$ (461)	$ 35,119	$ 284
Restricted Shares, shares		1,000,000
Restricted shares, value	66			66			66
Net Income (Loss) Attributable to Parent	708				708		708
Net Income (Loss) Attributable to Noncontrolling Interest	(13)							13
Net income	721
Distributions	(24)						0	(24)
Contributions	117						0	117
Preferred stock dividends	(156)				(156)		(156)
Common stock dividends	(1,118)				(1,118)		(1,118)
Other	(7)			12			12	(19)
Other comprehensive loss	(200)					(200)	(200)
Common stock, shares outstanding (in shares) at Dec. 31, 2016		2,230,000,000
Preferred stock, shares outstanding (in shares) at Dec. 31, 2016			2,000,000
Balance at Dec. 31, 2016	34,802	$ 22	$ 0	41,739	(6,669)	(661)	34,431	371
Repurchases of Shares, Shares		(14,000,000)
Repurchases of Shares, Value	(250)			(250)			(250)
Restricted Shares, shares		1,000,000
Restricted shares, value	65			65			65
Net Income (Loss) Attributable to Parent	183				183		183
Net Income (Loss) Attributable to Noncontrolling Interest	(40)							40
Net income	223
KML IPO	1,049			314		51	365	684
KML preferred share issuance	419						0	419
Reorganization of foreign subsidiaries	38			38			38
Distributions	(48)						0	(48)
Contributions	18						0	18
Preferred stock dividends	(156)				(156)		(156)
Common stock dividends	(1,120)				(1,120)		(1,120)
Sale and deconsolidation of interest in Deeprock Development, LLC	(30)						0	(30)
Other	(1)			3	8		11	(12)
Other comprehensive loss	$ 115					69	69	46
Common stock, shares outstanding (in shares) at Dec. 31, 2017		2,217,000,000
Preferred stock, shares outstanding (in shares) at Dec. 31, 2017	1,600,000		2,000,000
Balance at Dec. 31, 2017	$ 35,124	$ 22	$ 0	41,909	(7,754)	(541)	33,636	1,488
Impact of adoption of ASUs	66				175	(109)	66
Common stock, shares outstanding (in shares) at Jan. 01, 2018		2,217,000,000
Preferred stock, shares outstanding (in shares) at Jan. 01, 2018			2,000,000
Balance at Jan. 01, 2018	$ 35,190	$ 22	$ 0	41,909	(7,579)	(650)	33,702	1,488
Common stock, shares outstanding (in shares) at Dec. 31, 2017		2,217,000,000
Preferred stock, shares outstanding (in shares) at Dec. 31, 2017	1,600,000		2,000,000
Balance at Dec. 31, 2017	$ 35,124	$ 22	$ 0	41,909	(7,754)	(541)	33,636	1,488
Repurchases of Shares, Shares		(15,000,000)
Repurchases of Shares, Value	(273)			(273)			(273)
Mandatory conversion of preferred shares, shares									58,000,000	(2,000,000)
Mandatory Conversion of Preferred Shares, Value	0						0		$ 1		$ (1)
Restricted Shares, shares		2,000,000
Restricted shares, value	65			65			65
Net Income (Loss) Attributable to Parent	1,609				1,609		1,609
Net Income (Loss) Attributable to Noncontrolling Interest	(310)							310
Net income	1,919
Distributions	(997)						0	(997)
Contributions	33						0	33
Preferred stock dividends	(128)				(128)		(128)
Common stock dividends	(1,618)				(1,618)		(1,618)
Impact of adoption of ASUs	(109)
Other	2			1			1	1
Other comprehensive loss	$ 338					320	320	18
Common stock, shares outstanding (in shares) at Dec. 31, 2018		2,262,000,000
Preferred stock, shares outstanding (in shares) at Dec. 31, 2018	0		0
Balance at Dec. 31, 2018	$ 34,531	$ 23	$ 0	$ 41,701	$ (7,716)	$ (330)	$ 33,678	$ 853

General (Notes)

General (Notes)	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	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 transload and store liquid commodities including petroleum products, ethanol and chemicals, and bulk products, including petroleum coke, metals and ores. Our common stock trades on the NYSE under the symbol “KMI.”

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of Significant Accounting Policies	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. Adoption of New Accounting Pronouncements On January 1, 2018, we adopted Accounting Standards Updates (ASU) No. 2014-09, “ Revenue from Contracts with Customers ” and a series of related accounting standard updates designed to create improved revenue recognition and disclosure comparability in financial statements. For more information, see “— Revenue Recognition ” below and Note 16. On January 1, 2018, we retroactively adopted ASU No. 2016-18, “ Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force). ” This ASU requires the statements of cash flows to present the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are now included with cash and cash equivalents when reconciling the beginning of period and end of period amounts presented on the statements of cash flows. The retrospective application of this new accounting guidance resulted in an increase of $41 million and a decrease of $43 million in “Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits”, no change and a decrease of $37 million in “Accrued contingencies and other current liabilities” in Cash Flows from Operating Activities, and a decrease of $41 million and an increase of $80 million in “Other, net” in Cash Flows from Investing Activities in our accompanying consolidated statement of cash flows for the years ended December 31, 2017 and 2016, respectively, from what was previously presented in our Annual Report on Form 10-K for the year ended December 31, 2017. 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 and other insurance subsidiaries, and cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions. 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 “Retained deficit” balance. The cumulative effect of the adoption of this ASU was a $66 million , net of income taxes, adjustment to our “Retained deficit” balance as presented in our consolidated statement of stockholders’ equity for the year ended December 31, 2018. This ASU also requires 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 sheet as of December 31, 2018, as EIG has the right under certain conditions to redeem their interests for cash. The December 31, 2017 balance of $485 million is included in “Other long-term liabilities and deferred credits” on our consolidated balance sheet as of December 31, 2017. On January 1, 2018, we adopted ASU No. 2017-07, “ Compensation - Retirement Benefits (Topic 715) .” This ASU requires an employer to disaggregate the service cost component from the other components of net benefit cost, allows only the service cost component of net benefit cost to be eligible for capitalization and establishes how to present the service cost component and the other components of net benefit cost in the income statement. Topic 715 required us to retrospectively reclassify $15 million and $34 million of other components of net benefit credits (excluding the service cost component) from “General and administrative” to “Other, net” in our accompanying consolidated statements of income for the years ended December 31, 2017 and 2016, respectively. We prospectively applied Topic 715 related to net benefit costs eligible for capitalization. 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 “Retained deficit” on our consolidated statement of stockholders’ equity for the year ended December 31, 2018. 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. Restricted deposits were $51 million and $62 million as of December 31, 2018 and 2017 , respectively. Accounts Receivable, net The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of December 31, 2018 and 2017 primarily consist of amounts due from customers net of the allowance for doubtful accounts. Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. The allowance for doubtful accounts was $3 million and $35 million as of December 31, 2018 and 2017 , respectively. 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 1.01% to 23.0% 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 bulk and liquids 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. In those 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. 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 bulk and liquids 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 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 total proved and risk-adjusted probable reserves. 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 total proved and risk-adjusted probable and possible reserves or, if available, comparable market values. 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. Equity Method of Accounting and Excess Investment Cost We account for investments which we do not control, but do have the ability to exercise significant influence using the equity method of accounting. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. With regard to our equity investments in unconsolidated affiliates, in almost all cases, either (i) the price we paid to acquire our share of the net assets of such equity investees or (ii) the revaluation of our share of the net assets of any retained noncontrolling equity investment (from the sale of a portion of our ownership interest in a consolidated subsidiary, thereby losing our controlling financial interest in the subsidiary) differed from the underlying carrying value of such net assets. This differential consists of two pieces. First, an amount related to the difference between the investee’s recognized net assets at book value and at current fair values (representing the appreciated value in plant and other net assets), and secondly, to any premium in excess of fair value (referred to as equity method goodwill) we paid to acquire the investment. We include both amounts within “Investments” on our accompanying consolidated balance sheets. The first differential, representing the excess of the fair market value of our investees’ plant and other net assets over its underlying book value at either the date of acquisition or the date of the loss of control totaled $470 million and $732 million as of December 31, 2018 and 2017 , respectively. Generally, this basis difference relates to our share of the underlying depreciable assets, and, as such, we amortize this portion of our investment cost against our share of investee earnings. As of December 31, 2018 , this excess investment cost is being amortized over a weighted average life of approximately twelve years. The second differential, representing equity method goodwill, totaled $1,967 million for both periods as of December 31, 2018 and 2017 . This differential is not subject to amortization but rather to impairment testing as part of our periodic evaluation of the recoverability of our investment as compared to the fair value of net assets accounted for under the equity method. Our impairment test considers whether the fair value of the equity investment as a whole has declined and whether that decline is other than temporary. Goodwill Goodwill is the cost of an acquisition 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. This test requires us to assign goodwill to an appropriate reporting unit and to determine if the implied fair value of the reporting unit’s goodwill is less than its carrying amount. We evaluate goodwill for impairment on May 31 of each year. For this purpose, prior to the TMPL Sale we had seven 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 ; (vi) Terminals; and (vii) Kinder Morgan Canada. Subsequent to the TMPL Sale, Kinder Morgan Canada is no longer a reporting unit. We also evaluate goodwill for impairment to the extent events or conditions indicate a risk of possible impairment during the interim periods subsequent to our annual impairment test. Generally, the evaluation of goodwill for impairment involves a two-step test, although under certain circumstance an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test. Step 1 involves comparing the estimated fair value of each respective reporting unit to its carrying value, including goodwill. If the estimated fair value exceeds the carrying value, the reporting unit’s goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, step 2 must be performed to determine whether goodwill is impaired and, if so, the amount of the impairment. Step 2 involves 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 is then compared to the actual carrying amount of the goodwill for the reporting unit. To the extent the carrying amount of goodwill exceeds the implied goodwill, the difference is 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, 2018 and 2017 , the gross carrying amounts of these intangible assets was $4,305 million and the accumulated amortization was $1,425 million and $1,206 million , respectively, resulting in net carrying amounts of $2,880 million and $3,099 million , respectively. These intangible assets primarily consisted of customer contracts, relationships and agreements associated with our Natural Gas Pipelines and Terminals 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, 2018 , 2017 and 2016 , the amortization expense on our intangibles totaled $219 million , $220 million and $223 million , respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2019 – 2023) is approximately $213 million , $209 million , $209 million , $207 million , and $203 million , respectively. As of December 31, 2018 , the weighted average amortization period for our intangible assets was approximately fifteen years . Revenue Recognition Revenue from Contracts with Customers Beginning in 2018, we account for revenue from contracts with customers in accordance with Accounting Standards Updates ASU No. 2014-09, “ Revenue from Contracts with Customers ” and a series of related accounting standard updates (Topic 606). The unit of account in Topic 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. Topic 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) control of the goods or services transfers to the customer and the performance obligation is satisfied. 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). Refer to Note 16 for further information. Revenue Recognition Policy prior to January 1, 2018 Prior to the implementation of Topic 606, we recognized revenue as services were rendered or goods were delivered and, if applicable, risk of loss had passed. We recognized natural gas, crude and NGL sales revenue when the commodity was sold to a purchaser at a fixed or determinable price, delivery had occurred and risk of loss had transferred,

Divestitures and Acquisition (N

Divestitures and Acquisition (Notes)	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Divestitures and Acquisition	Divestitures and Acquisition 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 and Kinder Morgan Canada Inc., the Canadian employer of our staff that operate the business, which were indirectly acquired by the Government of Canada through Trans Mountain Corporation (a subsidiary of the Canada Development Investment Corporation) for 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 $596 million within “Loss on impairments and divestitures, net” in our accompanying consolidated statement of income during the year ended December 31, 2018, including an incremental working capital adjustment of $26 million accrued as of December 31, 2018. On January 3, 2019, pursuant to KML’s shareholders’ approval on November 29, 2018, KML distributed to its shareholders as a return of capital, the net proceeds from the TMPL Sale, after capital gains taxes, customary purchase price adjustments and the repayment of debt outstanding under a temporary KML credit facility (see Note 9, “ Debt—Credit Facilities and Restrictive Covenants — KML ”). KML’s public owners of its restricted voting shares, reflected as noncontrolling interests by us, received approximately $0.9 billion ( C$1.2 billion ), and part of our approximate 70% portion of the net proceeds of $1.9 billion ( C$2.5 billion ) (after Canadian tax) were used to immediately 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. To facilitate the return of capital and provide flexibility for KML’s dividends going forward, KML’s shareholders also approved a reduction in the stated capital of its restricted voting shares by C$1.45 billion , which was recorded in the fourth quarter of 2018, along with a “reverse stock split” of KML’s restricted voting shares, and KML’s special voting shares that we own, on a one -for- three basis (three shares consolidating to one share) which occurred on January 4, 2019. May 2017 Sale of Approximate 30% Interest in Canadian Business On May 30, 2017, KML completed an IPO of 102,942,000 restricted voting shares listed on the Toronto Stock Exchange at a price to the public of C$17.00 per restricted voting share for total gross proceeds of approximately C$1,750 million ( US$1,299 million ). The net proceeds from the IPO were used by KML to indirectly acquire from us an approximate 30% interest in a limited partnership that holds our Canadian business while we retained the remaining 70% interest. We used the proceeds from KML’s IPO to pay down debt. Subsequent to the IPO, we retained control of KML and the limited partnership, and as a result, they remain consolidated in our consolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in our consolidated statements of stockholders’ equity and consolidated balance sheets. Earnings attributable to the public ownership of KML are presented in “Net income attributable to noncontrolling interests” in our consolidated statements of income for the periods presented after May 30, 2017. The net proceeds received of $1,245 million are presented as “Contributions from noncontrolling interests - net proceeds from KML IPO” on our consolidated statement of cash flows for the year ended December 31, 2017. Because we retained control of KML subsequent to the IPO, the $314 million adjustment made to “Additional paid-in capital” on our consolidated statement of stockholders equity for the year ended December 31, 2017 represents the difference between our book value prior to the sale and our share of book value in KML’s net assets after the sale. The impact of the IPO resulted in a $166 million deferred income tax adjustment. At the date of the IPO, $765 million was attributed to the KML public shareholders to reflect their proportionate ownership percentage in the net assets of KML acquired from us and is included in “Noncontrolling interests” on our consolidated statement of stockholders equity. The above amounts recorded to “Additional paid-in capital” and “Noncontrolling interests” are net of IPO fees. In addition, the amount recorded to “Noncontrolling interests” at the date of the IPO was reduced by $81 million primarily associated with the allocation of currency translation adjustments from “Accumulated other comprehensive loss” to “Noncontrolling interests.” The portion of the Canadian business operations that we sold to the public on May 30, 2017 represented Canadian assets that were included in our Kinder Morgan Canada, Terminals and Product Pipelines business segments and include (i) the Trans Mountain pipeline system; (ii) the Canadian Cochin pipeline system; (iii) the Puget Sound pipeline system; (iv) the Jet Fuel pipeline system; and (v) terminal facilities located in Western Canada. In January 2018, KML completed the registration of its restricted voting shares pursuant to Section 12(g) of the United States Securities Exchange Act of 1934 (the “Exchange Act”) and subsequently is subject to the reporting requirements of Section 13(a) of the Exchange Act. In conjunction with the IPO, Kinder Morgan Canada Limited Partnership (KMC LP) and Kinder Morgan Canada GP Inc. (KMC GP) were formed to hold our Canadian business. We have determined that KMC LP is a variable interest entity because a simple majority or lower threshold of the limited partnership interests do not possess substantive “kick-out rights” (i.e., the right to remove the general partner or to dissolve (liquidate) the entity without cause) or substantive participation rights. We have also determined KMC GP is the primary beneficiary because it has the power to direct the activities that most significantly impact KMC LP’s performance, the right to receive benefits and the obligation to absorb losses, that could be significant to KMC LP. As a result, KMC GP consolidates KMC LP. KMC GP is a wholly owned subsidiary of KML, which is indirectly controlled by us through our 100% interest in KML’s special voting shares that represent approximately 70% of KML’s total voting shares (comprised of restricted voting shares and special voting shares). Consequently, we consolidate KML and the variable interest entity, KMC LP, in our consolidated financial statements. The following table shows the carrying amount and classification of KMC LP’s assets and liabilities in our consolidated balance sheet (in millions): December 31, 2018 2017 Assets Total current assets 3,204 $ 270 Property, plant and equipment, net 719 2,956 Total goodwill, deferred charges and other assets 8 322 Total assets $ 3,931 $ 3,548 Liabilities Current portion of debt — $ — Total other current liabilities 2,353 236 Long-term debt, excluding current maturities — — Total other long-term liabilities and deferred credits 52 414 Total liabilities $ 2,405 $ 650 We receive distributions from KMC LP through our indirectly owned limited partnership interests in KMC LP, but otherwise the assets of KMC LP cannot be used to settle our obligations other than those of KML. We do not guarantee the debt, commercial paper or other similar commitments of KMC LP or any of its subsidiaries, and the obligations of KMC LP may only be settled using the assets of KMC LP. KMC LP does not guarantee the debt or other similar commitments of KMI. Sale of Noncontrolling Interest in ELC Effective February 28, 2017, we sold a 49% partnership interest in ELC to investment funds managed by EIG. We continue to own a 51% controlling interest in and operate ELC. Under the terms of ELC’s limited liability company agreement, we are responsible for placing in service and operating certain supply pipelines and terminal facilities that support the operations of ELC and that are wholly owned by us. In certain limited circumstances that are not expected to occur, EIG has the right to relinquish its interest in ELC and redeem its capital account. The sale proceeds of $386 million , and subsequent EIG contributions, have been reflected as of December 31, 2018 within “Redeemable Noncontrolling Interest” and as of December 31, 2017, as a deferred credit within “Other long-term liabilities and deferred credits” on our consolidated balance sheets. Once these contingencies expire, EIG’s capital account will be reflected in Noncontrolling interests on our consolidated balance sheet. Terminals Asset Sale In October 2016, we entered into a definitive agreement to sell several bulk terminals to an affiliate of Watco Companies, LLC for approximately $100 million . The terminals are predominantly located along the inland river system and handle mostly coal and steel products, and are included within our Terminals business segment. The sale of eight of the locations closed in the fourth quarter of 2016, for which we received $37 million of the total consideration, and the balance of this transaction, which included an additional eleven locations, closed in the second quarter of 2017 as certain conditions were satisfied. As a result of this transaction, we recognized a pre-tax loss of $81 million , including a $7 million reduction of goodwill, which is included within “Loss on impairments and divestitures, net” on our accompanying consolidated statement of income for the year ended December 31, 2016. Sale of Equity Interest in SNG On September 1, 2016, we completed the sale of a 50% interest in our SNG natural gas pipeline system to The Southern Company (Southern Company), receiving proceeds of $1.4 billion , and the formation of a joint venture, which includes our remaining 50% interest in SNG. We used the proceeds from the sale to reduce outstanding debt. We recognized a pre-tax loss of $84 million on the sale of our interest in SNG which is included within “Loss on impairments and divestitures, net” on the accompanying consolidated statement of income for the year ended December 31, 2016. As a result of this transaction, we no longer hold a controlling interest in SNG or Bear Creek Storage Company, LLC (Bear Creek) ( 50% of which is owned by SNG) and, as such, we now account for our remaining equity interests in SNG and Bear Creek as equity investments. Acquisition of BP Products North America Inc. (BP) Terminal Assets On February 1, 2016, we completed the acquisition of 15 products terminals and associated infrastructure from BP for $349 million , including a transaction deposit paid in 2015 and working capital adjustments paid in 2016. The purchase price consisted of $396 million of property, plant and equipment, $2 million of current assets, and assumed liabilities of $49 million . In conjunction with this transaction, we and BP formed a joint venture with an equity ownership interest of 75% and 25% , respectively. Subsequent to the acquisition, we contributed 14 of the acquired terminals to the joint venture, which we operate, and the remaining terminal is solely owned by us. BP acquired its 25% interest in the joint venture for $84 million , which we reported as “Contributions from noncontrolling interests - other” within our accompanying consolidated statement of cash flows for the year ended December 31, 2016. These terminals are included in our Terminals and Products Pipelines business segments.

Impairments (Notes)

Impairments (Notes)	12 Months Ended
	Dec. 31, 2018
Impairments [Abstract]
Impairment of Goodwill, Long-lived assets and equity investments [Text Block]	Impairments and Losses (Gains) on Divestitures During the years ended December 31, 2018 , 2017 , and 2016 , we recorded impairments of certain equity investments, long-lived assets, and intangible assets, and net gains and losses on divestitures totaling $437 million , $172 million , and $1,013 million , respectively. During 2016, and to a lesser degree in 2017 and 2018, a sustained lower commodity price environment, and negative outlook for certain long-term transportation contracts, led us to cancel certain construction projects, divest of certain assets, write-down certain assets and investments to fair value. These impairments were driven by market conditions that existed at the time and required management to estimate the fair value of these assets. The estimates of fair value are based on Level 3 valuation estimates using industry standard income approach valuation methodologies which include assumptions primarily involving management’s significant judgments and estimates with respect to general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. We typically use discounted cash flow analyses to determine the fair value of our assets. We may probability weight various forecasted cash flow scenarios utilized in the analysis as we consider the possible outcomes. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular asset. In January 2019, Pacific Gas and Electric (PG&E) filed for Chapter 11 bankruptcy protection. Our exposure to PG&E is limited to our $750 million equity investment in Ruby and an approximate $55 million note receivable from Ruby, where PG&E is Ruby’s largest customer. PG&E represents approximately $93 million of annual revenues on Ruby, and our partner’s preferred equity interest in Ruby is senior to our interest. Despite the bankruptcy filing, Ruby continues to perform under its existing service contracts with PG&E and PG&E has provided credit support on its trade payables to Ruby through a prepayment arrangement. While the ultimate outcome of the bankruptcy proceedings remains uncertain, there is the potential for Ruby’s existing contracts with PG&E to be canceled in the bankruptcy process. Any cancellation of these contracts could negatively impact Ruby’s future revenues and require us to evaluate our investment in Ruby for an other than temporary impairment. This could result in a material impairment of our investment in Ruby at the time such events become known. We may identify additional triggering events requiring future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill. Because certain assets and investments have been written down to fair value in the last few years, any deterioration in fair value relative to our carrying value increases the likelihood of 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 be not fully recoverable. We recognized the following non-cash pre-tax impairment charges and losses (gains) on divestitures of assets (in millions): Year Ended December 31, 2018 2017 2016 Natural Gas Pipelines Impairments of long-lived assets(a) $ 600 $ 30 $ 106 (Gains) losses on divestitures of long-lived assets(b) (6 ) — 94 Impairment of equity investments(c) 270 150 606 Impairment at equity investee(d) — 10 7 Products Pipelines Impairments of long-lived assets(e) 36 — 66 Losses on divestitures of long-lived assets — — 10 Gain on divestiture of equity investment — — (12 ) Terminals Impairments of long-lived assets(f) 59 3 19 (Gains) losses on divestitures of long-lived assets(g) (6 ) (18 ) 80 Losses on impairments and divestitures of equity investments, net — — 16 CO 2 Impairments of long-lived assets(h) 79 (1 ) 20 Gain on divestitures of long-lived assets — — (1 ) Impairment at equity investee — (4 ) 9 Kinder Morgan Canada Gain on divestiture of long-lived assets(i) (595 ) — — Other losses (gains) on divestitures of long-lived assets — 2 (7 ) Pre-tax losses on impairments and divestitures, net $ 437 $ 172 $ 1,013 _______ (a) 2018 amount represents the non-cash impairment associated with certain gathering and processing assets in Oklahoma. 2017 amount represents the impairment of our Colden storage facility, of which $3 million is included in “Costs of sales” on our accompanying consolidated statement of income. 2016 amount represents the project write-off of our portion of the Northeast Energy Direct Market project. (b) 2016 amount primarily relates to our sale of a 50% interest in SNG. (c) 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. 2017 amount represents the non-cash impairment of our investment in FEP. 2016 amount includes a $350 million non-cash impairment of our investment in MEP and a $250 million non-cash impairment of our investment in Ruby. (d) 2017 and 2016 amounts represent losses on impairments recorded by equity investees and are included in “Earnings from equity investments” on our accompanying consolidated statements of income. (e) 2018 amount represents a project write-off associated with the Utica Marcellus Texas pipeline. 2016 amount represents project write-offs associated with the canceled Palmetto project. (f) 2018 amount primarily relates to non-cash impairments of certain Northeast terminal assets. (g) 2017 amount includes a $23 million gain related to the sale of a 40% membership interest in the Deeprock Development joint venture. 2016 amount primarily relates to the sale of 20 bulk terminals that handle mostly coal and steel products, predominately located along the inland river system. (h) 2018 amount represents impairments of oil and gas properties. (i) 2018 amount represents the gain on the TMPL Sale. 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. These reduced estimates triggered an impairment analysis 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.

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of “Income Before Income Taxes” are as follows (in millions): Year Ended December 31, 2018 2017 2016 U.S. $ 1,739 $ 1,976 $ 1,466 Foreign 767 185 172 Total Income Before Income Taxes $ 2,506 $ 2,161 $ 1,638 Components of the income tax provision applicable for federal, foreign and state taxes are as follows (in millions): Year Ended December 31, 2018 2017 2016 Current tax expense (benefit) Federal $ (22 ) $ (137 ) $ (148 ) State (45 ) (16 ) (28 ) Foreign 249 18 6 Total 182 (135 ) (170 ) Deferred tax expense (benefit) Federal 425 2,022 998 State 55 4 51 Foreign (75 ) 47 38 Total 405 2,073 1,087 Total tax provision $ 587 $ 1,938 $ 917 We are subject to taxation in Canada and Mexico. In Canada we recognized income tax expense of $168 million , $58 million and $38 million at December 31, 2018 , 2017 , and 2016 , respectively. In Mexico we recognized income tax expense of $6 million , $7 million and $6 million at December 31, 2018 , 2017 , and 2016 , respectively. The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows (in millions, except percentages): Year Ended December 31, 2018 2017 2016 Federal income tax $ 526 21.0 % $ 756 35.0 % $ 573 35.0 % Increase (decrease) as a result of: State deferred tax rate change (7 ) (0.3 )% 10 0.5 % 11 0.7 % Taxes on foreign earnings, net of federal benefit 131 5.2 % 42 1.9 % 28 1.7 % Net effects of noncontrolling interests (65 ) (2.6 )% (14 ) (0.7 )% (4 ) (0.3 )% State income tax, net of federal benefit 46 1.8 % 38 1.8 % 26 1.6 % Dividend received deduction (31 ) (1.2 )% (56 ) (2.6 )% (48 ) (2.9 )% Adjustments to uncertain tax positions (47 ) (1.9 )% (12 ) (0.6 )% (23 ) (1.4 )% Valuation allowance on investment and tax credits 14 0.5 % 13 0.6 % 34 2.1 % Impact of the 2017 Tax Reform — — % 1,240 57.4 % — — % Nondeductible goodwill 58 2.3 % — — % 301 18.5 % General business credit (64 ) (2.6 )% (95 ) (4.4 )% — — % Other 26 1.2 % 16 0.8 % 19 1.1 % Total $ 587 23.4 % $ 1,938 89.7 % $ 917 56.1 % Deferred tax assets and liabilities result from the following (in millions): December 31, 2018 2017 Deferred tax assets Employee benefits $ 238 $ 251 Accrued expenses 76 73 Net operating loss, capital loss and tax credit carryforwards 1,526 1,113 Derivative instruments and interest rate and currency swaps 9 12 Debt fair value adjustment 33 37 Investments 177 968 Other — 6 Valuation allowances (178 ) (171 ) Total deferred tax assets 1,881 2,289 Deferred tax liabilities Property, plant and equipment 270 225 Other 45 20 Total deferred tax liabilities 315 245 Net deferred tax assets $ 1,566 $ 2,044 Deferred Tax Assets and Valuation Allowances: The step-up in tax basis from the merger transactions that occurred in November 2014 resulted in a deferred tax asset, primarily related to our investment in KMP. As book earnings from our investment in KMP are projected to exceed taxable income (primarily as a result of the partnership’s tax depreciation in excess of book depreciation), the deferred tax asset related to our investment in KMP is expected to be fully realized. We increased our valuation allowances in 2018 by $7 million , primarily due to a $17 million increase for capital loss carryover as a result of the TMPL Sale, a $6 million decrease for foreign operating losses and a $4 million utilization of foreign tax credits. We have deferred tax assets of $1,249 million related to net operating loss carryovers, $260 million related to general business, alternative minimum, and foreign tax credits, $17 million related to capital losses, and $140 million of valuation allowances related to these deferred tax assets at December 31, 2018. As of December 31, 2017, we had deferred tax assets of $935 million related to net operating loss carryovers, $178 million related to general business, alternative minimum and foreign tax credits and $133 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 2022. Our alternative minimum tax credit carryforwards decreased by $8 million in 2018 as a result of a federal audit settlement. In 2017, our decision to elect to forgo bonus depreciation on property placed in service in that year allowed us to utilize $137 million of minimum tax credits. Section 168(k)(4) of the Internal Revenue Code allows for corporate taxpayers with minimum tax credit carryforwards to forgo bonus depreciation and accelerate their use of the credits to reduce tax liability in that same tax year if the amount of the allowable credit exceeds the taxpayer’s tax liability. We received an income tax refund of $145 million in 2018 related to the 2017 credit utilization and 2018 audit settlement. Expiration Periods for Deferred Tax Assets: As of December 31, 2018, we have U.S. federal net operating loss carryforwards of $1.4 billion that will be carried forward indefinitely and $3.4 billion that will expire from 2019 - 2037; state losses of $3.7 billion which will expire from 2019 - 2038; and foreign losses of $112 million which will expire from 2029 - 2038. We also have $241 million of general business credits which will expire from 2019 - 2028; a capital loss carryover of $17 million which will expire in 2023; and approximately $17 million of foreign tax credits, which will expire from 2020 - 2023. Use of a portion of our U.S. federal carryforwards is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation rules of Internal Revenue Service regulations. If certain substantial changes in our ownership occur, there would be an annual limitation on the amount of carryforwards that could be utilized. Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution. A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows (in millions): Year Ended December 31, 2018 2017 2016 Balance at beginning of period $ 97 $ 122 $ 148 Additions based on current year tax positions 3 3 3 Additions based on prior year tax positions 7 — 7 Reductions based on prior year tax positions — — (1 ) Reductions based on settlements with taxing authority (73 ) (22 ) (26 ) Reductions due to lapse in statute of limitations — (2 ) (9 ) Impact of the 2017 Tax Reform — (4 ) — Balance at end of period $ 34 $ 97 $ 122 We recognize interest and/or penalties related to income tax matters in income tax expense. We recognized tax benefits of $15 million , $9 million and an expense of $2 million at December 31, 2018, 2017 and 2016 , respectively. As of December 31, 2018 , 2017 and 2016 , we had $2 million , $19 million and $28 million , respectively, of accrued interest. We had less than $1 million of accrued penalties as of December 31, 2018 and no accrued penalties as of December 31, 2017. All of the $34 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 $21 million during the next year to approximately $13 million , primarily due to settlements with taxing authorities, partially 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 2015-2017 in the U.S., 2005-2017 in various states and 2007-2017 in various foreign jurisdictions. Impact of 2017 Tax Reform On December 22, 2017, the U.S. enacted the 2017 Tax Reform. Among the many provisions included in the 2017 Tax Reform is a provision to reduce the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018. As of December 31, 2017, we had deferred tax assets related to our net operating loss carryforwards and tax credits, in addition to tax basis in excess of accounting basis primarily related to our investment in KMP. Prior to the 2017 Tax Reform, the value of these deferred tax assets was recorded at the previous income tax rate of 35% , which represented their expected future benefit to us. As a result of the 2017 Tax Reform, the future benefit of these deferred tax assets was re-measured at the new income tax rate of 21% and we recorded an approximate $1,240 million provisional non-cash adjustment for the year ended December 31, 2017. We determined the effects of the rate change using our best estimate of temporary book-to-tax differences. Upon final analysis and remeasurement of our deferred tax balances, the December 31, 2017 adjustment recorded accurately reflected the change in corporate income tax rates and has not been materially adjusted in subsequent periods. In addition, the 2017 Tax Reform required a mandatory deemed repatriation of post-1986 undistributed foreign earnings and profits. As of December 31, 2017, we recorded a provisional amount for this 2017 Tax Reform provision and as of December 31, 2018, completed our analysis on this provision. The 2017 Tax Reform transition tax was $2 million . The income tax rate change in the 2017 Tax Reform had an impact not only on our corporate income taxes but also resulted in us recording an approximate $144 million after-tax ( $219 million pre-tax) provisional non-cash adjustment, including our share of equity investee provisional adjustments, related to our FERC regulated business for the year ended December 31, 2017. As a result of the completion of our assessment of the 2017 Tax Reform’s effect on our FERC regulated business, we decreased this non-cash provisional adjustment by approximately $27 million after-tax ( $36 million pre-tax) during the year ended December 31, 2018. The 2017 Tax Reform requires a U.S. corporation to record taxes on global intangible low-tax income (GILTI) and elect an accounting policy to either recognize GILTI as a current period expense when incurred or to record deferred taxes for the temporary basis differences expected to reverse in the future as GILTI. Though we did not generate any GILTI during 2018, we have elected to recognize the GILTI tax as a period cost in the future, as applicable.

Property, Plant and Equipment (

Property, Plant and Equipment (Notes)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure [Text Block]	Property, Plant and Equipment, net Classes and Depreciation As of December 31, 2018 and 2017 , our property, plant and equipment, net consisted of the following (in millions): December 31, 2018 2017 Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 19,727 $ 20,157 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 24,392 24,152 Other(a) 5,447 5,570 Accumulated depreciation, depletion and amortization (15,359 ) (14,175 ) 34,207 35,704 Land and land rights-of-way 1,378 1,456 Construction work in process 2,312 2,995 Property, plant and equipment, net $ 37,897 $ 40,155 _______ (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, 2018 and 2017 , property, plant and equipment, net included $12,349 million and $14,055 million , respectively, of assets which were regulated by either the FERC or the NEB. Depreciation, depletion, and amortization expense charged against property, plant and equipment was $2,057 million , $2,022 million , and $1,970 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. Asset Retirement Obligations As of December 31, 2018 and 2017 , we recognized asset retirement obligations in the aggregate amount of $213 million and $208 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, 2018
Investments [Abstract]
Equity Method Investments and Joint Ventures Disclosure [Text Block]	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. As of December 31, 2018 and 2017 , our investments consisted of the following (in millions): December 31, 2018 2017 Citrus Corporation $ 1,708 $ 1,698 SNG 1,536 1,495 Ruby 750 774 NGPL Holdings LLC 733 687 Gulf LNG Holdings Group, LLC 361 461 Plantation Pipe Line Company 344 331 Utopia Holding LLC 333 276 EagleHawk 299 314 Gulf Coast Express Pipeline LLC 240 — MEP 235 253 Red Cedar Gathering Company 191 187 Watco Companies, LLC 185 182 Double Eagle Pipeline LLC 140 149 Liberty Pipeline Group LLC 66 71 Bear Creek Storage 65 63 Sierrita Gas Pipeline LLC 55 55 Permian Highway Pipeline 45 — FEP 44 112 All others 151 190 Total investments $ 7,481 $ 7,298 As shown in the investment balance table above and the earnings from equity investments table below, our significant equity investments, as of December 31, 2018 consisted of the following: • Citrus Corporation—We own a 50% interest in Citrus Corporation, the sole owner of Florida Gas Transmission Company, L.L.C. (Florida Gas). Florida Gas transports natural gas to cogeneration facilities, electric utilities, independent power producers, municipal generators, and local distribution companies through a 5,300 -mile natural gas pipeline. Energy Transfer Partners L.P. operates Florida Gas and owns the remaining 50% interest in Citrus; • SNG—We operate SNG and own a 50% interest in SNG; and Evergreen Enterprise Holdings, LLC, a subsidiary of Southern Company, owns the remaining 50% interest; • Ruby—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; • NGPL Holdings LLC— We operate NGPL Holdings LLC and own a 50% interest in NGPL Holdings LLC, the indirect owner of NGPL and certain affiliates, collectively referred to in this report as NGPL, a major interstate natural gas pipeline and storage system. The remaining 50% interest is owned by Brookfield; • Gulf LNG Holdings Group, LLC—We operate Gulf LNG Holdings Group, LLC and own a 50% interest in Gulf LNG Holdings Group, LLC, the owner of a LNG receiving, storage and regasification terminal near Pascagoula, Mississippi, as well as pipeline facilities to deliver vaporized natural gas into third party pipelines for delivery into various markets around the country. The remaining 50% interest is owned by a variety of investment entities, including subsidiaries of The Blackstone Group, LP; Warburg Pincus, LLC; Kelso and Company; and Chatham Asset Management, LLC, which is directed by Chatham Asset GP, LLC; • Plantation—We operate Plantation and own a 51.17% interest in Plantation, the sole owner of the Plantation refined petroleum products pipeline system. A subsidiary of Exxon Mobil Corporation owns the remaining interest. Each investor has an equal number of directors on Plantation’s board of directors, and board approval is required for certain corporate actions that are considered substantive participating rights; therefore, we do not control Plantation, and account for the investment under the equity method; • Utopia Holding L.L.C. — We operate Utopia Holding L.L.C. and own a 50% interest in Utopia Holding L.L.C. Riverstone Investment Group LLC owns the remaining 50% interest; • BHP Billiton Petroleum (Eagle Ford Gathering) LLC, (EagleHawk)—We own a 25% interest in EagleHawk, the sole owner of natural gas and condensate gathering systems serving the producers of the Eagle Ford shale formation. A subsidiary of BHP Billiton Petroleum (Tx Gathering), LLC operates EagleHawk and owns the remaining 75% ownership interest; • Gulf Coast Express Pipeline LLC — We operate Gulf Coast Express Pipeline LLC and own 35% interest of Gulf Coast Express Pipeline LLC indirectly through Kinder Morgan Texas Pipeline LLC, our 100% subsidiary. DCP GCX Pipeline LLC, an indirect subsidiary of DCP Midstream, owns 25% interest; Targa GCX Pipeline LLC, an indirect subsidiary of Targa Resources Corp., owns 25% interest and Altus Midstream Company, an indirect subsidiary of Apache Corporation, owns 15% interest; • MEP—We operate MEP and own a 50% interest in MEP, the sole owner of the MEP natural gas pipeline system. The remaining 50% ownership interest is owned by subsidiaries of Energy Transfer Partners L.P.; • Red Cedar Gathering Company—We own a 49% interest in Red Cedar Gathering Company, the sole owner of the Red Cedar natural gas gathering, compression and treating system. The Southern Ute Indian Tribe owns the remaining 51% interest and serves as operator of Red Cedar; • Watco Companies, LLC—We hold a preferred and common equity investment in Watco Companies, LLC, the largest privately held short line railroad company in the U.S. We own 100,000 Class A and 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 3.25% and 3.00% per quarter, respectively, and participate partially in additional profit distributions at a rate equal to 0.4% . Neither class holds any voting powers, but do provide us certain approval rights, including the right to appoint one of the members to Watco’s board of managers. In addition to the senior interests, we also hold approximately 13,000 common equity units, which represents a 3.2% common ownership; • Double Eagle Pipeline LLC - We own a 50% equity interest in Double Eagle Pipeline LLC. The remaining 50% interest is owned by Magellan Midstream Partners; • Liberty Pipeline Group, LLC (Liberty) —We own a 50% interest in Liberty. ETC NGL Transport, LLC, a subsidiary of Energy Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of Liberty; • Bear Creek Storage—We own a combined 75% interest in Bear Creek through: our wholly owned subsidiary’s (TGP) 50% interest and an additional 25% indirect interest through our 50% equity interest in SNG, which owns the remaining 50% interest; • Sierrita Gas Pipeline LLC — We operate Sierrita Gas Pipeline LLC and own a 35% interest in Sierrita Gas Pipeline LLC. MGI Enterprises U.S. LLC, a subsidiary of PEMEX, owns 35% ; and MIT Pipeline Investment Americas, Inc., a subsidiary of Mitsui & Co., Ltd, owns 30% ; • Permian Highway Pipeline — We operate Permian Highway Pipeline and own a 50% interest of Permian Highway Pipeline indirectly through KMTP, our wholly owned subsidiary. BCP PHP, LLC (BCP), a portfolio company of Blackstone Energy Partners, owns the remaining 50% interest. An affiliate of an anchor shipper exercised its option in January 2019 to acquire a 20% equity interest in the project, bringing KMTP’s and BCP’s ownership interest to 40% each. Altus Midstream Company (Altus Midstream) (a gas gathering, processing and transportation company formed by shipper Apache Corporation) has an option to acquire an equity interest in the project from the initial partners by September 2019. If Altus Midstream exercises its option, KMTP, BCP and Altus Midstream will each hold a 26.67% ownership interest in the project. KMTP will build and operate the pipeline; • FEP —We own a 50% interest in FEP, the sole owner of the Fayetteville Express natural gas pipeline system. Energy Transfer Partners, L.P. owns the remaining 50% interest and serves as operator of FEP; • Cortez Pipeline Company—We operate the Cortez CO 2 pipeline system, and own a 52.98% interest in the Cortez Pipeline Company, the sole owner of the Cortez CO 2 pipeline system. Mobil Cortez Pipeline Inc. owns 33.25% ; and Cortez Vickers Pipeline Company owns the remaining 13.77% . Our earnings from equity investments were as follows (in millions): Year Ended December 31, 2018 2017 2016 Gulf LNG Holdings Group, LLC(a) $ 209 $ 47 $ 48 Citrus Corporation 169 108 102 SNG 141 77 58 NGPL Holdings LLC 66 10 12 FEP 55 53 51 Plantation Pipe Line Company 55 46 37 Cortez Pipeline Company(b) 36 44 24 MEP 31 38 40 Ruby 26 44 15 Watco Companies, LLC 21 19 25 Red Cedar Gathering Company(c) 18 14 24 Utopia Holding LLC 14 — — Double Eagle Pipeline LLC 10 7 5 Bear Creek Storage 9 8 2 EagleHawk 7 24 10 Liberty Pipeline Group LLC 7 9 11 Sierrita Gas Pipeline LLC 7 7 7 Gulf Coast Express LLC 2 — — All others 4 23 26 Total earnings from equity investments $ 887 $ 578 $ 497 Amortization of excess costs (95 ) (61 ) (59 ) _______ (a) 2018 amount includes our share of earnings recognized due to a ruling by an arbitration panel affecting a customer contract. (b) 2017 and 2016 amounts include $(4) million and $9 million , respectively, representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company. (c) 2017 amount includes non-cash impairment charges of $10 million (pre-tax) related to our investment. Summarized combined financial information for our significant equity investments (listed or described above) is reported below (in millions; amounts represent 100% of investee financial information): Year Ended December 31, Income Statement 2018 2017 2016 Revenues $ 5,129 $ 4,703 $ 4,084 Costs and expenses 3,371 3,398 3,056 Net income $ 1,758 $ 1,305 $ 1,028 December 31, Balance Sheet 2018 2017 Current assets $ 1,496 $ 956 Non-current assets 23,396 22,344 Current liabilities 2,715 1,241 Non-current liabilities 9,555 10,605 Partners’/owners’ equity 12,622 11,454

Goodwill (Notes)

Goodwill (Notes)	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill Disclosure [Text Block]	Goodwill Changes in the amounts of our goodwill for each of the years ended December 31, 2018 and 2017 are summarized by reporting unit as follows (in millions): Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated CO 2 Products Pipelines Products Pipelines Terminals Terminals Kinder Morgan Canada Total Historical Goodwill $ 15,892 $ 5,812 $ 1,528 $ 2,125 $ 221 $ 1,575 $ 562 $ 27,715 Accumulated impairment losses (1,643 ) (1,597 ) — (1,197 ) (70 ) (679 ) (377 ) (5,563 ) December 31, 2016 14,249 4,215 1,528 928 151 896 185 22,152 Currency translation — — — — — — 13 13 Divestitures(a) — — — — — (3 ) — (3 ) December 31, 2017 14,249 4,215 1,528 928 151 893 198 22,162 Currency translation — — — — — — (8 ) (8 ) Divestitures(b) — — — — — — (190 ) (190 ) Other — — — — — 1 — 1 December 31, 2018 $ 14,249 $ 4,215 $ 1,528 $ 928 $ 151 $ 894 $ — $ 21,965 _______ (a) 2017 includes $3 million related to certain terminal divestitures. (b) 2018 includes $190 million related to the TMPL Sale. Refer to Note 2 “ Summary of Significant Accounting Policies—Goodwill ” for a description of our accounting for goodwill. We determine the fair value of each reporting unit as of May 31 of each year based primarily on a market approach utilizing enterprise value to estimated earning before interest, taxes, depreciation and amortization (EBITDA) multiples of comparable companies. The value of each reporting unit is determined on a stand-alone basis from the perspective of a market participant representing the price estimated to be received in a sale of the reporting unit in an orderly transaction between market participants at the measurement date. For our Natural Gas Pipelines Non-Regulated reporting unit, our May 31, 2018 annual test included a discounted cash flow analysis (income approach) to evaluate the fair value of this reporting unit to provide additional indication of fair value based on the present value of cash flows this reporting unit is expected to generate in the future. We weighted the market and income approaches for this reporting unit to arrive at an estimated fair value of this reporting unit giving more weighting on the income approach and less on the market approach as we believed the value indicated using the income approach is more representative of the value that could be received from a market participant. As of May 31, 2018, each of our reporting units indicated a fair value in excess of their respective carrying values (by at least 10%) and step 2 was not required. The results of our Step 1 analysis did not indicate an impairment of goodwill and we did not identify any triggers for further impairment analysis during the remainder of the year. A continued period of volatile commodity prices could result in deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital, and our cash flow estimates. A significant unfavorable change to any one or combination of these factors would result in a change to the reporting unit fair values discussed above potentially resulting in future impairments of long-lived assets, equity method investments, and/or goodwill. Such non-cash impairments could have a significant effect on our results of operations.

Debt (Notes)

Debt (Notes)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	Debt We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statements of income. The following table provides detail on the principal amount of our outstanding debt balances. The table amounts exclude all debt fair value adjustments, including debt discounts, premiums and issuance costs (in millions): December 31, 2018 2017 Credit facility and commercial paper borrowings(a) $ 433 $ 365 Corporate senior notes(b) 6.00%, due January 2018 — 750 7.00%, due February 2018 — 82 5.95%, due February 2018 — 975 7.25%, due June 2018 — 477 9.00%, due February 2019 500 500 2.65%, due February 2019 800 800 3.05%, due December 2019 1,500 1,500 6.85%, due February 2020 700 700 6.50%, due April 2020 535 535 5.30%, due September 2020 600 600 6.50%, due September 2020 349 349 5.00%, due February 2021 750 750 3.50%, due March 2021 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(c) 860 900 3.95%, due September 2022 1,000 1,000 3.15%, due January 2023 1,000 1,000 Floating rate, due January 2023 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(c) 573 600 6.67%, due November 2027 7 7 4.30%, due March 2028 1,250 — 7.25%, due March 2028 32 32 6.95%, due June 2028 31 31 8.05%, due October 2030 234 234 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 December 31, 2018 2017 5.625%, due September 2041 375 375 5.00%, due August 2042 625 625 4.70%, due November 2042 475 475 5.00%, due March 2043 700 700 5.50%, due March 2044 750 750 5.40%, due September 2044 550 550 5.55%, due June 2045 1,750 1,750 5.05%, due February 2046 800 800 5.20%, due March 2048 750 — 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 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 December 2035 409 421 Trust I Preferred Securities, 4.75%, due March 2028(d) 221 221 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(e) 100 100 Other miscellaneous debt(f) 250 278 Total debt – KMI and Subsidiaries 36,593 36,916 Less: Current portion of debt(g) 3,388 2,828 Total long-term debt – KMI and Subsidiaries(h) $ 33,205 $ 34,088 _______ (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) Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2018 exchange rate of 1.1467 U.S. dollars per Euro and at the December 31, 2017 exchange rate of 1.2005 U.S. dollars per Euro. As of December 31, 2018 and 2017 , the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in increases to our debt balance of $46 million and $86 million , respectively, related to the 1.50% series and increases of $30 million and $57 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 consolidated balance sheets. At the time of issuance, we entered into cross-currency swap agreements 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 ”). (d) Capital Trust I (Trust I), is a 100% -owned business trust that as of December 31, 2018 , 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% , carry a liquidation value of $50 per security plus accrued and unpaid distributions. The Trust I Preferred Securities outstanding as of December 31, 2018 are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; and (ii) $25.18 in cash without interest. We have the right to redeem these Trust I Preferred Securities at any time. (e) As of December 31, 2018 and 2017, KMGP had outstanding, 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057. Since August 18, 2012, dividends on the preferred stock accumulate at a floating rate of the 3-month LIBOR plus 3.8975% and are payable quarterly in arrears, when and if declared by KMGP’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2012. The preferred stock has approval rights over a commencement of or filing of voluntary bankruptcy by KMP or its SFPP or Calnev subsidiaries. (f) Includes capital lease obligations with monthly installments. The lease terms expire between 2024 and 2061. (g) Amounts include KMI and KML outstanding credit facility borrowings, commercial paper borrowings and other debt maturing within 12 months. See “—Current Portion of Debt” below. (h) Excludes our “Debt fair value adjustments” which, as of December 31, 2018 and 2017 , increased our combined debt balances by $731 million and $927 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, 2018 2017 $500 million, 364-day credit facility due November 15, 2019(a) $ — $ — $4 billion credit facility due November 16, 2023(a) — — $5 billion, five-year credit facility due November 26, 2019, -% and 2.99%, respectively(a)(b) — 125 Commercial paper notes, 3.10% and 2.02%, respectively(b) 433 240 KML 2018 Credit Facility(c) — — Current portion of senior notes 6.00%, due January 2018 — 750 7.00%, due February 2018 — 82 5.95%, due February 2018 — 975 7.25%, due June 2018 — 477 9.00%, due February 2019 500 — 2.65%, due February 2019 800 — 3.05%, due December 2019 1,500 — Trust I Preferred Securities, 4.75%, due March 2028 111 111 Current portion - Other debt 44 68 Total current portion of debt $ 3,388 $ 2,828 _______ (a) On November 16, 2018, we replaced our $5 billion , five-year credit facility with two new credit facilities discussed further in “—Credit Facilities and Restrictive Covenants” following. (b) Interest rates are weighted average rates at December 31, 2018 and 2017, respectively. (c) Borrowings under the KML 2018 Credit Facility are denominated in C$ and are converted to U.S. dollars. The exchange rate was 0.7330 U.S. dollars per C$ at December 31, 2018 and 0.7971 U.S. dollars per C$ at December 31, 2017. See “—Credit Facilities” below. 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. Also, see Note 20. Subsequent Event—Debt Repayments Using part of our portion of proceeds from the TMPL Sale that KML distributed to us in January 2019, we immediately repaid our outstanding balance of commercial paper borrowings, and then in February 2019, repaid $500 million of maturing 9.00% senior notes and $800 million of maturing 2.65% senior notes which were included in “Current portion of debt” on the accompanying consolidated balance sheet as of December 31, 2018. Credit Facilities and Restrictive Covenants KMI On November 16, 2018, we replaced our five-year, $5 billion revolving credit facility with (i) a new five-year, $ 4 billion revolving credit facility (Five-year Credit Facility); and (ii) a new 364-day, $500 million revolving credit facility (364-day Credit Facility) with a syndicate of lenders, together, “KMI’s New Credit Facilities.” We also continue to maintain a $4 billion commercial paper program through the private placement of short-term notes. The notes mature up to 270 days from the date of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less a discount representing an interest factor or if interest bearing, at par. Borrowings under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program reduce the borrowings allowed under our Five-year Credit Facility. Depending on the type of loan request, our credit facility borrowings under either of our credit facilities 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% for the Five-year Credit Facility and 0.090% to 0.275% for the 364-day Credit Facility based upon our debt credit rating. KMI’s New Credit Facilities contain financial and various other covenants that apply to the Company and its subsidiaries and are common in such agreements, including a maximum ratio of Consolidated Net Indebtedness to Consolidated EBITDA (each as defined in the Five-Year Credit Facility and 364-day Credit Facility, as applicable) of 5.50 to 1.00 , for any four-fiscal-quarter period. Other negative covenants include restrictions on the Company’s and certain of its 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 the Company or any guarantor. KMI’s New Credit Facilities also restrict the Company’s ability to make certain restricted payments if an event of default (as defined in the Five-Year Credit Facility and the 364-Day Credit Facility) has occurred and is continuing or would occur and be continuing. As of December 31, 2018 , we had no borrowings outstanding under our Five-year Credit Facility or our 364-day Credit Facility, $433 million outstanding under our commercial paper program and $99 million in letters of credit. Our availability under these facilities as of December 31, 2018 was $3,968 million . As of December 31, 2018 , we were in compliance with all required covenants. KML Upon the closing of the TMPL Sale on August 31, 2018, KML’s prior credit facility was replaced with a new 4-year, C$500 million unsecured revolving credit facility for working capital purposes (“KML 2018 Credit Facility”) under a credit agreement with the Royal Bank of Canada (the “KML Credit Agreement”) as agent. In addition, the C$133 million (U.S. $102 million ) of outstanding borrowings under KML’s prior credit facility were paid off prior to its termination with a portion of the proceeds from the TMPL Sale. Depending on the type of loan requested, interest on borrowings outstanding are calculated based on: (i) a Canadian prime rate of interest; (ii) a U.S. base rate; (iii) LIBOR; or (iv) bankers’ acceptance fees, plus (i) in the case of Canadian prime rate or U.S. base rate loans, an applicable margin of up to 1.25% ; or (ii) in the case of LIBOR or bankers’ acceptance loans, an applicable margin ranging from 1.00% to 2.25% , with such margin in any case determined by KML’s debt credit rating. Standby fees for the unused portion of the KML 2018 Credit Facility will be calculated at a rate ranging from 0.20% to 0.45% based upon KML’s debt credit rating. The KML Credit Agreement contains various financial and other covenants that apply to KML and its subsidiaries and that are common in such agreements, including a maximum ratio of KML’s consolidated total funded debt to its consolidated earnings before interest, income taxes, DD&A, and non-cash adjustments as defined in the KML Credit Agreement, of 5.00 :1.00 and restrictions on KML’s ability to incur debt, grant liens, make dispositions, engage in transactions with affiliates, make restricted payments, make investments, enter into sale leaseback transactions, amend organizational documents and engage in corporate reorganization transactions. In addition, the KML Credit Agreement contains customary events of default, including non-payment; non-compliance with covenants (in some cases, subject to grace periods); payment default under, or acceleration events affecting, certain other indebtedness; bankruptcy or insolvency events involving KML or guarantors; and changes of control. If an event of default under the KML Credit Agreement exists and is continuing, the lenders could terminate their commitments and accelerate the maturity of the outstanding obligations under the KML Credit Agreement. On May 30, 2018, in conjunction with the announcement of the TMPL Sale approximately C$100 million of borrowings outstanding under KML’s June 16, 2017 revolving credit facilities (the “KML 2017 Credit Facility”) were repaid, the underlying credit facilities were terminated, and approximately $46 million of deferred costs associated with the KML 2017 Credit Facility that were being amortized as interest expense over its term were written off. As of December 31, 2018 , KML had no borrowings outstanding under the KML 2018 Credit Facility, and had C$489 million (U.S. $359 million ) available under the KML 2018 Credit Facility, after reducing the C$500 million (U.S. $367 million ) capacity for the C$11 million (U.S. $8 million ) in letters of credit. Of the total C$11 million of letters of credit issued, approximately C$8 million are related to Trans Mountain for which it has issued a backstop letter of credit to KML. As of December 31, 2018, KML was in compliance with all required covenants. As of December 31, 2017, KML had no borrowings outstanding under the KML 2017 Credit Facility. Maturities of Debt The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2018 , are summarized as follows (in millions): Year Total 2019 $ 3,388 2020 2,205 2021 2,422 2022 2,518 2023 3,250 Thereafter 22,810 Total $ 36,593 Debt Fair Value Adjustments The carrying value adjustment to debt securities whose fair value is being hedged is included within “Debt fair value adjustments” on our accompanying consolidated balance sheets. “Debt fair value adjustments” also include unamortized debt discount/premiums, purchase accounting debt fair value adjustments, unamortized portion of proceeds received from the early termination of interest rate swap agreements, and debt issuance costs. As of December 31, 2018 , the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 16 years . The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets (in millions): December 31, Debt Fair Value Adjustments 2018 2017 Purchase accounting debt fair value adjustments $ 658 $ 719 Carrying value adjustment to hedged debt 2 115 Unamortized portion of proceeds received from the early termination of interest rate swap agreements 275 297 Unamortized debt discounts, net (74 ) (74 ) Unamortized debt issuance costs (130 ) (130 ) Total debt fair value adjustments $ 731 $ 927 Interest Rates, Interest Rate Swaps and Contingent Debt The weighted average interest rate on all of our borrowings was 5.15% during 2018 and 5.02% during 2017 . 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, 2018
Employee Benefits and Share-based Compensation, Noncash [Abstract]
Share-based Compensation and Employee Benefits	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, 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 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 2018 , 2017 and 2016 , we made restricted Class P common stock grants to our non-employee directors of 25,800 , 17,740 and 31,880 , respectively. These grants were valued at time of issuance at $500,000 , $400,000 and $400,000 , respectively. All of the restricted stock awards made to non-employee directors vest during a six -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 (in millions, except share and per share amounts): Year Ended Year Ended Year Ended December 31, 2018 December 31, 2017 December 31, 2016 Shares Weighted Average Shares Weighted Average Shares Weighted Average Grant Date Fair Value per Share Outstanding at beginning of period 10,518,344 $ 28.21 9,038,137 $ 32.72 7,645,105 $ 37.91 Granted 5,389,476 17.73 3,221,691 19.52 2,816,599 21.36 Vested (2,371,193 ) 36.34 (1,501,939 ) 36.67 (1,226,652 ) 38.53 Forfeited (382,022 ) 23.26 (239,545 ) 28.34 (196,915 ) 35.74 Outstanding at end of period 13,154,605 22.59 10,518,344 28.21 9,038,137 32.72 The intrinsic value of restricted stock awards vested during the years ended December 31, 2018 , 2017 and 2016 was $42 million , $30 million and $25 million , respectively. Restricted stock awards made to employees have vesting periods ranging from 1 year with variable vesting dates to 10 years . Following is a summary of the future vesting of our outstanding restricted stock awards: Year Vesting of Restricted Shares 2019 4,048,963 2020 3,537,544 2021 4,814,403 2022 152,104 2023 121,093 Thereafter 480,498 Total Outstanding 13,154,605 The related compensation costs less estimated forfeitures is generally recognized ratably over the vesting period of the restricted stock awards. Upon vesting, the grants will be paid in our Class P common shares. During 2018 , 2017 and 2016 , we recorded $63 million , $65 million and $66 million , respectively, in expense related to restricted stock awards and capitalized approximately $13 million , $9 million and $9 million , respectively. At December 31, 2018 and 2017 , unrecognized restricted stock awards compensation costs, less estimated forfeitures, was approximately $127 million with a weighted average remaining amortization period of 2.32 years . KML Restricted Shares KML adopted the 2017 Restricted Share Unit Plan for Employees, an equity awards plan, for its eligible employees, and the 2017 Restricted Share Unit Plan for Non-Employee Directors, in which its eligible non-employee directors participate. During the year ended December 31, 2018 and 2017 , we recognized $6 million and $1 million , respectively, of expense and capitalized $2 million and $1 million , respectively, related to these compensation programs. At December 31, 2018 , unrecognized compensation costs, less estimated forfeitures associated with KML’s restricted share unit awards, was approximately $3 million , with a weighted average remaining amortization period of 2.1 years . Pension and Other Postretirement Benefit 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. The total cost for our savings plan was approximately $48 million , $47 million , and $47 million for the years ended December 31, 2018 , 2017 and 2016 , 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 distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees accrue benefits through career pay or final pay formulas. Other Postretirement Benefit Plans We and certain of our subsidiaries provide other postretirement benefits (OPEB), 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. Additionally, our subsidiary SFPP has incurred certain liabilities for postretirement benefits to certain current and former employees, their covered dependents, and their beneficiaries. However, the net periodic benefit costs, contributions and liability amounts associated with the SFPP postretirement benefit plan are not material to our consolidated income statements or balance sheets. Plans Associated with Foreign Operations Two of our former subsidiaries, Kinder Morgan Canada Inc. and Trans Mountain Pipeline ULC (as general partner of Trans Mountain Pipeline L.P.), were sponsors of pension and OPEB plans for eligible Canadian and Trans Mountain pipeline employees. These subsidiaries, along with the plan assets of the Canadian pension and OPEB plans, were sold on August 31, 2018 (see Note 3). Prior to 2018, we included the net periodic benefit costs, contributions and liability amounts associated with our Canadian pension plans within our consolidated financial statements. In conjunction with the sale, Kinder Morgan Canada Services was formed and became the Canadian employer of the staff that operates our remaining Canadian assets. Kinder Morgan Canada Services subsequently established a defined contribution pension plan and an OPEB plan for eligible Canadian employees which are not material to our consolidated income statements and balance sheets, and therefore are excluded from the following disclosures. Benefit Obligation, Plan Assets and Funded Status . The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 2018 and 2017 (in millions): Pension Benefits OPEB 2018 2017 2018 2017 Change in benefit obligation: Benefit obligation at beginning of period $ 2,982 $ 2,884 $ 425 $ 473 Service cost 52 40 1 1 Interest cost 84 88 12 13 Actuarial (gain) loss (172 ) 155 (53 ) (16 ) Benefits paid (175 ) (180 ) (33 ) (38 ) Participant contributions — 3 1 2 Medicare Part D subsidy receipts — — 1 1 Exchange rate changes — 13 — 1 Settlements — (21 ) — — Other(a) (205 ) — (15 ) (12 ) Benefit obligation at end of period 2,566 2,982 339 425 Change in plan assets: Fair value of plan assets at beginning of period 2,296 2,160 335 332 Actual return on plan assets (128 ) 292 (5 ) 29 Employer contributions 30 32 7 9 Participant contributions — 3 1 2 Medicare Part D subsidy receipts — — 1 1 Benefits paid (175 ) (180 ) (33 ) (38 ) Exchange rate changes — 10 — — Settlements — (21 ) — — Other(a) (159 ) — — — Fair value of plan assets at end of period 1,864 2,296 306 335 Funded status - net liability at December 31, $ (702 ) $ (686 ) $ (33 ) $ (90 ) _______ (a) 2018 amounts represent December 31, 2017 balances associated with Canadian pension and OPEB plans that were included in the TMPL Sale. 2017 amounts represent December 31, 2016 balances associated with our Plantation Pipeline OPEB plan that are no longer included in these disclosures. Components of Funded Status . The following table details the amounts recognized in our balance sheets at December 31, 2018 and 2017 related to our pension and OPEB plans (in millions): Pension Benefits OPEB 2018 2017 2018 2017 Non-current benefit asset(a) $ — $ — $ 190 $ 198 Current benefit liability — — (13 ) (15 ) Non-current benefit liability (702 ) (686 ) (210 ) (273 ) Funded status - net liability at December 31, $ (702 ) $ (686 ) $ (33 ) $ (90 ) _______ (a) 2018 and 2017 OPEB amounts include $32 million and $33 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, 2018 and 2017 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets, including the portion attributable to our noncontrolling interests, (in millions): Pension Benefits OPEB 2018 2017 2018 2017 Unrecognized net actuarial (loss) gain $ (653 ) $ (635 ) $ 117 $ 88 Unrecognized prior service (cost) credit (3 ) (4 ) 14 17 Accumulated other comprehensive (loss) income $ (656 ) $ (639 ) $ 131 $ 105 We anticipate that approximately $40 million of pre-tax accumulated other comprehensive loss, inclusive of amounts reported as noncontrolling interests, will be recognized as part of our net periodic benefit cost in 2019 , including approximately $42 million of unrecognized net actuarial loss and approximately $2 million of unrecognized prior service credit. Our accumulated benefit obligation for our pension plans was $2,535 million and $2,840 million at December 31, 2018 and 2017 , respectively. Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $293 million and $373 million at December 31, 2018 and 2017 , respectively. The fair value of these plans’ assets was approximately $70 million and $84 million at December 31, 2018 and 2017 , respectively. Plan Assets. The investment policies and strategies are established by the 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 (1) meet or exceed plan actuarial earnings assumptions over the long term and (2) 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, 2018 , the allowable range for asset allocations in effect for our pension plan were 34% to 59% 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, 2018 , the allowable range for asset allocations in effect for our OPEB plans were 42% to 67% equity, 25% to 51% fixed income and 0% to 20% 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, exchange traded mutual funds and MLPs. 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. • Level 3 assets’ fair values are calculated using valuation techniques that require inputs that are both significant to the fair value measurement and are unobservable, or are similar to Level 2 assets. Included in this level are guaranteed insurance contracts and immediate participation guarantee contracts. These contracts are valued at contract value, which approximates fair value. • 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, limited partnerships, and fixed income trusts. 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, 2018 and 2017 (in millions): Pension Assets 2018 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Cash $ — $ — $ — $ — $ 6 $ — $ — $ 6 Short-term investment funds — 7 — 7 — 65 — 65 Mutual funds(a) 81 — — 81 245 — — 245 Equities(b) 227 — — 227 278 — — 278 Fixed income securities — 422 — 422 — 416 — 416 Derivatives — 6 — 6 — 5 — 5 Subtotal $ 308 $ 435 $ — $ 743 $ 529 $ 486 $ — $ 1,015 Measured at NAV(c) Common/collective trusts(d) 857 895 Private investment funds(e) 215 337 Private limited partnerships(f) 49 49 Subtotal 1,121 1,281 Total plan assets fair value $ 1,864 $ 2,296 _______ (a) Includes mutual funds which are invested in equity. (b) Plan assets include $94 million and $110 million of KMI Class P common stock for 2018 and 2017 , respectively. (c) Plan assets for which fair value was measured using NAV as a practical expedient. (d) Common/collective trust funds were invested in approximately 37% fixed income and 63% equity in 2018 and 36% fixed income and 64% equity in 2017 . (e) Private investment funds were invested in approximately 71% fixed income and 29% equity in 2018 and 52% fixed income and 48% equity in 2017 . (f) Includes assets invested in real estate, venture and buyout funds. OPEB Assets 2018 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Short-term investment funds $ — $ 4 $ — $ 4 $ — $ 7 $ — $ 7 Equities(a) — — — — 16 — — 16 MLPs — — — — 50 — — 50 Guaranteed insurance contracts — — 51 51 — — 49 49 Mutual funds 1 — — 1 1 — — 1 Subtotal $ 1 $ 4 $ 51 $ 56 $ 67 $ 7 $ 49 $ 123 Measured at NAV(b) Common/collective trusts(c) 250 68 Fixed income trusts — 66 Limited partnerships(d) — 78 Subtotal 250 212 Total plan assets fair value $ 306 $ 335 _______ (a) Plan assets include $2 million of KMI Class P common stock for 2017 . (b) Plan assets for which fair value was measured using NAV as a practical expedient. (c) Common/collective trust funds were invested in approximately 60% equity and 40% fixed income securities for 2018 and 71% equity and 29% fixed income securities for 2017 . (d) Limited partnerships were invested in global equity securities. The following tables present the changes in our pension and OPEB plans’ assets included in Level 3 for the years ended December 31, 2018 and 2017 (in millions): Pension Assets Balance at Beginning of Period Transfers In (Out) Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period 2017 Insurance contracts $ 16 $ — $ — $ (16 ) $ — OPEB Assets Balance at Beginning of Period Transfers In (Out) Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period 2018 Insurance contracts $ 49 $ — $ 4 $ (2 ) $ 51 2017 Insurance contracts $ 47 $ — $ 5 $ (3 ) $ 49 Changes in the underlying value of Level 3 assets due to the effect of changes of fair value were immaterial for the years ended December 31, 2018 and 2017 . Expected Payment of Future Benefits and Employer Contributions . As of December 31, 2018 , we expect to make the following benefit payments under our plans (in millions): Fiscal year Pension Benefits OPEB(a) 2019 $ 234 $ 33 2020 233 32 2021 225 32 2022 223 31 2023 214 29 2024 - 2028 969 127 _______ (a) Includes a reduction of approximately $2 million in each of the years 2019 - 2023 and approximately $13 million in aggregate for 2024 - 2028 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. In 2019 , we expect to contribute approximately $60 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 2018 , 2017 and 2016 : Pension Benefits OPEB 2018 2017 2016 2018 2017 2016 Assumptions related to benefit obligations: Discount rate 4.26 % 3.56 % 3.83 % 4.16 % 3.48 % 3.69 % Rate of compensation increase 3.50 % 3.53 % 3.52 % n/a n/a n/a Assumptions related to benefit costs: Discount rate for benefit obligations 3.56 % 3.83 % 4.05 % 3.48 % 3.69 % 3.91 % Discount rate for interest on benefit obligations 3.13 % 3.09 % 3.24 % 3.08 % 3.05 % 3.18 % Discount rate for service cost 3.56 % 3.88 % 4.15 % 3.82 % 4.15 % 4.36 % Discount rate for interest on service cost 3.14 % 3.24 % 3.50 % 3.76 % 3.95 % 4.17 % Expected return on plan assets(a) 7.25 % 7.07 % 7.31 % 7.08 % 6.84 % 7.07 % Rate of compensation increase 3.50 % 3.52 % 3.51 % 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 a UBIT rate of 21% for 2018 , 2017 and 2016 . 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 assumed a weighted-average annual rate of increase in the per capita cost of covered health care benefits of 7.26% , gradually decreasing to 4.54% by the year 2038. Assumed health care cost trends have a significant effect on the amounts reported for OPEB plans. A one -percentage point change in assumed health care cost trends would have the following effects as of December 31, 2018 and 2017 (in millions): 2018 2017 One-percentage point increase: Aggregate of service cost and interest cost $ 1 $ 1 Accumulated postretirement benefit obligation 16 22 One-percentage point decrease: Aggregate of service cost and interest cost $ (1 ) $ (1 ) Accumulated postretirement benefit obligation (14 ) (19 ) 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 (in millions): Pension Benefits OPEB 2018 2017 2016 2018 2017 2016 Components of net benefit cost: Service cost $ 52 $ 40 $ 36 $ 1 $ 1 $ 1 Interest cost 84 88 89 12 13 16 Expected return on assets (149 ) (147 ) (151 ) (20 ) (19 ) (19 ) Amortization of prior service cost (credit) — 1 1 (4 ) (3 ) (3 ) Amortization of net actuarial loss (gain) 40 52 35 (6 ) (6 ) — Curtailment and settlement loss — 5 — — — — Net benefit (credit) cost(a) 27 39 10 (17 ) (14 ) (5 ) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 105 17 116 (32 ) (25 ) (48 ) Prior service cost (credit) arising during period — — — — — — Amortization or settlement recognition of net actuarial (loss) gain (87 ) (64 ) (34 ) 3 6 — Amortization of prior service (cost) credit (1 ) (1 ) — 3 1 1 Exchange rate changes — — 1 — — — Total recognized in total other comprehensive (income) loss 17 (48 ) 83 (26 ) (18 ) (47 ) Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ 44 $ (9 ) $ 93 $ (43 ) $ (32 ) $ (52 ) _______ (a) 2018 and 2017 OPEB amounts each include $4 million of net benefit credits related to a plan that we sponsor that is associated with employee services provided to an unconsolidated joint venture. We charge or refund these costs or credits associated with this plan to the joint venture as an offset to our net benefit cost or credit and receive our proportionate share of these costs or credits through our share of the equity investee’s earnings. Multiemployer Plans We participate in several multi-employer pension plans for the benefit of employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs. Amounts charged to expense for these plans were approximately $8 million for each of the years ended December 31, 2018 , 2017 and 2016 . We consider the overall multi-employer pension plan liability exposure to be minimal in relation to the value of its total consolidated assets and net income.

Stockholders' Equity (Notes)

Stockholders' Equity (Notes)	12 Months Ended
	Dec. 31, 2018
Stockholders' Equity Note [Abstract]
Shareholders' Equity	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 current market price of our common stock at the time of conversion, our Series A Preferred Shares converted into approximately 58 million common shares. Preferred Stock Dividends Dividends on our mandatory convertible preferred stock were payable on a cumulative basis when, as and if declared by our board of directors (or an authorized committee thereof) at an annual rate of 9.75% of the liquidation preference of $1,000 per share on January 26, April 26, July 26 and October 26 of each year, commencing on January 26, 2016 to, and including, October 26, 2018. Prior to the October 26, 2018 conversion of our Series A Preferred Shares into common shares, we paid all dividends on our mandatory convertible preferred stock in cash. The following table provides information regarding our preferred stock dividends: Period Total dividend per share for the period Date of declaration Date of record Date of dividend January 26, 2018 through April 25, 2018 $24.375 January 17, 2018 April 11, 2018 April 26, 2018 April 26, 2018 through July 25, 2018 24.375 April 18, 2018 July 11, 2018 July 26, 2018 July 26, 2018 through October 25, 2018 24.375 July 18, 2018 October 11, 2018 October 26, 2018 Common Equity As of December 31, 2018 , 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, 2018 and 2017, we repurchased approximately 15 million and 14 million , respectively, of our Class P shares for approximately $273 million and $250 million , respectively. 2018 amounts exclude repurchases made in December 2018 of approximately 0.1 million of our Class P shares for approximately $2 million which settled on January 2, 2019. 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, 2018, 2017 and 2016 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, 2018 2017 2016 Per common share cash dividend declared for the period $ 0.80 $ 0.50 $ 0.50 Per common share cash dividend paid in the period 0.725 0.50 0.50 On January 16, 2019, our board of directors declared a cash dividend of $0.20 per common share for the quarterly period ended December 31, 2018, which is payable on February 15, 2019 to shareholders of record as of January 31, 2019. Warrants The warrant repurchase program dated June 12, 2015, which authorized us to repurchase up to $100 million of warrants, expired along with the warrants on May 25, 2017, at which time 293 million of unexercised warrants to buy KMI common stock expired without the issuance of Class P common stock. Prior to expiration, each of the warrants entitled the holder to purchase one share of our common stock for an exercise price of $40 per share, payable in cash or by cashless exercise. Noncontrolling Interests The caption “Noncontrolling interests” in our accompanying consolidated balance sheets consists of interests that we do not own in the following subsidiaries (in millions): December 31, 2018 2017 KML(a) $ 514 $ 1,163 Others 339 325 $ 853 $ 1,488 _______ (a) The reduction in the noncontrolling interests associated with KML is primarily attributable to the accrual of the return of capital distribution for the net proceeds from the TMPL Sale paid to KML’s Restricted Voting Shareholders on January 3, 2019 of approximately $0.9 billion . KML Contributions KML Restricted Voting Shares As discussed in Note 3, on May 30, 2017 our indirect subsidiary, KML, issued 102,942,000 restricted voting shares in a public offering listed on the Toronto Stock Exchange. The public ownership of the KML restricted voting shares represents an approximate 30% interest in our Canadian operations and is reflected within “Noncontrolling interests” in our consolidated financial statements as of and for the period presented after May 30, 2017. KML Preferred Share Offerings On August 15, 2017, KML completed an offering of 12,000,000 cumulative redeemable minimum rate reset preferred shares, Series 1 (Series 1 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 1 Preferred Share for total gross proceeds of C$300 million (U.S. $235 million ). On December 15, 2017, KML completed an offering of 10,000,000 cumulative redeemable minimum rate reset preferred shares, Series 3 (Series 3 Preferred Shares) on the Toronto Stock Exchange at a price to the public of C$25.00 per Series 3 Preferred Share for total gross proceeds of C$250 million (U.S. $195 million ). The net proceeds from the Series 1 and Series 3 Preferred Share offerings of C$293 million (U.S. $230 million ) and C$243 million (U.S. $189 million ), respectively, were used by KML to indirectly subscribe for preferred units in KMC LP, which in turn were used by KMC LP to repay the KML Credit Facility indebtedness recently incurred to, directly or indirectly, finance the development, construction and completion of the TMEP and Base Line Terminal project, and for its general corporate purposes. KML Distributions KML has a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its DCF. The payment of dividends is not guaranteed and the amount and timing of any dividends payable will be at the discretion of KML’s board of directors. If declared by KML’s board of directors, KML will pay quarterly dividends, on or about the 45th day (or next business day) following the end of each calendar quarter to holders of its restricted voting shares of record as of the close of business on or about the last business day of the month following the end of each calendar quarter. KML also established a Dividend Reinvestment Plan (DRIP) which allows holders (excluding holders not resident in Canada) of restricted voting shares to elect to have any or all cash dividends payable to such shareholder automatically reinvested in additional restricted voting shares at a price per share calculated by reference to the volume-weighted average of the closing price of the restricted voting shares on the stock exchange on which the restricted voting shares are then listed for the five trading days immediately preceding the relevant dividend payment date, less a discount of between 0% and 5% (as determined from time to time by KML’s board of directors, in its sole discretion). Subsequent Event On January 16, 2019, KML’s board of directors announced that it would suspend KML’s DRIP, effective with the payment of the fourth quarter 2018 dividend noted above, in light of KML’s reduced need for capital. KML also pays dividends on its Series 1 Preferred Shares and Series 3 Preferred Shares, which are fixed, cumulative, preferential, and payable quarterly in the annual amount of C$1.3125 per share and C$1.3000 per share, respectively, on the 15th day of February, May, August and November, as and when declared by KML’s board of directors, for the initial fixed rate period to but excluding November 15, 2022 and February 15, 2023, respectively. During the years ended December 31, 2018 and 2017, KML paid dividends on its Restricted Voting Shares to the public valued at $52 million and $18 million , respectively, of which $38 million and $13 million , respectively, was paid in cash. The remaining value of $14 million and $5 million for the years ended December 31, 2018 and 2017, respectively, was paid in 1,092,791 and 418,989 , respectively, KML Restricted Voting Shares. KML also paid dividends to the public on its Series 1 and Series 3 Preferred Shares of $21 million for the year ended December 31, 2018 and on its Series 1 Preferred Shares of $3 million for the year ended December 31, 2017.

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	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 joint venture partners of our joint ventures we consolidate, and 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 (in millions): December 31, 2018 2017 Balance sheet location Accounts receivable, net $ 48 $ 34 Other current assets 2 8 Deferred charges and other assets 55 23 $ 105 $ 65 Current portion of debt $ 6 $ 6 Accounts payable 26 18 Other current liabilities 7 4 Long-term debt 148 155 Other long-term liabilities and deferred credits 34 35 $ 221 $ 218 Year Ended December 31, 2018 2017 2016 Income statement location Revenues Services $ 171 $ 73 $ 71 Product sales and other 94 89 71 $ 265 $ 162 $ 142 Operating Costs, Expenses and Other Costs of sales $ 63 $ 20 $ 38 Other operating expenses 91 100 75

Commitments and Contingent Liab

Commitments and Contingent Liabilities (Notes)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	Commitments and Contingent Liabilities Leases and Rights-of-Way Obligations The table below depicts future gross minimum rental commitments under our operating leases and rights-of-way obligations as of December 31, 2018 (in millions): Year Commitment 2019 $ 122 2020 107 2021 102 2022 97 2023 81 Thereafter 353 Total minimum payments $ 862 The remaining terms on our operating leases, including probable elections to exercise renewal options, range from one to thirty-five years. Total lease and rental expenses were $155 million , $140 million and $138 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. The amount of capital leases included within “Property, plant and equipment, net” in our accompanying consolidated balance sheets as of December 31, 2018 and 2017 is not material to our consolidated balance sheets. 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, 2018 and 2017 , our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $714 million and $1,070 million , respectively. December 31, 2018 and 2017 amounts are represented by our proportional share of the debt obligations of four and three equity investees, respectively. Under such guarantees we are severally liable for our percentage ownership share of these equity investees’ debt issued in the event of their non-performance. Also included in our contingent debt obligations is a guarantee of a throughput and deficiency agreement supporting certain debt obligations of a subsidiary of our investee, Cortez Pipeline Company. Through this guarantee, we are severally liable for approximately 50% of a Cortez Pipeline Company subsidiary’s debt obligations with respect to a $50 million credit facility and $100 million in bonds. In addition, we have guaranteed approximately 100% of the debt issued by another Cortez Pipeline Company subsidiary to fund an expansion project, of which debt consists of a $27 million credit facility and a $120 million private placement note. Guarantees and Indemnifications We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters. While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are also circumstances where the amount and duration are unlimited. Currently, we are not subject to any material requirements to perform under quantifiable arrangements. We are unable to estimate a maximum exposure for our 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, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management	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 and net investments in foreign operations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks. During the year ended December 31, 2018, due to volatility in certain basis differentials, we discontinued hedge accounting on certain of our crude oil derivative contracts as we did not expect them to be highly effective, for accounting purposes, in offsetting the variability in cash flows. As of December 31, 2018, these hedging relationships had been re-designated as the effectiveness improved to required levels. As the forecasted transactions were still probable, accumulated gains and losses prior to the discontinuance remained in “Accumulated other comprehensive loss” unless earnings were impacted by the forecasted transactions; however, changes in the derivative contracts’ fair value subsequent to the discontinuance of hedge accounting and prior to the re-designation were reported in earnings. Upon re-designation, we resumed reporting changes in the derivative contracts’ fair value in “Accumulated other comprehensive income.” Energy Commodity Price Risk Management As of December 31, 2018 , 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 (21.6 ) MMBbl Crude oil basis (13.7 ) MMBbl Natural gas fixed price (33.3 ) Bcf Natural gas basis (26.1 ) Bcf Derivatives not designated as hedging contracts Crude oil fixed price (0.5 ) MMBbl Crude oil basis (4.5 ) MMBbl Natural gas fixed price (4.5 ) Bcf Natural gas basis (26.9 ) Bcf NGL fixed price (3.2 ) MMBbl As of December 31, 2018 , 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 2022. Interest Rate Risk Management As of December 31, 2018 and 2017, we had a combined notional principal amount of $10,575 million and $9,575 million , respectively, of fixed-to-variable interest rate swap agreements, all of which were designated as fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of December 31, 2018 , the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of debt due to interest rate risk is through March 15, 2035. Foreign Currency Risk Management As of both December 31, 2018 and 2017 , we had a notional principal amount of $1,358 million of cross-currency swap agreements to manage the foreign currency risk related to our Euro denominated senior notes by effectively converting all of the fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates equivalent to approximately 3.79% and 4.67% for the 7 -year and 12 -year senior notes, respectively. These cross-currency swaps are accounted for as cash flow hedges. The terms of the cross-currency swap agreements correspond to the related hedged senior notes, and such agreements have the same maturities as the hedged senior notes. During the year ended December 31, 2018, we entered into foreign currency swap agreements with a combined notional principal amount of C$2,450 million (U.S. $1,888 million ). These swaps result in our selling fixed C$ and receiving fixed U.S.$, effectively hedging the foreign currency risk associated with a substantial portion of our share of the TMPL Sale proceeds which KML distributed on January 3, 2019, at which time the foreign currency swaps expired. These foreign currency swaps were accounted for as net investment hedges as the foreign currency risk was related to our investment in Canadian dollar denominated foreign operations, and the critical risks of the forward contracts coincided with those of the net investment. As a result, the change in fair value of the foreign currency swaps while outstanding were reflected in the CTA section of OCI. Fair Value of Derivative Contracts The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets (in millions): Fair Value of Derivative Contracts Asset derivatives Liability derivatives December 31, December 31, 2018 2017 2018 2017 Location Fair value Fair value Derivatives designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 135 $ 65 $ (45 ) $ (53 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 64 14 — (24 ) Subtotal 199 79 (45 ) (77 ) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 12 41 (37 ) (3 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 121 164 (78 ) (62 ) Subtotal 133 205 (115 ) (65 ) Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) 91 — (6 ) (6 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 106 166 — — Subtotal 197 166 (6 ) (6 ) Total 529 450 (166 ) (148 ) Derivatives not designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 22 8 (5 ) (22 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — — (2 ) Total 22 8 (5 ) (24 ) Total derivatives $ 551 $ 458 $ (171 ) $ (172 ) Effect of Derivative Contracts on the Income Statement The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of income (in millions): Derivatives in fair value hedging relationships Location Gain/(loss) recognized in income on derivatives and related hedged item Year Ended December 31, 2018 2017 2016 Interest rate contracts Interest, net $ (122 ) $ (103 ) $ (180 ) Hedged fixed rate debt Interest, net $ 113 $ 105 $ 160 Derivatives in cash flow hedging relationships Gain/(loss) recognized in OCI on derivative (effective portion)(a) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Year Ended Year Ended Year Ended December 31, December 31, December 31, 2018 2017 2016 2018 2017 2016 2018 2017 2016 Energy commodity derivative contracts $ 201 $ 37 $ (182 ) Revenues—Natural gas sales $ (29 ) $ 18 $ 23 Revenues—Natural gas sales $ — $ — $ — Revenues—Product sales and other (30 ) 55 233 Revenues—Product sales and other (65 ) 11 (12 ) Costs of sales 21 14 (26 ) Costs of sales — — — Interest rate contracts(c) 3 — (3 ) Interest, net (4 ) (5 ) (4 ) Interest, net — — — Foreign currency contracts (59 ) 190 21 Other, net (67 ) 186 (43 ) Other, net — — — Total $ 145 $ 227 $ (164 ) Total $ (109 ) $ 268 $ 183 Total $ (65 ) $ 11 $ (12 ) _______ (a) We expect to reclassify an approximate $165 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2018 into earnings during the next twelve months (when the associated forecasted transactions are also expected to occur); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices. (b) 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 (effective portion) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(a) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Year Ended Year Ended Year Ended December 31, December 31, December 31, 2018 2017 2016 2018 2017 2016 2018 2017 2016 Foreign currency contracts $ 91 $ — $ — Loss on impairments and divestitures, net $ 26 $ — $ — Other, net $ — $ — $ — Total $ 91 $ — $ — Total $ 26 $ — $ — Total $ — $ — $ — _______ (a) During the year ended December 31, 2018, we recognized a $26 million gain from our accumulated other comprehensive loss balance related to the TMPL Sale. See Note 3. Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives Year Ended December 31, 2018 2017 2016 Energy commodity derivative contracts Revenues—Natural gas sales $ 3 $ 20 $ (10 ) Revenues—Product sales and other (12 ) (16 ) (26 ) Costs of sales 2 — 3 Interest rate contracts Interest, net — — 63 Total(a) $ (7 ) $ 4 $ 30 ________ (a) For the years ended December 31, 2018 , 2017 and 2016 includes approximate losses of $4 million and gains of $57 million and $73 million , respectively, associated with natural gas, crude and NGL derivative contract settlements. Credit Risks In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2018 and 2017 , we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2018 , we had cash margins of $16 million posted by our counterparties with us as collateral and reported within “Other Current Liabilities” on our accompanying consolidated balance sheet. As of December 31, 2017 , we had cash margins of $1 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheet. The balance at December 31, 2018 consisted of initial margin requirements of $9 million offset by variation margin requirements of $25 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, 2018 , based on our current mark to market positions and posted collateral, we estimate that if our credit rating were downgraded one or two notches we would not be required to post additional collateral. 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 (in millions): Net unrealized gains/(losses) on cash flow hedge derivatives Foreign currency translation adjustments Pension and other postretirement liability adjustments Total Accumulated other comprehensive loss Balance at December 31, 2015 $ 219 $ (322 ) $ (358 ) $ (461 ) Other comprehensive (loss) gain before reclassifications (104 ) 34 (14 ) (84 ) Gains reclassified from accumulated other comprehensive loss (116 ) — — (116 ) Net current-period other comprehensive (loss) income (220 ) 34 (14 ) (200 ) Balance at December 31, 2016 (1 ) (288 ) (372 ) (661 ) Other comprehensive gain before reclassifications 145 55 40 240 Gains reclassified from accumulated other comprehensive loss (171 ) — — (171 ) KML IPO — 44 7 51 Net current-period other comprehensive (loss) income (26 ) 99 47 120 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 (Note 1) (4 ) (36 ) (69 ) (109 ) Net current-period other comprehensive income (loss) 191 98 (78 ) 211 Balance at December 31, 2018 $ 164 $ (91 ) $ (403 ) $ (330 ) _______ (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.

Fair Value (Notes)

Fair Value (Notes)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
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. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. The three broad levels of inputs defined by the fair value hierarchy are as follows: • Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date; • Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and • Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data). Fair Value of Derivative Contracts The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the Codification (in millions). The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements. Balance sheet asset fair value measurements by level Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral held(b) Net amount As of December 31, 2018 Energy commodity derivative contracts(a) $ 28 $ 193 $ — $ 221 $ (39 ) $ (25 ) $ 157 Interest rate contracts $ — $ 133 $ — $ 133 $ (7 ) $ — $ 126 Foreign currency contracts $ — $ 197 $ — $ 197 $ (6 ) $ — $ 191 As of December 31, 2017 Energy commodity derivative contracts(a) $ 17 $ 70 $ — $ 87 $ (42 ) $ (12 ) $ 33 Interest rate contracts $ — $ 205 $ — $ 205 $ (15 ) $ — $ 190 Foreign currency contracts $ — $ 166 $ — $ 166 $ (6 ) $ — $ 160 Balance sheet liability fair value measurements by level Level 1 Level 2 Level 3 Gross amount Contracts available for netting Collateral posted(b) Net amount As of December 31, 2018 Energy commodity derivative contracts(a) $ (11 ) $ (39 ) $ — $ (50 ) $ 39 $ — $ (11 ) Interest rate contracts $ — $ (115 ) $ — $ (115 ) $ 7 $ — $ (108 ) Foreign currency contracts $ — $ (6 ) $ — $ (6 ) $ 6 $ — $ — As of December 31, 2017 Energy commodity derivative contracts(a) $ (3 ) $ (98 ) $ — $ (101 ) $ 42 $ — $ (59 ) Interest rate contracts $ — $ (65 ) $ — $ (65 ) $ 15 $ — $ (50 ) Foreign currency contracts $ — $ (6 ) $ — $ (6 ) $ 6 $ — $ — _______ (a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and NGL 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. Fair Value of Financial Instruments The carrying value and estimated fair value of our outstanding debt balances is disclosed below (in millions): December 31, 2018 December 31, 2017 Carrying value Estimated fair value Carrying value Estimated fair value Total debt $ 37,324 $ 37,469 $ 37,843 $ 40,050 We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2018 and 2017 .

Revenue Recognition (Notes)

Revenue Recognition (Notes)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Revenue Recognition Adoption of Topic 606 Effective January 1, 2018, we adopted ASU No. 2014-09, “Revenue from Contracts with Customers” and the series of related accounting standard updates that followed (collectively referred to as “Topic 606”). We utilized the modified retrospective method to adopt Topic 606, which required us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) revenue contracts that were not completed as of January 1, 2018. In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 were not revised. The cumulative effect of this adoption of Topic 606 as of January 1, 2018 was not material. The impact to our consolidated financial statement line items from the adoption of Topic 606 for these changes was as follows (in millions): Year ended December 31, 2018 Line Item As Reported Amounts Without Adoption of Topic 606 Effect of Change Increase/(Decrease) Consolidated Statement of Income Natural gas sales $ 3,281 $ 3,339 $ (58 ) Services 7,931 8,134 (203 ) Product sales and other 2,932 3,270 (338 ) Total Revenues 14,144 14,743 (599 ) Cost of sales 4,421 5,020 (599 ) Operating Income 3,794 3,794 — The effect-of-change amounts in the table above are attributable to the non-FERC-regulated portion of our Natural Gas Pipelines business segment, which provides gathering, processing and processed commodity sales services for various producers. In those instances where we purchase and obtain control of the entire natural gas stream in our producer arrangements, we have determined these are contracts with suppliers rather than contracts with customers, and therefore, these arrangements are not included in the scope of Topic 606. These supplier arrangements are subject to updated guidance in ASC 705, Cost of Sales and Services, whereby any embedded fees within such contracts, which historically have been reported as Services revenue, are now reported as a reduction to Cost of sales upon adoption of Topic 606. In our natural gas processing arrangements where we extract and sell the commodities derived from the processed natural gas stream (i.e., residue gas or NGLs), we may take control of: (i) none of the commodities we sell, (ii) a portion of the commodities we sell, or (iii) all of the commodities we sell. In those instances where we remit all of the cash proceeds received from third parties for selling the extracted commodities, less the fees attributable to these arrangements, we have determined that the producer has control over these commodities. Upon adoption of Topic 606, we eliminated recording both sales revenue (Natural gas and Product) and Cost of sales amounts and now only record fees attributable to these arrangements to Service revenues. In other instances where we do not obtain control of the extracted commodities we sell, we are acting as an agent for the producer and, upon adoption of Topic 606, we have continued to recognize Services revenue for the net amount of consideration we retain in exchange for our service. When we purchase and obtain control of a portion of the residue gas or NGLs we sell, we have determined these arrangements contain both a supply and a service revenue element and therefore are partially in the scope of Topic 606. In these arrangements, the producer is a supplier for the cash settled portion of the commodity we purchase and a customer with regards to the service provided to gather and redeliver the other component. Upon adoption of Topic 606, fees attributable to the supply element are recorded as a reduction to Cost of sales and fees attributable to the service element are recorded as Services revenue. Previously, we recognized Services revenue for both elements. 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 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 based on a 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 3). 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 (in millions): Year ended December 31, 2018 Natural Gas Pipelines Products Pipelines Terminals CO 2 Kinder Morgan Canada Corporate and Eliminations Total Revenues from contracts with customers(a) Services Firm services(b) $ 3,215 $ 566 $ 976 $ 2 $ — $ (13 ) $ 4,746 Fee-based services 860 791 581 67 167 — 2,466 Total services revenues 4,075 1,357 1,557 69 167 (13 ) 7,212 Sales Natural gas sales 3,319 — — 2 — (11 ) 3,310 Product sales 1,333 216 18 1,222 — (1 ) 2,788 Other sales 8 — — — — — 8 Total sales revenues 4,660 216 18 1,224 — (12 ) 6,106 Total revenues from contracts with customers 8,735 1,573 1,575 1,293 167 (25 ) 13,318 Other revenues(c) 280 140 444 (38 ) 3 (3 ) 826 Total revenues $ 9,015 $ 1,713 $ 2,019 $ 1,255 $ 170 $ (28 ) $ 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) below). (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 Accounting Standards Codification other than in Topic 606 and primarily include leases and derivatives. The majority of our lease revenues are from certain firm service contracts that are accounted for as operating leases. See Note 14 for additional information related to our derivative contracts. 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. The following table presents the activity in our contract assets and liabilities (in millions): Year ended December 31, 2018 Contract Assets Balance at January 1, 2018 $ 32 Additions 59 Transfer to Accounts receivable (67 ) Balance at December 31, 2018(a) $ 24 Contract Liabilities Balance at January 1, 2018 $ 206 Additions 453 Transfer to Revenues (360 ) Other(b) (7 ) Balance at December 31, 2018(c) $ 292 _______ (a) Includes current and non-current balances of $14 million and $10 million reported within “Other current assets” and “Deferred charges and other assets,” respectively, in our accompanying consolidated balance sheet at December 31, 2018 . (b) Includes 2018 foreign currency translation adjustments associated with the balances at December 31, 2017 . (c) Includes current and non-current balances of $80 million and $212 million reported within “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheet at December 31, 2018 . 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, 2018 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions): Year Estimated Revenue 2019 $ 4,881 2020 4,182 2021 3,528 2022 3,011 2023 2,497 Thereafter 14,138 Total $ 32,237 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 expedients that we elected to apply, remaining performance obligations for: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services; (ii) contracts with an original expected duration of one year or less; and (iii) contracts for which we recognize revenue at the amount for which we have the right to invoice for services performed.

Reportable Segments (Notes)

Reportable Segments (Notes)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Reportable Segments	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 and crude oil gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG facilities; • Products Pipelines—the ownership and operation of refined petroleum products, NGL and crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, propane, ethane, 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 that transload and store refined petroleum products, crude oil, ethanol and chemicals, and bulk products, including petroleum coke, metals and ores; and (ii) Jones Act 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 gas 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, 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 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 either market value or, in some instances, book value. During 2018, 2017 and 2016, we did not have revenues from any single external customer that exceeded 10% of our consolidated revenues. Financial information by segment follows (in millions): Year Ended December 31, 2018 2017 2016 Revenues Natural Gas Pipelines Revenues from external customers $ 9,004 $ 8,608 $ 7,998 Intersegment revenues 11 10 7 Products Pipelines Revenues from external customers 1699 1645 1631 Intersegment revenues 14 16 18 Terminals Revenues from external customers 2,017 1,965 1,921 Intersegment revenues 2 1 1 CO2 1,255 1,196 1,221 Kinder Morgan Canada 170 256 253 Corporate and intersegment eliminations(a) (28 ) 8 8 Total consolidated revenues $ 14,144 $ 13,705 $ 13,058 Year Ended December 31, 2018 2017 2016 Operating expenses(b) Natural Gas Pipelines $ 5,353 $ 5,457 $ 4,393 Products Pipelines 594 487 573 Terminals 818 788 768 CO 2 453 394 399 Kinder Morgan Canada 72 95 87 Corporate and intersegment eliminations (2 ) (6 ) 2 Total consolidated operating expenses $ 7,288 $ 7,215 $ 6,222 Year Ended December 31, 2018 2017 2016 Other expense (income)(c) Natural Gas Pipelines $ 593 $ 26 $ 199 Products Pipelines 34 — 76 Terminals 54 (14 ) 99 CO 2 79 (1 ) 19 Kinder Morgan Canada (596 ) — — Corporate — 1 (7 ) Total consolidated other expense (income) $ 164 $ 12 $ 386 Year Ended December 31, 2018 2017 2016 DD&A Natural Gas Pipelines $ 1,058 $ 1,011 $ 1,041 Products Pipelines 228 216 221 Terminals 484 472 435 CO 2 473 493 446 Kinder Morgan Canada 29 46 44 Corporate 25 23 22 Total consolidated DD&A $ 2,297 $ 2,261 $ 2,209 Year Ended December 31, 2018 2017 2016 Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments Natural Gas Pipelines $ 391 $ 253 $ (269 ) Products Pipelines 75 48 56 Terminals 22 24 19 CO 2 34 42 22 Total consolidated equity earnings $ 522 $ 367 $ (172 ) Year Ended December 31, 2018 2017 2016 Other, net-income (expense) Natural Gas Pipelines $ 37 $ 49 $ 19 Products Pipelines 3 (1 ) 2 Terminals 2 8 4 Kinder Morgan Canada 26 25 15 Corporate 39 16 38 Total consolidated other, net-income (expense) $ 107 $ 97 $ 78 Year Ended December 31, 2018 2017 2016 Segment EBDA(d) Natural Gas Pipelines $ 3,580 $ 3,487 $ 3,211 Products Pipelines 1,173 1,231 1,067 Terminals 1,171 1,224 1,078 CO 2 759 847 827 Kinder Morgan Canada 720 186 181 Total segment EBDA 7,403 6,975 6,364 DD&A (2,297 ) (2,261 ) (2,209 ) Amortization of excess cost of equity investments (95 ) (61 ) (59 ) General and administrative and corporate charges (588 ) (660 ) (652 ) Interest, net (1,917 ) (1,832 ) (1,806 ) Income tax expense (587 ) (1,938 ) (917 ) Total consolidated net income $ 1,919 $ 223 $ 721 Year Ended December 31, 2018 2017 2016 Capital expenditures Natural Gas Pipelines $ 1,620 $ 1,376 $ 1,227 Products Pipelines 150 127 244 Terminals 380 888 983 CO 2 397 436 276 Kinder Morgan Canada 332 338 124 Corporate 25 23 28 Total consolidated capital expenditures $ 2,904 $ 3,188 $ 2,882 2018 2017 Investments at December 31 Natural Gas Pipelines $ 6,358 $ 6,218 Products Pipelines 839 777 Terminals 268 263 CO 2 16 6 Kinder Morgan Canada — 34 Total consolidated investments $ 7,481 $ 7,298 2018 2017 Assets at December 31 Natural Gas Pipelines $ 51,562 $ 51,173 Products Pipelines 8,429 8,539 Terminals 9,283 9,935 CO 2 3,928 3,946 Kinder Morgan Canada — 2,080 Corporate assets(e) 5,664 3,382 Total consolidated assets $ 78,866 $ 79,055 _______ (a) 2017 and 2016 amounts include a management fee of $35 million and $34 million , respectively, for services we perform as operator of an equity investee. (b) Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes. (c) Includes loss on impairments and divestitures, net and other income, net. (d) Includes revenues, earnings from equity investments, other, net, less operating expenses, loss on impairments and divestitures, net, loss on impairments and divestitures of equity investments, net and other income, net, (e) 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 activity) not allocated to our reportable segments. We do not attribute interest and debt expense to any of our reportable business segments. Following is geographic information regarding the revenues and long-lived assets of our business (in millions): Year Ended December 31, 2018 2017 2016 Revenues from external customers U.S. $ 13,596 $ 13,073 $ 12,459 Canada 447 503 483 Mexico and other foreign 101 129 116 Total consolidated revenues from external customers $ 14,144 $ 13,705 $ 13,058 December 31, 2018 2017 2016 Long-term assets, excluding goodwill and other intangibles U.S. $ 47,468 $ 47,928 $ 49,125 Canada 748 3,071 2,399 Mexico and other foreign 83 80 82 Total consolidated long-lived assets $ 48,299 $ 51,079 $ 51,606

Litigation, Environmental and O

Litigation, Environmental and Other Contingencies (Notes)	12 Months Ended
	Dec. 31, 2018
Loss Contingency, Information about Litigation Matters [Abstract]
Litigation, Environmental and Other Contingencies	Litigation, Environmental and Other Contingencies 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 on our business, financial position, results of operations or dividends to our shareholders. 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 Proceedings FERC Rulemaking on Tax Cuts and Jobs Act for Jurisdictional Natural Gas Pipelines On March 15, 2018, FERC issued a notice of proposed rule-making (NOPR) which proposed a process to implement for ratemaking purposes the 2017 Tax Reform. The NOPR proposed that each regulated interstate natural gas pipeline make a mandatory filing (Form 501-G) to reflect, based upon certain required assumptions, the rate impact of the reduced statutory corporate tax rate, and in the case of master limited partnerships and other pass-through entities, the elimination of an income tax allowance and unspecified resulting treatment of accumulated deferred income tax (ADIT) in the cost of service. The NOPR also provided four options for regulated entities to consider: (1) make a limited filing under section 4 of the NGA to reduce rates for the impact of the 2017 Tax Reform; (2) commit to file a general section 4 rate case in the near future; (3) file an explanation why no rate change is needed, or (4) take no further action other than filing the required Form 501-G report. On July 18, 2018, FERC issued Order No. 849 (Final Rule) promulgating a final rule to implement the 2017 Tax Reform for jurisdictional natural gas pipelines. The Final Rule continues to require the regulated interstate pipelines to file the Form 501-G reflecting certain mandatory assumptions. The Final Rule also maintains substantially the same four options for regulated entities to implement the reduced corporate tax rate. The Final Rule clarifies that pass-through entities whose income consolidates up to a federal income tax paying entity are eligible for a tax allowance. It also clarifies that the required filing is a one-time informational filing and that FERC is not mandating any adjustment in rates as a function of complying with the Final Rule. Companies are also allowed to file an addendum which may reflect an income tax allowance, alternative capital structure and alternative equity returns. The Final Rule establishes a presumption that negotiated rate contracts should not be disturbed. Kinder Morgan filed for rehearing of the Final Rule, but also filed the required Form 501-G filings. We continue to believe any initial, downward rate pressure will be mitigated and spread out over multiple years given the procedural options presented in the Final Rule, the prospective nature of rate changes under section 5 of the NGA and the fact that the FERC affirmed its intention to respect negotiated rate contracts. Many of our transportation and storage services are rendered pursuant to negotiated rate agreements that, consistent with the Final Rule, will not be subject to adjustment due to changes in tax law. Also, many of our current transactions are provided at discounted rates that are below maximum tariff rates, many of which would not be impacted by a change in the maximum tariff rate. Further, on many of our pipelines we are operating under settlements that preclude customers from requesting rate changes at the FERC during the life of the settlement. SFPP The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the complaints and protests of various shippers, the most recent of which was filed in 2015 (docketed at OR16-6) challenging SFPP’s filed East Line rates. 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. If the shippers prevail on their arguments or claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing date of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. 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. On March 22, 2016, the D.C. Circuit issued a decision in United Airlines, Inc. v. FERC remanding to FERC for further consideration of two issues: (1) the appropriate data to be used to determine the return on equity for SFPP in the underlying docket, and (2) the just and reasonable return to be provided to a tax pass-through entity that includes an income tax allowance in its underlying cost of service. On July 21, 2017, an initial decision by the Administrative Law Judge (ALJ) in OR16-6 concluded that the Complainants are due reparations, with appropriate interest, equal to the difference between what SFPP collected from the Complainants for service on the East Line and the amounts SFPP would have collected had it charged just and reasonable rates for that line. The ALJ ruled that an income tax allowance should be included in the cost of service both to determine reparations and to set going forward rates, and found that the new just and reasonable rates are not knowable until the FERC reviews the initial decision and orders a compliance filing. The FERC will determine which portions of the initial decision to affirm, reject or amend. On March 15, 2018, the FERC announced certain policy changes including a Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and, that same day, the FERC issued orders in a series of pending SFPP proceedings which combined to deny income tax allowance to SFPP, direct SFPP to make compliance filings in its 2008 and 2009 rate filing dockets, and restart the 2011 SFPP complaint proceeding which had been abated. Requests for rehearing were filed in the Revised Policy Statement docket as well as the SFPP dockets in which the Revised Policy Statement was applied. The requests for rehearing in the SFPP dockets remain pending at the FERC. On July 18, 2018, the FERC issued an Order on Rehearing in the Revised Policy Statement docket in which it denied the rehearing petitions and clarified that the issue of entitlement to an income tax allowance will continue to be resolved in individual proceedings, including proceedings involving income tax pass-through entities. The FERC also clarified that when an income tax allowance is eliminated from cost of service, previously ADIT balances associated with such income tax allowance may also be eliminated. SFPP along with another pipeline entity appealed the Revised Policy Statement along with the Order on Rehearing to the D.C. Circuit. With respect to the various SFPP related complaints and protest proceedings at the FERC, we estimate that the shippers are seeking approximately $30 million in annual rate reductions and approximately $330 million in refunds. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. However, to the extent the shippers are successful in one or more of the complaints or protest proceedings, SFPP estimates that applying the principles of FERC precedent, as applicable, to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers. EPNG The tariffs and rates charged by EPNG are subject to two ongoing 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 it will apply its findings in Opinion 517-A to the same issues in the 2010 rate case. All refund obligations related to the 2008 rate case were satisfied during calendar year 2015. EPNG sought federal appellate review of Opinion 517-A and oral arguments were held on February 15, 2017. On February 21, 2017, the reviewing court delayed the case until the FERC rules on the rehearing requests pending in the 2010 Rate Case. 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 the terms of 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 the refund calculations, and 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. On August 23, 2018, the reviewing court established a briefing schedule and consolidated EPNG’s delayed appeal from the 2008 rate case, EPNG’s appeal from the 2010 rate case, and the intervenors’ delayed appeal in the 2010 case. In accordance with that schedule, EPNG and the intervenors filed their initial briefs on January 8, 2019. Other Commercial Matters Union Pacific Railroad Company Easements Landowner Litigation A purported class action lawsuit was filed in 2015 in a U.S. District Court in California against Union Pacific Railroad Company (UPRR), SFPP, KMGP and Kinder Morgan Operating L.P. “D” by private landowners who claimed to be the lawful owners of subsurface real property allegedly used or occupied by UPRR or SFPP for pipeline easements on rights-of-way held by UPRR. Substantially similar follow-on lawsuits were filed in federal courts by landowners in Nevada, Arizona and New Mexico. These suits, which were brought purportedly as class actions on behalf of all landowners who own land in fee adjacent to and underlying the railroad easement under which the SFPP pipeline is located in those respective states, asserted claims alleging that the defendants’ occupation and use of the subsurface real property was improper. Plaintiffs’ motions for class certification were denied by the federal courts in Arizona and California. The Ninth Circuit Court of Appeals denied interlocutory review of the class certification decisions, and the New Mexico and Nevada lawsuits were stayed. All pending lawsuits have now been settled or dismissed on terms that are not material to KMI’s results of operations, cash flows or dividends to shareholders. Gulf LNG Facility Arbitration On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Disagreement and Disputed Statements and 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. A three-member arbitration panel conducted an arbitration hearing in January 2017. On June 29, 2018, the arbitration panel delivered its Award, and the panel's ruling calls 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 September 25, 2018, GLNG filed a lawsuit against Eni USA in the Delaware Court of Chancery to enforce the Award. On February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award. 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 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. GLNG intends to vigorously prosecute and defend both lawsuits. Brinckerhoff Merger Litigation In April 2017, a purported class action suit was filed in the Delaware Court of Chancery by Peter Brinckerhoff, a former EPB unitholder on behalf of a class of former unaffiliated unitholders of EPB, seeking to challenge the $9.2 billion merger of EPB into a subsidiary of KMI as part of a series of transactions in November 2014 whereby KMI acquired all of the outstanding equity interests in KMP, Kinder Morgan Management, LLC and EPB that KMI and its subsidiaries did not already own. The suit alleged that the merger consideration did not sufficiently compensate EPB unitholders for the value of three derivative suits concerning drop down transactions which the derivative plaintiff lost standing to pursue after the merger. The suit claimed that the alleged failure to obtain sufficient merger consideration for the drop down lawsuits constituted a breach of the EPB limited partnership agreement and the implied covenant of good faith and fair dealing. The suit also asserted claims against KMI and certain individual defendants for allegedly tortiously interfering with and/or aiding and abetting the alleged breach of the limited partnership agreement. In November 2017, the Court dismissed the suit in its entirety. On June 8, 2018, the Delaware Supreme Court affirmed the dismissal. Also in November 2017, counsel for Brinckerhoff filed a separate lawsuit against KMEP and KMI seeking to recover up to $44 million in attorneys’ fees allegedly incurred in connection with the assertion of derivative claims that Brinckerhoff lost standing to pursue. On April 9, 2018, the Court dismissed the suit in its entirety, and that dismissal is final. Price Reporting Litigation Beginning in 2003, several lawsuits were filed by purchasers of natural gas against El Paso Corporation, El Paso Marketing L.P. and numerous other energy companies based on a claim under state antitrust law that such defendants conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Several of the cases were previously settled or dismissed, except for two cases pending in a U.S. District Court in Nevada, including a lawsuit brought by an industrial consumer in Kansas in which approximately $500 million in damages plus interest was alleged against all defendants, and a Wisconsin class action in which approximately $300 million in damages plus interest has been alleged against all defendants. The Kansas case has now been settled, and a settlement in principal has been reached in the Wisconsin class action that will require class notice and court approval in 2019. The amount to be paid in settlement of these matters is not material to our results of operations, cash flows or dividends to shareholders. 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, 2018 and 2017 , our total reserve for legal matters was $207 million and $350 million , respectively. The reduction in the reserve primarily resulted from the payment of refunds in the EPNG rate case matter discussed above in “— FERC Proceedings — EPNG.” The remaining reserve primarily relates to various claims from regulatory proceedings arising in our Products Pipelines business segment. 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 federal, state and local 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, 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, could result in substantial costs and liabilities to us. We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations, including alleged violations of the Risk Management Program and leak detection and repair requirements of the Clean Air Act. 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, individually or in the aggregate, will be material. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the remediation. In addition, we are involved with and have been identified as a potentially responsible party 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 and CO 2 . Portland Harbor Superfund Site, Willamette River, Portland, Oregon In December 2000, the EPA issued General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). At that time, GATX owned two liquids terminals along the lower reach of the Willamette River, an industrialized area known as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-voting member. The LWG agreed to conduct the remedial investigation and feasibility study (RI/FS) leading to the proposed remedy for cleanup of the Portland Harbor site. The EPA issued the FS and the Proposed Plan on June 8, 2016 which included a proposed combination of dredging, capping, and enhanced natural recovery. On January 6, 2017, the EPA issued its Record of Decision (ROD) for the final cleanup plan. The final remedy is more stringent than the remedy proposed in the EPA’s Proposed Plan. The estimated cost increased from approximately $750 million to approximately $1.1 billion , and active cleanup is now expected to take as long as 13 years to complete. KMLT and 90 other parties are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs. We are participating in the allocation process on behalf of KMLT and KMBT in connection with their current or former ownership or operation of four facilities located in Portland Harbor. Our share of responsibility for Portland Harbor Superfund Site costs will not be determined until the ongoing non-judicial allocation process is concluded in several years 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 site. 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 site. At this time, we are unable to reasonably estimate the extent of our potential NRD liability. Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P., U.S. District Court, Arizona The Roosevelt Irrigation District filed a lawsuit in 2010 against KMGP, KMEP and others under CERCLA for alleged contamination of the water purveyor’s wells. The First Amended Complaint sought $175 million in damages from approximately 70 defendants. KMGP was dismissed from the suit. On August 6, 2013, plaintiffs filed their Second Amended Complaint seeking monetary damages in unspecified amounts and reducing the number of defendants to 26 including KMEP and SFPP. The claims against KMEP and SFPP were related to alleged releases from a specific parcel within the SFPP Phoenix Terminal and the alleged impact of such releases on water wells owned by the plaintiffs and located in the vicinity of the Terminal. During the first quarter of 2018, KMEP and SFPP settled all claims made by the Roosevelt Irrigation District on terms that are not material to KMI’s results of operations, cash flows or dividends to shareholders. Uranium Mines in Vicinity of Cameron, Arizona In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately twenty 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 potentially responsible party 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 a radiological assessment of the surface 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, given the U.S. is the owner of the Navajo Reservation, the U.S.’s exploration and reclamation activities at the mines, and the pervasive control of such federal agencies over all aspects of the nuclear weapons program. Defendants filed an answer and counterclaims seeking contribution and recovery of response costs allegedly incurred by the federal agencies in investigating uranium impacts on the Navajo Reservation. The counterclaim of defendant EPA has been settled, and no viable claims for reimbursement by the other defendants are known to exist. In August 2017, the District Court found the U.S. liable under CERCLA as owner of the Navajo Reservation. The matter seeking cost recovery and contribution from federal government agencies is set for trial in February 2019. We intend to continue to prosecute and defend this case vigorously. Lower Passaic River Study Area of the Diamond Alkali Superfund Site, Essex, Hudson, Bergen and Passaic Counties, 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 Superfund Site (Site) concerning the lower 17 -mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be potentially responsible parties (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) 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 has entered into AOCs and is directing and funding the work required by the EPA. Under the first AOC, draft remedial investigation and feasibility studies (RI/FS) of the Site were submitted to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG members conducted a CERCLA removal action at the Passaic River Mile 10.9, and the group is currently conducting EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with the AOCs. On April 11, 2014, the EPA announced the issuance of its Focused Feasibility Study (FFS) for the lower eight miles of the Passaic River Study Area, and its proposed plan for remedial alternatives to address the dioxin sediment contamination from the mouth of Newark Bay to River Mile 8.3. The EPA estimates the cost for the alternatives will range from $365 million to $3.2 billion . The EPA’s preferred alternative would involve dredging the river bank-to-bank and installing an engineered cap at an estimated cost of $1.7 billion . On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Passaic River Study area. The final cleanup plan in the ROD is substantially similar to the EPA’s preferred alternative announced on April 11, 2014. 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 Passaic River. The design work is expected to take four years to complete and the cleanup is expected to take six years to complete. On June 30, 2018 and July 13, 2018, respectively, OCC filed two separate lawsuits in the U.S. District Court for the District of New Jersey seeking cost recovery and contribution under CERCLA from more than 120 defendants, including EPEC Polymers. OCC alleges that each defendant is responsible to reimburse OCC for a proportionate share of the $165 million OCC is required to spend pursuant to its AOC. EPEC Polymers was dismissed without prejudice from the lawsuit on August 8, 2018. 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 Passaic River Study area. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the FFS and ROD. There is also uncertainty as to the impact of the recent EPA FS directive for the upper nine mile segment not subject to the lower eight mile FFS and 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 this FS is completed and the RI/FS is finalized and allocations are determined, the scope of potential EPA claims for the Site and liability therefor are not reasonably estimable. Plaquemines Parish Louisiana Coastal Zone Litigation 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 defendants’ oil and gas exploration, production and transportation operations in the Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish, including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal Zone Management Act). The case is one of numerous similar cases pending in Louisiana. As a result of such alleged violations of the Coastal Zone Management Act, Plaquemines Parish seeks, among other relief, unspecified monetary relief, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxify the Coastal Zone. In connection with this suit, TGP made two tenders for defense and indemnity: (1) to Anadarko, as successor to the entity that purchased TGP’s oil and gas assets in Bastian Bay, and (2) to Kinetica, which purchased TGP’s pipeline assets in Bastian Bay in 2013. Anadarko accepted TGP’s tender (limited to oil and gas assets), and Kinetica rejected TGP’s tender. The Louisiana Department of Natural Resources (LDNR) and the Louisiana Attorney General (LAG) intervened in the lawsuit. The Court separated the defendants into several trial groups and set trials to begin in 2019. The case involving TGP was set for trial in 2020. During May 2018, the defendants removed numerous cases which allege violations under the Coastal Zone Management Act to federal court in Louisiana; the case involving TGP was removed to the U.S. District Court for the Eastern District of Louisiana. Thereafter, the defendants moved the U.S. Judicial Panel on Multidistrict Litigation to transfer all such cases, including the case involving TGP, to the U.S. District Court for the Eastern District of Louisiana for coordinated proceedings. On July 31, 2018, the Panel denied the motion. The plaintiffs and intervenors moved to remand all of the cases, including the case involving TGP, to the state district courts. Those motions are pending. All of the cases, including the case involving TGP, remain effectively stayed pending resolution of the removal and remand issues. We will continue to vigorously defend the lawsuit. Vintage Assets, Inc. Coastal Erosion Litigation On December 18, 2015, Vintage Assets, Inc. and several individual landowners filed a lawsuit in the State District Court f

Recent Accounting Pronoucements

Recent Accounting Pronoucements (Notes)	12 Months Ended
	Dec. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Recent Accounting Pronouncements Accounting Standards Updates Topic 842 On February 25, 2016, the FASB issued ASU No. 2016-02, “ Leases ” followed by a series of related accounting standard updates (collectively referred to as “Topic 842”). Topic 842 establishes a new lease accounting model for leases. The most significant changes include the clarification of the definition of a lease, the requirement for lessees to recognize for all leases a right-of-use asset and a lease liability in the consolidated balance sheet, and additional quantitative and qualitative disclosures which are designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. Expenses are recognized in the consolidated statement of income in a manner similar to current accounting guidance. Lessor accounting under the new standard is substantially unchanged. The new standard will become effective for us beginning with the first quarter 2019. We will adopt the accounting standard using a prospective transition approach, which applies the provisions of the new guidance at the effective date without adjusting the comparative periods presented. We have elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows us to carry forward the historical accounting relating to lease identification and classification for existing leases upon adoption. We have also elected the optional practical expedient permitted under the transition guidance within the new standard related to land easements that allows us to carry forward our historical accounting treatment for land easements on existing agreements upon adoption. We have made an accounting policy election to keep leases with an initial term of 12 months or less off of the consolidated balance sheet. We are finalizing our evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements, and estimate approximately $500 million of additional right-of-use assets and liabilities will be recognized in our consolidated balance sheet upon adoption. ASU No. 2016-13 On June 16, 2016, the FASB issued ASU No. 2016-13, “ Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments .” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. ASU No. 2016-13 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements. ASU No. 2017-04 On January 26, 2017, the FASB issued ASU No. 2017-04, “ Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. ” This ASU simplifies the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. Goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU No. 2017-04 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements. ASU No. 2017-12 On August 28, 2017, the FASB issued ASU No. 2017-12, “ Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities .” This ASU better aligns an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirement to separately measure and report hedge ineffectiveness, and eases certain hedge effectiveness assessment requirements. ASU No. 2017-12 was effective January 1, 2019. We adopted ASU No. 2017-12 with no material impact to our financial statements. ASU No. 2018-13 On August 28, 2018, the FASB issued ASU No. 2018-13, “ Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU amends existing fair value measurement disclosure requirements by adding, changing, or removing certain disclosures. ASU No. 2018-13 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements. ASU No. 2018-14 On August 28, 2018, the FASB issued ASU No. 2018-14, “ Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans .” This ASU amends existing annual disclosure requirements applicable to all employers that sponsor defined benefit pension and other postretirement plans by adding, removing, and clarifying certain disclosures. ASU No. 2018-14 will be effective for us for the fiscal year ending December 31, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

Guarantee of Securities of Subs

Guarantee of Securities of Subsidiaries (Notes)	12 Months Ended
	Dec. 31, 2018
Guarantee of Securities of Subsidiaries [Abstract]
Guarantees [Text Block]	Guarantee of Securities of Subsidiaries KMI, along with its direct subsidiary KMP, are issuers of certain public debt securities. KMI, KMP and substantially all of KMI’s wholly owned domestic subsidiaries, are parties 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. Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the parent issuer, subsidiary issuer and other subsidiaries are all guarantors of each series of public debt. As a result of the cross guarantee agreement, a holder of any of the guaranteed public debt securities issued by KMI or KMP are in the same position with respect to the net assets, income and cash flows of KMI and the Subsidiary Issuer and Guarantors. The only amounts that are not available to the holders of each of the guaranteed public debt securities to satisfy the repayment of such securities are the net assets, income and cash flows of the Subsidiary Non-Guarantors. In lieu of providing separate financial statements for subsidiary issuer and guarantor, we have included the accompanying condensed consolidating financial statements based on Rule 3-10 of the SEC’s Regulation S-X. We have presented each of the parent and subsidiary issuer in separate columns in this single set of condensed consolidating financial statements. Excluding fair value adjustments, as of December 31, 2018, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $15,192 million , $17,910 million , and $2,535 million of Guaranteed Notes outstanding, respectively. Included in the Subsidiary Guarantors debt balance as presented in the accompanying December 31, 2018 condensed consolidating balance sheet are approximately $159 million of capitalized lease debt that is not subject to the cross guarantee agreement. The accounts within the Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Guarantors and Subsidiary Non-Guarantors are presented using the equity method of accounting for investments in subsidiaries, including subsidiaries that are guarantors and non-guarantors, for purposes of these condensed consolidating financial statements only. These intercompany investments and related activity eliminate in consolidation and are presented separately in the accompanying condensed consolidating balance sheets and statements of income and cash flows. A significant amount of each Issuers’ income and cash flow is generated by its respective subsidiaries. As a result, the funds necessary to meet its debt service and/or guarantee obligations are provided in large part by distributions or advances it receives from its respective subsidiaries. We utilize a centralized cash pooling program among our majority-owned and consolidated subsidiaries, including the Subsidiary Issuers and Guarantors and Subsidiary Non-Guarantors. The following Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [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. Adoption of New Accounting Pronouncements On January 1, 2018, we adopted Accounting Standards Updates (ASU) No. 2014-09, “ Revenue from Contracts with Customers ” and a series of related accounting standard updates designed to create improved revenue recognition and disclosure comparability in financial statements. For more information, see “— Revenue Recognition ” below and Note 16. On January 1, 2018, we retroactively adopted ASU No. 2016-18, “ Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force). ” This ASU requires the statements of cash flows to present the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are now included with cash and cash equivalents when reconciling the beginning of period and end of period amounts presented on the statements of cash flows. The retrospective application of this new accounting guidance resulted in an increase of $41 million and a decrease of $43 million in “Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits”, no change and a decrease of $37 million in “Accrued contingencies and other current liabilities” in Cash Flows from Operating Activities, and a decrease of $41 million and an increase of $80 million in “Other, net” in Cash Flows from Investing Activities in our accompanying consolidated statement of cash flows for the years ended December 31, 2017 and 2016, respectively, from what was previously presented in our Annual Report on Form 10-K for the year ended December 31, 2017. 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 and other insurance subsidiaries, and cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions. 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 “Retained deficit” balance. The cumulative effect of the adoption of this ASU was a $66 million , net of income taxes, adjustment to our “Retained deficit” balance as presented in our consolidated statement of stockholders’ equity for the year ended December 31, 2018. This ASU also requires 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 sheet as of December 31, 2018, as EIG has the right under certain conditions to redeem their interests for cash. The December 31, 2017 balance of $485 million is included in “Other long-term liabilities and deferred credits” on our consolidated balance sheet as of December 31, 2017. On January 1, 2018, we adopted ASU No. 2017-07, “ Compensation - Retirement Benefits (Topic 715) .” This ASU requires an employer to disaggregate the service cost component from the other components of net benefit cost, allows only the service cost component of net benefit cost to be eligible for capitalization and establishes how to present the service cost component and the other components of net benefit cost in the income statement. Topic 715 required us to retrospectively reclassify $15 million and $34 million of other components of net benefit credits (excluding the service cost component) from “General and administrative” to “Other, net” in our accompanying consolidated statements of income for the years ended December 31, 2017 and 2016, respectively. We prospectively applied Topic 715 related to net benefit costs eligible for capitalization. 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 “Retained deficit” on our consolidated statement of stockholders’ equity for the year ended December 31, 2018.
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. Restricted deposits were $51 million and $62 million as of December 31, 2018 and 2017 , respectively.
Accounts Receivable, net	Accounts Receivable, net The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of December 31, 2018 and 2017 primarily consist of amounts due from customers net of the allowance for doubtful accounts. Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. Generally, we make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and we record adjustments as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. The allowance for doubtful accounts was $3 million and $35 million as of December 31, 2018 and 2017 , respectively.
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 1.01% to 23.0% 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 bulk and liquids 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. In those 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.
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 bulk and liquids 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 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 total proved and risk-adjusted probable reserves. 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 total proved and risk-adjusted probable and possible reserves or, if available, comparable market values. 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.
Equity Method of Accounting and Excess Investment Cost	Equity Method of Accounting and Excess Investment Cost We account for investments which we do not control, but do have the ability to exercise significant influence using the equity method of accounting. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. With regard to our equity investments in unconsolidated affiliates, in almost all cases, either (i) the price we paid to acquire our share of the net assets of such equity investees or (ii) the revaluation of our share of the net assets of any retained noncontrolling equity investment (from the sale of a portion of our ownership interest in a consolidated subsidiary, thereby losing our controlling financial interest in the subsidiary) differed from the underlying carrying value of such net assets. This differential consists of two pieces. First, an amount related to the difference between the investee’s recognized net assets at book value and at current fair values (representing the appreciated value in plant and other net assets), and secondly, to any premium in excess of fair value (referred to as equity method goodwill) we paid to acquire the investment. We include both amounts within “Investments” on our accompanying consolidated balance sheets. The first differential, representing the excess of the fair market value of our investees’ plant and other net assets over its underlying book value at either the date of acquisition or the date of the loss of control totaled $470 million and $732 million as of December 31, 2018 and 2017 , respectively. Generally, this basis difference relates to our share of the underlying depreciable assets, and, as such, we amortize this portion of our investment cost against our share of investee earnings. As of December 31, 2018 , this excess investment cost is being amortized over a weighted average life of approximately twelve years. The second differential, representing equity method goodwill, totaled $1,967 million for both periods as of December 31, 2018 and 2017 . This differential is not subject to amortization but rather to impairment testing as part of our periodic evaluation of the recoverability of our investment as compared to the fair value of net assets accounted for under the equity method. Our impairment test considers whether the fair value of the equity investment as a whole has declined and whether that decline is other than temporary.
Goodwill	Goodwill Goodwill is the cost of an acquisition 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. This test requires us to assign goodwill to an appropriate reporting unit and to determine if the implied fair value of the reporting unit’s goodwill is less than its carrying amount. We evaluate goodwill for impairment on May 31 of each year. For this purpose, prior to the TMPL Sale we had seven 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 ; (vi) Terminals; and (vii) Kinder Morgan Canada. Subsequent to the TMPL Sale, Kinder Morgan Canada is no longer a reporting unit. We also evaluate goodwill for impairment to the extent events or conditions indicate a risk of possible impairment during the interim periods subsequent to our annual impairment test. Generally, the evaluation of goodwill for impairment involves a two-step test, although under certain circumstance an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test. Step 1 involves comparing the estimated fair value of each respective reporting unit to its carrying value, including goodwill. If the estimated fair value exceeds the carrying value, the reporting unit’s goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, step 2 must be performed to determine whether goodwill is impaired and, if so, the amount of the impairment. Step 2 involves 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 is then compared to the actual carrying amount of the goodwill for the reporting unit. To the extent the carrying amount of goodwill exceeds the implied goodwill, the difference is 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, 2018 and 2017 , the gross carrying amounts of these intangible assets was $4,305 million and the accumulated amortization was $1,425 million and $1,206 million , respectively, resulting in net carrying amounts of $2,880 million and $3,099 million , respectively. These intangible assets primarily consisted of customer contracts, relationships and agreements associated with our Natural Gas Pipelines and Terminals 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, 2018 , 2017 and 2016 , the amortization expense on our intangibles totaled $219 million , $220 million and $223 million , respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2019 – 2023) is approximately $213 million , $209 million , $209 million , $207 million , and $203 million , respectively. As of December 31, 2018 , the weighted average amortization period for our intangible assets was approximately fifteen years .
Revenue Recognition	Revenue Recognition Revenue from Contracts with Customers Beginning in 2018, we account for revenue from contracts with customers in accordance with Accounting Standards Updates ASU No. 2014-09, “ Revenue from Contracts with Customers ” and a series of related accounting standard updates (Topic 606). The unit of account in Topic 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. Topic 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) control of the goods or services transfers to the customer and the performance obligation is satisfied. 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). Refer to Note 16 for further information. Revenue Recognition Policy prior to January 1, 2018 Prior to the implementation of Topic 606, we recognized revenue as services were rendered or goods were delivered and, if applicable, risk of loss had passed. We recognized natural gas, crude and NGL sales revenue when the commodity was sold to a purchaser at a fixed or determinable price, delivery had occurred and risk of loss had transferred, and collectability of the revenue was reasonably assured. Our sales and purchases of natural gas, crude and NGL were primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales, except in circumstances where we solely acted as an agent and did not have price and related risk of ownership, in which case we recognized revenue on a net basis. For revenues associated with our firm services as previously described, the fixed-fee component of the overall rate was recognized as revenue in the period the service was provided. The per-unit charge was recognized as revenue when the volumes were delivered to the customers’ agreed upon delivery point, or when the volumes were injected into/withdrawn from our storage facilities. Revenues associated with our non-firm services as previously described, were recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. Revenues associated with our crude oil and refined petroleum products transportation and storage services were recorded when products were delivered and services had been provided, and adjusted according to terms prescribed by the toll settlements with shippers and approved by regulatory authorities. We recognized bulk terminal transfer service revenues based on volumes loaded and unloaded. We recognized liquids terminal tank rental revenue ratably over the contract period. We recognized liquids terminal throughput revenue based on volumes received and volumes delivered. We recognized transmix processing revenues based on volumes processed or sold, and if applicable, when risk of loss had passed. We recognized energy-related product sales revenues based on delivered quantities of product. Revenues from the sale of crude oil, NGL, CO2 and natural gas production within the CO2 business segment were recorded using the entitlement method, under which revenue was recorded when title passed based on our net interest. We recorded our entitled share of revenues based on entitled volumes and contracted sales prices. Since there was a ready market for oil and gas production, we sold the majority of our products soon after production at various locations, at which time title and risk of loss had passed to the buyer.
Cost of Sales	Cost of Sales Cost of sales primarily includes the cost of energy commodities sold, including natural gas, NGL and other refined petroleum products, adjusted for the effects of our energy commodity activities, as applicable, other than production from our CO 2 business segment.
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 oil, gas and CO 2 producing activities included within operations and maintenance totaled $363 million , $342 million and $349 million for the years ended December 31, 2018 , 2017 and 2016 , respectively.
Environmental Matters	Environmental Matters We capitalize or expense, as appropriate, environmental expenditures. We capitalize certain environmental expenditures required in obtaining rights-of-way, regulatory approvals or permitting as part of the construction. 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 recording of these accruals coincides with 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. 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.
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 sheet. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—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.
Noncontrolling Interests	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 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.
Foreign Currency Transactions and Translation	Foreign Currency Transactions and Translation Foreign currency transaction gains or losses result from a change in exchange rates between (i) the functional currency, for example the Canadian dollar for a Canadian subsidiary and (ii) the currency in which a foreign currency transaction is denominated, for example the U.S. dollar for a Canadian subsidiary. In our accompanying consolidated statements of income, gains and losses from our foreign currency transactions are included within “Other Income (Expense)—Other, net.” Foreign currency translation is the process of expressing, in U.S. dollars, amounts recorded in a local functional currency other than U.S. dollars, for example the Canadian dollar for a Canadian subsidiary. We translate the assets and liabilities of each of our consolidated foreign subsidiaries that have a local functional currency to U.S. dollars at year-end exchange rates. Income and expense items are translated at weighted-average rates of exchange prevailing during the year and stockholders’ equity accounts are translated by using historical exchange rates. The cumulative translation adjustments balance is reported as a component of “Accumulated other comprehensive loss.”
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 natural gas, NGL and crude oil. 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 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, and how any ineffectiveness will be measured and recorded. If we designate a derivative contract as a cash flow accounting hedge, the effective portion of the change in fair value of the derivative is deferred in “Accumulated other comprehensive loss” and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value or amount excluded from the assessment of hedge effectiveness is recognized currently in earnings. If we designate a derivative contract as a fair value accounting hedge, the effective portion of the change in fair value of the derivative is recorded as an adjustment to the item being hedged. Any ineffective portion of the derivative’s change in fair value is recognized currently in earnings. If we designate a derivative contract as a net investment accounting hedge, the effective portion of the change in fair value of the derivative is reflected in the Cumulative Translation Adjustment (CTA) section of Other Comprehensive Income (OCI) 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.
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 refunded to customers through the ratemaking process. We included 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 Income Tax (Polici

Income Taxes Income Tax (Policies)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Tax Uncertainties, Policy [Policy Text Block]	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, 2018
Organization, Consolidation and Presentation of Financial Statements [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, 2018 and 2017 (in millions): December 31, 2018 2017 Current regulatory assets $ 66 $ 60 Non-current regulatory assets 245 288 Total regulatory assets(a) $ 311 $ 348 Current regulatory liabilities $ 29 $ 107 Non-current regulatory liabilities 206 236 Total regulatory liabilities(b) $ 235 $ 343 _______ (a) Regulatory assets as of December 31, 2018 include (i) $176 million of unamortized losses on disposal of assets; (ii) $53 million income tax gross up on equity AFUDC; and (iii) $82 million of other assets including amounts related to fuel tracker arrangements. Approximately $98 million of the regulatory assets, with a weighted average remaining recovery period of 23 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, 2018 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 $136 million of the $206 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 18 years , while the remaining $70 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 (in millions): Year Ended December 31, 2018 2017 2016 Net Income Available to Common Stockholders $ 1,481 $ 27 $ 552 Participating securities: Less: Net Income Allocated to Restricted stock awards(a) (8 ) (5 ) (4 ) Net Income Allocated to Class P Stockholders $ 1,473 $ 22 $ 548 Basic Weighted Average Common Shares Outstanding 2,216 2,230 2,230 Basic Earnings Per Common Share $ 0.66 $ 0.01 $ 0.25 _______ (a) As of December 31, 2018 , there were approximately 13 million such restricted stock awards.
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 (in millions on a weighted average basis): Year Ended December 31, 2018 2017 2016 Unvested restricted stock awards 12 10 8 Warrants to purchase our Class P shares(a) 116 293 Convertible trust preferred securities 3 3 8 Mandatory convertible preferred stock(b) 48 58 58 _______ (a) On May 25, 2017, approximately 293 million of unexercised warrants expired without the issuance of Class P common stock. Prior to expiration, each warrant entitled the holder to purchase one share of our common stock for an exercise price of $40 per share. The potential dilutive effect of the warrants did not consider the assumed proceeds to KMI upon exercise. (b) 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.

(Tables)

(Tables)	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Schedule of Variable Interest Entities	The following table shows the carrying amount and classification of KMC LP’s assets and liabilities in our consolidated balance sheet (in millions): December 31, 2018 2017 Assets Total current assets 3,204 $ 270 Property, plant and equipment, net 719 2,956 Total goodwill, deferred charges and other assets 8 322 Total assets $ 3,931 $ 3,548 Liabilities Current portion of debt — $ — Total other current liabilities 2,353 236 Long-term debt, excluding current maturities — — Total other long-term liabilities and deferred credits 52 414 Total liabilities $ 2,405 $ 650

Impairments (Tables)

Impairments (Tables)	12 Months Ended
	Dec. 31, 2018
Impairments [Abstract]
Impairment of Goodwill, Long-lived assets and equity investments [Table Text Block]	We recognized the following non-cash pre-tax impairment charges and losses (gains) on divestitures of assets (in millions): Year Ended December 31, 2018 2017 2016 Natural Gas Pipelines Impairments of long-lived assets(a) $ 600 $ 30 $ 106 (Gains) losses on divestitures of long-lived assets(b) (6 ) — 94 Impairment of equity investments(c) 270 150 606 Impairment at equity investee(d) — 10 7 Products Pipelines Impairments of long-lived assets(e) 36 — 66 Losses on divestitures of long-lived assets — — 10 Gain on divestiture of equity investment — — (12 ) Terminals Impairments of long-lived assets(f) 59 3 19 (Gains) losses on divestitures of long-lived assets(g) (6 ) (18 ) 80 Losses on impairments and divestitures of equity investments, net — — 16 CO 2 Impairments of long-lived assets(h) 79 (1 ) 20 Gain on divestitures of long-lived assets — — (1 ) Impairment at equity investee — (4 ) 9 Kinder Morgan Canada Gain on divestiture of long-lived assets(i) (595 ) — — Other losses (gains) on divestitures of long-lived assets — 2 (7 ) Pre-tax losses on impairments and divestitures, net $ 437 $ 172 $ 1,013 _______ (a) 2018 amount represents the non-cash impairment associated with certain gathering and processing assets in Oklahoma. 2017 amount represents the impairment of our Colden storage facility, of which $3 million is included in “Costs of sales” on our accompanying consolidated statement of income. 2016 amount represents the project write-off of our portion of the Northeast Energy Direct Market project. (b) 2016 amount primarily relates to our sale of a 50% interest in SNG. (c) 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. 2017 amount represents the non-cash impairment of our investment in FEP. 2016 amount includes a $350 million non-cash impairment of our investment in MEP and a $250 million non-cash impairment of our investment in Ruby. (d) 2017 and 2016 amounts represent losses on impairments recorded by equity investees and are included in “Earnings from equity investments” on our accompanying consolidated statements of income. (e) 2018 amount represents a project write-off associated with the Utica Marcellus Texas pipeline. 2016 amount represents project write-offs associated with the canceled Palmetto project. (f) 2018 amount primarily relates to non-cash impairments of certain Northeast terminal assets. (g) 2017 amount includes a $23 million gain related to the sale of a 40% membership interest in the Deeprock Development joint venture. 2016 amount primarily relates to the sale of 20 bulk terminals that handle mostly coal and steel products, predominately located along the inland river system. (h) 2018 amount represents impairments of oil and gas properties. (i) 2018 amount represents the gain on the TMPL Sale. 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. These reduced estimates triggered an impairment analysis 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.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of Income before Income Tax, Domestic and Foreign [Table Text Block]	The components of “Income Before Income Taxes” are as follows (in millions): Year Ended December 31, 2018 2017 2016 U.S. $ 1,739 $ 1,976 $ 1,466 Foreign 767 185 172 Total Income Before Income Taxes $ 2,506 $ 2,161 $ 1,638
Schedule of Components of Income Tax Expense (Benefit)	Components of the income tax provision applicable for federal, foreign and state taxes are as follows (in millions): Year Ended December 31, 2018 2017 2016 Current tax expense (benefit) Federal $ (22 ) $ (137 ) $ (148 ) State (45 ) (16 ) (28 ) Foreign 249 18 6 Total 182 (135 ) (170 ) Deferred tax expense (benefit) Federal 425 2,022 998 State 55 4 51 Foreign (75 ) 47 38 Total 405 2,073 1,087 Total tax provision $ 587 $ 1,938 $ 917
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows (in millions, except percentages): Year Ended December 31, 2018 2017 2016 Federal income tax $ 526 21.0 % $ 756 35.0 % $ 573 35.0 % Increase (decrease) as a result of: State deferred tax rate change (7 ) (0.3 )% 10 0.5 % 11 0.7 % Taxes on foreign earnings, net of federal benefit 131 5.2 % 42 1.9 % 28 1.7 % Net effects of noncontrolling interests (65 ) (2.6 )% (14 ) (0.7 )% (4 ) (0.3 )% State income tax, net of federal benefit 46 1.8 % 38 1.8 % 26 1.6 % Dividend received deduction (31 ) (1.2 )% (56 ) (2.6 )% (48 ) (2.9 )% Adjustments to uncertain tax positions (47 ) (1.9 )% (12 ) (0.6 )% (23 ) (1.4 )% Valuation allowance on investment and tax credits 14 0.5 % 13 0.6 % 34 2.1 % Impact of the 2017 Tax Reform — — % 1,240 57.4 % — — % Nondeductible goodwill 58 2.3 % — — % 301 18.5 % General business credit (64 ) (2.6 )% (95 ) (4.4 )% — — % Other 26 1.2 % 16 0.8 % 19 1.1 % Total $ 587 23.4 % $ 1,938 89.7 % $ 917 56.1 %
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Deferred tax assets and liabilities result from the following (in millions): December 31, 2018 2017 Deferred tax assets Employee benefits $ 238 $ 251 Accrued expenses 76 73 Net operating loss, capital loss and tax credit carryforwards 1,526 1,113 Derivative instruments and interest rate and currency swaps 9 12 Debt fair value adjustment 33 37 Investments 177 968 Other — 6 Valuation allowances (178 ) (171 ) Total deferred tax assets 1,881 2,289 Deferred tax liabilities Property, plant and equipment 270 225 Other 45 20 Total deferred tax liabilities 315 245 Net deferred tax assets $ 1,566 $ 2,044
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows (in millions): Year Ended December 31, 2018 2017 2016 Balance at beginning of period $ 97 $ 122 $ 148 Additions based on current year tax positions 3 3 3 Additions based on prior year tax positions 7 — 7 Reductions based on prior year tax positions — — (1 ) Reductions based on settlements with taxing authority (73 ) (22 ) (26 ) Reductions due to lapse in statute of limitations — (2 ) (9 ) Impact of the 2017 Tax Reform — (4 ) — Balance at end of period $ 34 $ 97 $ 122

Property, Plant and Equipment_2

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	As of December 31, 2018 and 2017 , our property, plant and equipment, net consisted of the following (in millions): December 31, 2018 2017 Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 19,727 $ 20,157 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 24,392 24,152 Other(a) 5,447 5,570 Accumulated depreciation, depletion and amortization (15,359 ) (14,175 ) 34,207 35,704 Land and land rights-of-way 1,378 1,456 Construction work in process 2,312 2,995 Property, plant and equipment, net $ 37,897 $ 40,155 _______ (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, 2018
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. As of December 31, 2018 and 2017 , our investments consisted of the following (in millions): December 31, 2018 2017 Citrus Corporation $ 1,708 $ 1,698 SNG 1,536 1,495 Ruby 750 774 NGPL Holdings LLC 733 687 Gulf LNG Holdings Group, LLC 361 461 Plantation Pipe Line Company 344 331 Utopia Holding LLC 333 276 EagleHawk 299 314 Gulf Coast Express Pipeline LLC 240 — MEP 235 253 Red Cedar Gathering Company 191 187 Watco Companies, LLC 185 182 Double Eagle Pipeline LLC 140 149 Liberty Pipeline Group LLC 66 71 Bear Creek Storage 65 63 Sierrita Gas Pipeline LLC 55 55 Permian Highway Pipeline 45 — FEP 44 112 All others 151 190 Total investments $ 7,481 $ 7,298
Schedule of earnings from equity investments [Table Text Block]	Our earnings from equity investments were as follows (in millions): Year Ended December 31, 2018 2017 2016 Gulf LNG Holdings Group, LLC(a) $ 209 $ 47 $ 48 Citrus Corporation 169 108 102 SNG 141 77 58 NGPL Holdings LLC 66 10 12 FEP 55 53 51 Plantation Pipe Line Company 55 46 37 Cortez Pipeline Company(b) 36 44 24 MEP 31 38 40 Ruby 26 44 15 Watco Companies, LLC 21 19 25 Red Cedar Gathering Company(c) 18 14 24 Utopia Holding LLC 14 — — Double Eagle Pipeline LLC 10 7 5 Bear Creek Storage 9 8 2 EagleHawk 7 24 10 Liberty Pipeline Group LLC 7 9 11 Sierrita Gas Pipeline LLC 7 7 7 Gulf Coast Express LLC 2 — — All others 4 23 26 Total earnings from equity investments $ 887 $ 578 $ 497 Amortization of excess costs (95 ) (61 ) (59 ) _______ (a) 2018 amount includes our share of earnings recognized due to a ruling by an arbitration panel affecting a customer contract. (b) 2017 and 2016 amounts include $(4) million and $9 million , respectively, representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company. (c) 2017 amount includes non-cash impairment charges of $10 million (pre-tax) related to our investment.
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 (in millions; amounts represent 100% of investee financial information): Year Ended December 31, Income Statement 2018 2017 2016 Revenues $ 5,129 $ 4,703 $ 4,084 Costs and expenses 3,371 3,398 3,056 Net income $ 1,758 $ 1,305 $ 1,028 December 31, Balance Sheet 2018 2017 Current assets $ 1,496 $ 956 Non-current assets 23,396 22,344 Current liabilities 2,715 1,241 Non-current liabilities 9,555 10,605 Partners’/owners’ equity 12,622 11,454

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 are summarized by reporting unit as follows (in millions): Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated CO 2 Products Pipelines Products Pipelines Terminals Terminals Kinder Morgan Canada Total Historical Goodwill $ 15,892 $ 5,812 $ 1,528 $ 2,125 $ 221 $ 1,575 $ 562 $ 27,715 Accumulated impairment losses (1,643 ) (1,597 ) — (1,197 ) (70 ) (679 ) (377 ) (5,563 ) December 31, 2016 14,249 4,215 1,528 928 151 896 185 22,152 Currency translation — — — — — — 13 13 Divestitures(a) — — — — — (3 ) — (3 ) December 31, 2017 14,249 4,215 1,528 928 151 893 198 22,162 Currency translation — — — — — — (8 ) (8 ) Divestitures(b) — — — — — — (190 ) (190 ) Other — — — — — 1 — 1 December 31, 2018 $ 14,249 $ 4,215 $ 1,528 $ 928 $ 151 $ 894 $ — $ 21,965 _______ (a) 2017 includes $3 million related to certain terminal divestitures. (b) 2018 includes $190 million related to the TMPL Sale.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	The following table provides detail on the principal amount of our outstanding debt balances. The table amounts exclude all debt fair value adjustments, including debt discounts, premiums and issuance costs (in millions): December 31, 2018 2017 Credit facility and commercial paper borrowings(a) $ 433 $ 365 Corporate senior notes(b) 6.00%, due January 2018 — 750 7.00%, due February 2018 — 82 5.95%, due February 2018 — 975 7.25%, due June 2018 — 477 9.00%, due February 2019 500 500 2.65%, due February 2019 800 800 3.05%, due December 2019 1,500 1,500 6.85%, due February 2020 700 700 6.50%, due April 2020 535 535 5.30%, due September 2020 600 600 6.50%, due September 2020 349 349 5.00%, due February 2021 750 750 3.50%, due March 2021 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(c) 860 900 3.95%, due September 2022 1,000 1,000 3.15%, due January 2023 1,000 1,000 Floating rate, due January 2023 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(c) 573 600 6.67%, due November 2027 7 7 4.30%, due March 2028 1,250 — 7.25%, due March 2028 32 32 6.95%, due June 2028 31 31 8.05%, due October 2030 234 234 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 December 31, 2018 2017 5.625%, due September 2041 375 375 5.00%, due August 2042 625 625 4.70%, due November 2042 475 475 5.00%, due March 2043 700 700 5.50%, due March 2044 750 750 5.40%, due September 2044 550 550 5.55%, due June 2045 1,750 1,750 5.05%, due February 2046 800 800 5.20%, due March 2048 750 — 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 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 December 2035 409 421 Trust I Preferred Securities, 4.75%, due March 2028(d) 221 221 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(e) 100 100 Other miscellaneous debt(f) 250 278 Total debt – KMI and Subsidiaries 36,593 36,916 Less: Current portion of debt(g) 3,388 2,828 Total long-term debt – KMI and Subsidiaries(h) $ 33,205 $ 34,088 _______ (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) Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2018 exchange rate of 1.1467 U.S. dollars per Euro and at the December 31, 2017 exchange rate of 1.2005 U.S. dollars per Euro. As of December 31, 2018 and 2017 , the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in increases to our debt balance of $46 million and $86 million , respectively, related to the 1.50% series and increases of $30 million and $57 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 consolidated balance sheets. At the time of issuance, we entered into cross-currency swap agreements 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 ”). (d) Capital Trust I (Trust I), is a 100% -owned business trust that as of December 31, 2018 , 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% , carry a liquidation value of $50 per security plus accrued and unpaid distributions. The Trust I Preferred Securities outstanding as of December 31, 2018 are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; and (ii) $25.18 in cash without interest. We have the right to redeem these Trust I Preferred Securities at any time. (e) As of December 31, 2018 and 2017, KMGP had outstanding, 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057. Since August 18, 2012, dividends on the preferred stock accumulate at a floating rate of the 3-month LIBOR plus 3.8975% and are payable quarterly in arrears, when and if declared by KMGP’s board of directors, on February 18, May 18, August 18 and November 18 of each year, beginning November 18, 2012. The preferred stock has approval rights over a commencement of or filing of voluntary bankruptcy by KMP or its SFPP or Calnev subsidiaries. (f) Includes capital lease obligations with monthly installments. The lease terms expire between 2024 and 2061. (g) Amounts include KMI and KML outstanding credit facility borrowings, commercial paper borrowings and other debt maturing within 12 months. See “—Current Portion of Debt” below. (h) Excludes our “Debt fair value adjustments” which, as of December 31, 2018 and 2017 , increased our combined debt balances by $731 million and $927 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 [Table Text Block]	The following table details the components of our “Current portion of debt” reported on our consolidated balance sheets. December 31, 2018 2017 $500 million, 364-day credit facility due November 15, 2019(a) $ — $ — $4 billion credit facility due November 16, 2023(a) — — $5 billion, five-year credit facility due November 26, 2019, -% and 2.99%, respectively(a)(b) — 125 Commercial paper notes, 3.10% and 2.02%, respectively(b) 433 240 KML 2018 Credit Facility(c) — — Current portion of senior notes 6.00%, due January 2018 — 750 7.00%, due February 2018 — 82 5.95%, due February 2018 — 975 7.25%, due June 2018 — 477 9.00%, due February 2019 500 — 2.65%, due February 2019 800 — 3.05%, due December 2019 1,500 — Trust I Preferred Securities, 4.75%, due March 2028 111 111 Current portion - Other debt 44 68 Total current portion of debt $ 3,388 $ 2,828 _______ (a) On November 16, 2018, we replaced our $5 billion , five-year credit facility with two new credit facilities discussed further in “—Credit Facilities and Restrictive Covenants” following. (b) Interest rates are weighted average rates at December 31, 2018 and 2017, respectively. (c) Borrowings under the KML 2018 Credit Facility are denominated in C$ and are converted to U.S. dollars. The exchange rate was 0.7330 U.S. dollars per C$ at December 31, 2018 and 0.7971 U.S. dollars per C$ at December 31, 2017. See “—Credit Facilities” below.
Schedule of Maturities of Long-term Debt [Table Text Block]	The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2018 , are summarized as follows (in millions): Year Total 2019 $ 3,388 2020 2,205 2021 2,422 2022 2,518 2023 3,250 Thereafter 22,810 Total $ 36,593
Debt Fair Value Adjustments [Table Text Block]	The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets (in millions): December 31, Debt Fair Value Adjustments 2018 2017 Purchase accounting debt fair value adjustments $ 658 $ 719 Carrying value adjustment to hedged debt 2 115 Unamortized portion of proceeds received from the early termination of interest rate swap agreements 275 297 Unamortized debt discounts, net (74 ) (74 ) Unamortized debt issuance costs (130 ) (130 ) Total debt fair value adjustments $ 731 $ 927

Share-based Compensation and _2

Share-based Compensation and Employee Benefits (Tables)	12 Months Ended
	Dec. 31, 2018
Employee Benefits and Share-based Compensation, Noncash [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 (in millions, except share and per share amounts): Year Ended Year Ended Year Ended December 31, 2018 December 31, 2017 December 31, 2016 Shares Weighted Average Shares Weighted Average Shares Weighted Average Grant Date Fair Value per Share Outstanding at beginning of period 10,518,344 $ 28.21 9,038,137 $ 32.72 7,645,105 $ 37.91 Granted 5,389,476 17.73 3,221,691 19.52 2,816,599 21.36 Vested (2,371,193 ) 36.34 (1,501,939 ) 36.67 (1,226,652 ) 38.53 Forfeited (382,022 ) 23.26 (239,545 ) 28.34 (196,915 ) 35.74 Outstanding at end of period 13,154,605 22.59 10,518,344 28.21 9,038,137 32.72
Summary of Future Vesting of Outstanding Restricted Stock Awards	Following is a summary of the future vesting of our outstanding restricted stock awards: Year Vesting of Restricted Shares 2019 4,048,963 2020 3,537,544 2021 4,814,403 2022 152,104 2023 121,093 Thereafter 480,498 Total Outstanding 13,154,605
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, 2018 and 2017 (in millions): Pension Benefits OPEB 2018 2017 2018 2017 Change in benefit obligation: Benefit obligation at beginning of period $ 2,982 $ 2,884 $ 425 $ 473 Service cost 52 40 1 1 Interest cost 84 88 12 13 Actuarial (gain) loss (172 ) 155 (53 ) (16 ) Benefits paid (175 ) (180 ) (33 ) (38 ) Participant contributions — 3 1 2 Medicare Part D subsidy receipts — — 1 1 Exchange rate changes — 13 — 1 Settlements — (21 ) — — Other(a) (205 ) — (15 ) (12 ) Benefit obligation at end of period 2,566 2,982 339 425 Change in plan assets: Fair value of plan assets at beginning of period 2,296 2,160 335 332 Actual return on plan assets (128 ) 292 (5 ) 29 Employer contributions 30 32 7 9 Participant contributions — 3 1 2 Medicare Part D subsidy receipts — — 1 1 Benefits paid (175 ) (180 ) (33 ) (38 ) Exchange rate changes — 10 — — Settlements — (21 ) — — Other(a) (159 ) — — — Fair value of plan assets at end of period 1,864 2,296 306 335 Funded status - net liability at December 31, $ (702 ) $ (686 ) $ (33 ) $ (90 ) _______ (a) 2018 amounts represent December 31, 2017 balances associated with Canadian pension and OPEB plans that were included in the TMPL Sale. 2017 amounts represent December 31, 2016 balances associated with our Plantation Pipeline OPEB plan that are no longer included in these disclosures.
Components of Funded Status	Components of Funded Status . The following table details the amounts recognized in our balance sheets at December 31, 2018 and 2017 related to our pension and OPEB plans (in millions): Pension Benefits OPEB 2018 2017 2018 2017 Non-current benefit asset(a) $ — $ — $ 190 $ 198 Current benefit liability — — (13 ) (15 ) Non-current benefit liability (702 ) (686 ) (210 ) (273 ) Funded status - net liability at December 31, $ (702 ) $ (686 ) $ (33 ) $ (90 ) _______ (a) 2018 and 2017 OPEB amounts include $32 million and $33 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, 2018 and 2017 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets, including the portion attributable to our noncontrolling interests, (in millions): Pension Benefits OPEB 2018 2017 2018 2017 Unrecognized net actuarial (loss) gain $ (653 ) $ (635 ) $ 117 $ 88 Unrecognized prior service (cost) credit (3 ) (4 ) 14 17 Accumulated other comprehensive (loss) income $ (656 ) $ (639 ) $ 131 $ 105
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, 2018 and 2017 (in millions): Pension Assets 2018 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Cash $ — $ — $ — $ — $ 6 $ — $ — $ 6 Short-term investment funds — 7 — 7 — 65 — 65 Mutual funds(a) 81 — — 81 245 — — 245 Equities(b) 227 — — 227 278 — — 278 Fixed income securities — 422 — 422 — 416 — 416 Derivatives — 6 — 6 — 5 — 5 Subtotal $ 308 $ 435 $ — $ 743 $ 529 $ 486 $ — $ 1,015 Measured at NAV(c) Common/collective trusts(d) 857 895 Private investment funds(e) 215 337 Private limited partnerships(f) 49 49 Subtotal 1,121 1,281 Total plan assets fair value $ 1,864 $ 2,296 _______ (a) Includes mutual funds which are invested in equity. (b) Plan assets include $94 million and $110 million of KMI Class P common stock for 2018 and 2017 , respectively. (c) Plan assets for which fair value was measured using NAV as a practical expedient. (d) Common/collective trust funds were invested in approximately 37% fixed income and 63% equity in 2018 and 36% fixed income and 64% equity in 2017 . (e) Private investment funds were invested in approximately 71% fixed income and 29% equity in 2018 and 52% fixed income and 48% equity in 2017 . (f) Includes assets invested in real estate, venture and buyout funds. OPEB Assets 2018 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Short-term investment funds $ — $ 4 $ — $ 4 $ — $ 7 $ — $ 7 Equities(a) — — — — 16 — — 16 MLPs — — — — 50 — — 50 Guaranteed insurance contracts — — 51 51 — — 49 49 Mutual funds 1 — — 1 1 — — 1 Subtotal $ 1 $ 4 $ 51 $ 56 $ 67 $ 7 $ 49 $ 123 Measured at NAV(b) Common/collective trusts(c) 250 68 Fixed income trusts — 66 Limited partnerships(d) — 78 Subtotal 250 212 Total plan assets fair value $ 306 $ 335 _______ (a) Plan assets include $2 million of KMI Class P common stock for 2017 . (b) Plan assets for which fair value was measured using NAV as a practical expedient. (c) Common/collective trust funds were invested in approximately 60% equity and 40% fixed income securities for 2018 and 71% equity and 29% fixed income securities for 2017 . (d) Limited partnerships were invested in global equity securities.
Schedule of Changes in Plans’ Assets Included in Level 3	The following tables present the changes in our pension and OPEB plans’ assets included in Level 3 for the years ended December 31, 2018 and 2017 (in millions): Pension Assets Balance at Beginning of Period Transfers In (Out) Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period 2017 Insurance contracts $ 16 $ — $ — $ (16 ) $ — OPEB Assets Balance at Beginning of Period Transfers In (Out) Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period 2018 Insurance contracts $ 49 $ — $ 4 $ (2 ) $ 51 2017 Insurance contracts $ 47 $ — $ 5 $ (3 ) $ 49
Schedule of Expected Payment of Future Benefits and Employer Contributions	Expected Payment of Future Benefits and Employer Contributions . As of December 31, 2018 , we expect to make the following benefit payments under our plans (in millions): Fiscal year Pension Benefits OPEB(a) 2019 $ 234 $ 33 2020 233 32 2021 225 32 2022 223 31 2023 214 29 2024 - 2028 969 127 _______ (a) Includes a reduction of approximately $2 million in each of the years 2019 - 2023 and approximately $13 million in aggregate for 2024 - 2028 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 2018 , 2017 and 2016 : Pension Benefits OPEB 2018 2017 2016 2018 2017 2016 Assumptions related to benefit obligations: Discount rate 4.26 % 3.56 % 3.83 % 4.16 % 3.48 % 3.69 % Rate of compensation increase 3.50 % 3.53 % 3.52 % n/a n/a n/a Assumptions related to benefit costs: Discount rate for benefit obligations 3.56 % 3.83 % 4.05 % 3.48 % 3.69 % 3.91 % Discount rate for interest on benefit obligations 3.13 % 3.09 % 3.24 % 3.08 % 3.05 % 3.18 % Discount rate for service cost 3.56 % 3.88 % 4.15 % 3.82 % 4.15 % 4.36 % Discount rate for interest on service cost 3.14 % 3.24 % 3.50 % 3.76 % 3.95 % 4.17 % Expected return on plan assets(a) 7.25 % 7.07 % 7.31 % 7.08 % 6.84 % 7.07 % Rate of compensation increase 3.50 % 3.52 % 3.51 % 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 a UBIT rate of 21% for 2018 , 2017 and 2016 .
Schedule of One-Percentage Point Change in Assumed Health Care Cost Trends	A one -percentage point change in assumed health care cost trends would have the following effects as of December 31, 2018 and 2017 (in millions): 2018 2017 One-percentage point increase: Aggregate of service cost and interest cost $ 1 $ 1 Accumulated postretirement benefit obligation 16 22 One-percentage point decrease: Aggregate of service cost and interest cost $ (1 ) $ (1 ) Accumulated postretirement benefit obligation (14 ) (19 )
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 (in millions): Pension Benefits OPEB 2018 2017 2016 2018 2017 2016 Components of net benefit cost: Service cost $ 52 $ 40 $ 36 $ 1 $ 1 $ 1 Interest cost 84 88 89 12 13 16 Expected return on assets (149 ) (147 ) (151 ) (20 ) (19 ) (19 ) Amortization of prior service cost (credit) — 1 1 (4 ) (3 ) (3 ) Amortization of net actuarial loss (gain) 40 52 35 (6 ) (6 ) — Curtailment and settlement loss — 5 — — — — Net benefit (credit) cost(a) 27 39 10 (17 ) (14 ) (5 ) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 105 17 116 (32 ) (25 ) (48 ) Prior service cost (credit) arising during period — — — — — — Amortization or settlement recognition of net actuarial (loss) gain (87 ) (64 ) (34 ) 3 6 — Amortization of prior service (cost) credit (1 ) (1 ) — 3 1 1 Exchange rate changes — — 1 — — — Total recognized in total other comprehensive (income) loss 17 (48 ) 83 (26 ) (18 ) (47 ) Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ 44 $ (9 ) $ 93 $ (43 ) $ (32 ) $ (52 ) _______ (a) 2018 and 2017 OPEB amounts each include $4 million of net benefit credits related to a plan that we sponsor that is associated with employee services provided to an unconsolidated joint venture. We charge or refund these costs or credits associated with this plan to the joint venture as an offset to our net benefit cost or credit and receive our proportionate share of these costs or credits through our share of the equity investee’s earnings.

Stockholders Equity (Tables)

Stockholders Equity (Tables)	12 Months Ended
	Dec. 31, 2018
Stockholders' Equity Note [Abstract]
Schedule of Dividends Payable [Table Text Block]	The following table provides information about our per share dividends: Year Ended December 31, 2018 2017 2016 Per common share cash dividend declared for the period $ 0.80 $ 0.50 $ 0.50 Per common share cash dividend paid in the period 0.725 0.50 0.50
Schedule of Preferred Stock Dividends [Table Text Block]	The following table provides information regarding our preferred stock dividends: Period Total dividend per share for the period Date of declaration Date of record Date of dividend January 26, 2018 through April 25, 2018 $24.375 January 17, 2018 April 11, 2018 April 26, 2018 April 26, 2018 through July 25, 2018 24.375 April 18, 2018 July 11, 2018 July 26, 2018 July 26, 2018 through October 25, 2018 24.375 July 18, 2018 October 11, 2018 October 26, 2018
noncontrolling interest table [Table Text Block]	The caption “Noncontrolling interests” in our accompanying consolidated balance sheets consists of interests that we do not own in the following subsidiaries (in millions): December 31, 2018 2017 KML(a) $ 514 $ 1,163 Others 339 325 $ 853 $ 1,488 _______ (a) The reduction in the noncontrolling interests associated with KML is primarily attributable to the accrual of the return of capital distribution for the net proceeds from the TMPL Sale paid to KML’s Restricted Voting Shareholders on January 3, 2019 of approximately $0.9 billion .

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2018
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 (in millions): December 31, 2018 2017 Balance sheet location Accounts receivable, net $ 48 $ 34 Other current assets 2 8 Deferred charges and other assets 55 23 $ 105 $ 65 Current portion of debt $ 6 $ 6 Accounts payable 26 18 Other current liabilities 7 4 Long-term debt 148 155 Other long-term liabilities and deferred credits 34 35 $ 221 $ 218 Year Ended December 31, 2018 2017 2016 Income statement location Revenues Services $ 171 $ 73 $ 71 Product sales and other 94 89 71 $ 265 $ 162 $ 142 Operating Costs, Expenses and Other Costs of sales $ 63 $ 20 $ 38 Other operating expenses 91 100 75

Commitments and Contingent Li_2

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	The table below depicts future gross minimum rental commitments under our operating leases and rights-of-way obligations as of December 31, 2018 (in millions): Year Commitment 2019 $ 122 2020 107 2021 102 2022 97 2023 81 Thereafter 353 Total minimum payments $ 862

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	As of December 31, 2018 , 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 (21.6 ) MMBbl Crude oil basis (13.7 ) MMBbl Natural gas fixed price (33.3 ) Bcf Natural gas basis (26.1 ) Bcf Derivatives not designated as hedging contracts Crude oil fixed price (0.5 ) MMBbl Crude oil basis (4.5 ) MMBbl Natural gas fixed price (4.5 ) Bcf Natural gas basis (26.9 ) Bcf NGL fixed price (3.2 ) MMBbl
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 (in millions): Fair Value of Derivative Contracts Asset derivatives Liability derivatives December 31, December 31, 2018 2017 2018 2017 Location Fair value Fair value Derivatives designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 135 $ 65 $ (45 ) $ (53 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 64 14 — (24 ) Subtotal 199 79 (45 ) (77 ) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 12 41 (37 ) (3 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 121 164 (78 ) (62 ) Subtotal 133 205 (115 ) (65 ) Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) 91 — (6 ) (6 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 106 166 — — Subtotal 197 166 (6 ) (6 ) Total 529 450 (166 ) (148 ) Derivatives not designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 22 8 (5 ) (22 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — — (2 ) Total 22 8 (5 ) (24 ) Total derivatives $ 551 $ 458 $ (171 ) $ (172 )
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 (in millions): Derivatives in fair value hedging relationships Location Gain/(loss) recognized in income on derivatives and related hedged item Year Ended December 31, 2018 2017 2016 Interest rate contracts Interest, net $ (122 ) $ (103 ) $ (180 ) Hedged fixed rate debt Interest, net $ 113 $ 105 $ 160 Derivatives in cash flow hedging relationships Gain/(loss) recognized in OCI on derivative (effective portion)(a) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Year Ended Year Ended Year Ended December 31, December 31, December 31, 2018 2017 2016 2018 2017 2016 2018 2017 2016 Energy commodity derivative contracts $ 201 $ 37 $ (182 ) Revenues—Natural gas sales $ (29 ) $ 18 $ 23 Revenues—Natural gas sales $ — $ — $ — Revenues—Product sales and other (30 ) 55 233 Revenues—Product sales and other (65 ) 11 (12 ) Costs of sales 21 14 (26 ) Costs of sales — — — Interest rate contracts(c) 3 — (3 ) Interest, net (4 ) (5 ) (4 ) Interest, net — — — Foreign currency contracts (59 ) 190 21 Other, net (67 ) 186 (43 ) Other, net — — — Total $ 145 $ 227 $ (164 ) Total $ (109 ) $ 268 $ 183 Total $ (65 ) $ 11 $ (12 ) _______ (a) We expect to reclassify an approximate $165 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2018 into earnings during the next twelve months (when the associated forecasted transactions are also expected to occur); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices. (b) 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 (effective portion) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(a) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Year Ended Year Ended Year Ended December 31, December 31, December 31, 2018 2017 2016 2018 2017 2016 2018 2017 2016 Foreign currency contracts $ 91 $ — $ — Loss on impairments and divestitures, net $ 26 $ — $ — Other, net $ — $ — $ — Total $ 91 $ — $ — Total $ 26 $ — $ — Total $ — $ — $ — _______ (a) During the year ended December 31, 2018, we recognized a $26 million gain from our accumulated other comprehensive loss balance related to the TMPL Sale. See Note 3. Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives Year Ended December 31, 2018 2017 2016 Energy commodity derivative contracts Revenues—Natural gas sales $ 3 $ 20 $ (10 ) Revenues—Product sales and other (12 ) (16 ) (26 ) Costs of sales 2 — 3 Interest rate contracts Interest, net — — 63 Total(a) $ (7 ) $ 4 $ 30 ________ (a) For the years ended December 31, 2018 , 2017 and 2016 includes approximate losses of $4 million and gains of $57 million and $73 million , respectively, associated with natural gas, crude and NGL derivative contract settlements.
Schedule of Accumulated Other Comprehensive Income (Loss)	Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions): Net unrealized gains/(losses) on cash flow hedge derivatives Foreign currency translation adjustments Pension and other postretirement liability adjustments Total Accumulated other comprehensive loss Balance at December 31, 2015 $ 219 $ (322 ) $ (358 ) $ (461 ) Other comprehensive (loss) gain before reclassifications (104 ) 34 (14 ) (84 ) Gains reclassified from accumulated other comprehensive loss (116 ) — — (116 ) Net current-period other comprehensive (loss) income (220 ) 34 (14 ) (200 ) Balance at December 31, 2016 (1 ) (288 ) (372 ) (661 ) Other comprehensive gain before reclassifications 145 55 40 240 Gains reclassified from accumulated other comprehensive loss (171 ) — — (171 ) KML IPO — 44 7 51 Net current-period other comprehensive (loss) income (26 ) 99 47 120 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 (Note 1) (4 ) (36 ) (69 ) (109 ) Net current-period other comprehensive income (loss) 191 98 (78 ) 211 Balance at December 31, 2018 $ 164 $ (91 ) $ (403 ) $ (330 ) _______ (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.

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the Codification (in millions). The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements. Balance sheet asset fair value measurements by level Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral held(b) Net amount As of December 31, 2018 Energy commodity derivative contracts(a) $ 28 $ 193 $ — $ 221 $ (39 ) $ (25 ) $ 157 Interest rate contracts $ — $ 133 $ — $ 133 $ (7 ) $ — $ 126 Foreign currency contracts $ — $ 197 $ — $ 197 $ (6 ) $ — $ 191 As of December 31, 2017 Energy commodity derivative contracts(a) $ 17 $ 70 $ — $ 87 $ (42 ) $ (12 ) $ 33 Interest rate contracts $ — $ 205 $ — $ 205 $ (15 ) $ — $ 190 Foreign currency contracts $ — $ 166 $ — $ 166 $ (6 ) $ — $ 160 Balance sheet liability fair value measurements by level Level 1 Level 2 Level 3 Gross amount Contracts available for netting Collateral posted(b) Net amount As of December 31, 2018 Energy commodity derivative contracts(a) $ (11 ) $ (39 ) $ — $ (50 ) $ 39 $ — $ (11 ) Interest rate contracts $ — $ (115 ) $ — $ (115 ) $ 7 $ — $ (108 ) Foreign currency contracts $ — $ (6 ) $ — $ (6 ) $ 6 $ — $ — As of December 31, 2017 Energy commodity derivative contracts(a) $ (3 ) $ (98 ) $ — $ (101 ) $ 42 $ — $ (59 ) Interest rate contracts $ — $ (65 ) $ — $ (65 ) $ 15 $ — $ (50 ) Foreign currency contracts $ — $ (6 ) $ — $ (6 ) $ 6 $ — $ — _______ (a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and NGL 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.
Fair Value, by Balance Sheet Grouping	The carrying value and estimated fair value of our outstanding debt balances is disclosed below (in millions): December 31, 2018 December 31, 2017 Carrying value Estimated fair value Carrying value Estimated fair value Total debt $ 37,324 $ 37,469 $ 37,843 $ 40,050

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Schedule of Impact to Consolidated Financial Statement Line Items	The impact to our consolidated financial statement line items from the adoption of Topic 606 for these changes was as follows (in millions): Year ended December 31, 2018 Line Item As Reported Amounts Without Adoption of Topic 606 Effect of Change Increase/(Decrease) Consolidated Statement of Income Natural gas sales $ 3,281 $ 3,339 $ (58 ) Services 7,931 8,134 (203 ) Product sales and other 2,932 3,270 (338 ) Total Revenues 14,144 14,743 (599 ) Cost of sales 4,421 5,020 (599 ) Operating Income 3,794 3,794 —
Schedule of Disaggregation of Revenue	The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source (in millions): Year ended December 31, 2018 Natural Gas Pipelines Products Pipelines Terminals CO 2 Kinder Morgan Canada Corporate and Eliminations Total Revenues from contracts with customers(a) Services Firm services(b) $ 3,215 $ 566 $ 976 $ 2 $ — $ (13 ) $ 4,746 Fee-based services 860 791 581 67 167 — 2,466 Total services revenues 4,075 1,357 1,557 69 167 (13 ) 7,212 Sales Natural gas sales 3,319 — — 2 — (11 ) 3,310 Product sales 1,333 216 18 1,222 — (1 ) 2,788 Other sales 8 — — — — — 8 Total sales revenues 4,660 216 18 1,224 — (12 ) 6,106 Total revenues from contracts with customers 8,735 1,573 1,575 1,293 167 (25 ) 13,318 Other revenues(c) 280 140 444 (38 ) 3 (3 ) 826 Total revenues $ 9,015 $ 1,713 $ 2,019 $ 1,255 $ 170 $ (28 ) $ 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) below). (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 Accounting Standards Codification other than in Topic 606 and primarily include leases and derivatives. The majority of our lease revenues are from certain firm service contracts that are accounted for as operating leases. See Note 14 for additional information related to our derivative contracts.
Activity in Contract Assets and Liabilities	The following table presents the activity in our contract assets and liabilities (in millions): Year ended December 31, 2018 Contract Assets Balance at January 1, 2018 $ 32 Additions 59 Transfer to Accounts receivable (67 ) Balance at December 31, 2018(a) $ 24 Contract Liabilities Balance at January 1, 2018 $ 206 Additions 453 Transfer to Revenues (360 ) Other(b) (7 ) Balance at December 31, 2018(c) $ 292 _______ (a) Includes current and non-current balances of $14 million and $10 million reported within “Other current assets” and “Deferred charges and other assets,” respectively, in our accompanying consolidated balance sheet at December 31, 2018 . (b) Includes 2018 foreign currency translation adjustments associated with the balances at December 31, 2017 . (c) Includes current and non-current balances of $80 million and $212 million reported within “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheet at December 31, 2018 .
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, 2018 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions): Year Estimated Revenue 2019 $ 4,881 2020 4,182 2021 3,528 2022 3,011 2023 2,497 Thereafter 14,138 Total $ 32,237

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Financial information by segment follows (in millions): Year Ended December 31, 2018 2017 2016 Revenues Natural Gas Pipelines Revenues from external customers $ 9,004 $ 8,608 $ 7,998 Intersegment revenues 11 10 7 Products Pipelines Revenues from external customers 1699 1645 1631 Intersegment revenues 14 16 18 Terminals Revenues from external customers 2,017 1,965 1,921 Intersegment revenues 2 1 1 CO2 1,255 1,196 1,221 Kinder Morgan Canada 170 256 253 Corporate and intersegment eliminations(a) (28 ) 8 8 Total consolidated revenues $ 14,144 $ 13,705 $ 13,058 Year Ended December 31, 2018 2017 2016 Operating expenses(b) Natural Gas Pipelines $ 5,353 $ 5,457 $ 4,393 Products Pipelines 594 487 573 Terminals 818 788 768 CO 2 453 394 399 Kinder Morgan Canada 72 95 87 Corporate and intersegment eliminations (2 ) (6 ) 2 Total consolidated operating expenses $ 7,288 $ 7,215 $ 6,222 Year Ended December 31, 2018 2017 2016 Other expense (income)(c) Natural Gas Pipelines $ 593 $ 26 $ 199 Products Pipelines 34 — 76 Terminals 54 (14 ) 99 CO 2 79 (1 ) 19 Kinder Morgan Canada (596 ) — — Corporate — 1 (7 ) Total consolidated other expense (income) $ 164 $ 12 $ 386 Year Ended December 31, 2018 2017 2016 DD&A Natural Gas Pipelines $ 1,058 $ 1,011 $ 1,041 Products Pipelines 228 216 221 Terminals 484 472 435 CO 2 473 493 446 Kinder Morgan Canada 29 46 44 Corporate 25 23 22 Total consolidated DD&A $ 2,297 $ 2,261 $ 2,209 Year Ended December 31, 2018 2017 2016 Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments Natural Gas Pipelines $ 391 $ 253 $ (269 ) Products Pipelines 75 48 56 Terminals 22 24 19 CO 2 34 42 22 Total consolidated equity earnings $ 522 $ 367 $ (172 ) Year Ended December 31, 2018 2017 2016 Other, net-income (expense) Natural Gas Pipelines $ 37 $ 49 $ 19 Products Pipelines 3 (1 ) 2 Terminals 2 8 4 Kinder Morgan Canada 26 25 15 Corporate 39 16 38 Total consolidated other, net-income (expense) $ 107 $ 97 $ 78 Year Ended December 31, 2018 2017 2016 Segment EBDA(d) Natural Gas Pipelines $ 3,580 $ 3,487 $ 3,211 Products Pipelines 1,173 1,231 1,067 Terminals 1,171 1,224 1,078 CO 2 759 847 827 Kinder Morgan Canada 720 186 181 Total segment EBDA 7,403 6,975 6,364 DD&A (2,297 ) (2,261 ) (2,209 ) Amortization of excess cost of equity investments (95 ) (61 ) (59 ) General and administrative and corporate charges (588 ) (660 ) (652 ) Interest, net (1,917 ) (1,832 ) (1,806 ) Income tax expense (587 ) (1,938 ) (917 ) Total consolidated net income $ 1,919 $ 223 $ 721 Year Ended December 31, 2018 2017 2016 Capital expenditures Natural Gas Pipelines $ 1,620 $ 1,376 $ 1,227 Products Pipelines 150 127 244 Terminals 380 888 983 CO 2 397 436 276 Kinder Morgan Canada 332 338 124 Corporate 25 23 28 Total consolidated capital expenditures $ 2,904 $ 3,188 $ 2,882 2018 2017 Investments at December 31 Natural Gas Pipelines $ 6,358 $ 6,218 Products Pipelines 839 777 Terminals 268 263 CO 2 16 6 Kinder Morgan Canada — 34 Total consolidated investments $ 7,481 $ 7,298 2018 2017 Assets at December 31 Natural Gas Pipelines $ 51,562 $ 51,173 Products Pipelines 8,429 8,539 Terminals 9,283 9,935 CO 2 3,928 3,946 Kinder Morgan Canada — 2,080 Corporate assets(e) 5,664 3,382 Total consolidated assets $ 78,866 $ 79,055 _______ (a) 2017 and 2016 amounts include a management fee of $35 million and $34 million , respectively, for services we perform as operator of an equity investee. (b) Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes. (c) Includes loss on impairments and divestitures, net and other income, net. (d) Includes revenues, earnings from equity investments, other, net, less operating expenses, loss on impairments and divestitures, net, loss on impairments and divestitures of equity investments, net and other income, net, (e) 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 activity) not allocated to our reportable segments.
Schedule of Revenue and Long-lived Assets from External Customers Attributed to Foreign Countries by Geographic Area [Table Text Block]	Following is geographic information regarding the revenues and long-lived assets of our business (in millions): Year Ended December 31, 2018 2017 2016 Revenues from external customers U.S. $ 13,596 $ 13,073 $ 12,459 Canada 447 503 483 Mexico and other foreign 101 129 116 Total consolidated revenues from external customers $ 14,144 $ 13,705 $ 13,058 December 31, 2018 2017 2016 Long-term assets, excluding goodwill and other intangibles U.S. $ 47,468 $ 47,928 $ 49,125 Canada 748 3,071 2,399 Mexico and other foreign 83 80 82 Total consolidated long-lived assets $ 48,299 $ 51,079 $ 51,606

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Adoption of ASU (Details) - USD ($) $ in Millions	Jan. 01, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect		$ 3,005	$ (461)	$ 498
Accrued contingencies and other current liabilities		73	138	11
Other, net		0	4	1
Impact of adoption of ASUs	$ 66	(109)
Accounting Standards Update 2017-05 [Member] | Other Long-Term Liabilities and Deferred Credits [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
EIG's cumulative contribution to ELC			485
Other Nonoperating Income (Expense) [Member] | Accounting Standards Update 2017-07 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impact of adoption of ASUs			15	34
General and Administrative Expense [Member] | Accounting Standards Update 2017-07 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impact of adoption of ASUs			(15)	(34)
Accumulated other comprehensive loss
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impact of adoption of ASUs	(109)
Accumulated other comprehensive loss | Accounting Standards Update 2018-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impact of adoption of ASUs		(109)
Retained deficit
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impact of adoption of ASUs	$ 175
Retained deficit | Accounting Standards Update 2017-05 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impact of adoption of ASUs		66
Retained deficit | Accounting Standards Update 2018-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impact of adoption of ASUs		$ 109
Accounting Standards Update 2016-18 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect			41	(43)
Accrued contingencies and other current liabilities			0	(37)
Other, net			$ (41)	$ 80

Summary of Significant Accoun_5

Summary of Significant Accounting Policies Cash Equivalents and Restricted Deposits (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Restricted deposits	$ 51	$ 62

Summary of Significant Accoun_6

Summary of Significant Accounting Policies Accounts Receivable, Net (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Allowance for Doubtful Accounts Receivable	$ 3	$ 35

Summary of Significant Accoun_7

Summary of Significant Accounting Policies Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Composite depreciation rate, low	1.01%
Composite depreciation rate, high	23.00%

Summary of Significant Accoun_8

Summary of Significant Accounting Policies Equity investment and excess costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity, Amortization Period	12 years
Amortized [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method of Accounting and Excess Investment Cost	$ 470	$ 732
Not Subject To Amortization But Subject to Impairment [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method of Accounting and Excess Investment Cost	$ 1,967	$ 1,967

Summary of Significant Accoun_9

Summary of Significant Accounting Policies Goodwill (Details)	7 Months Ended
	Jul. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of Reporting Units	7

Summary of Significant Accou_10

Summary of Significant Accounting Policies Other Intangibles (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Intangible Assets, Gross (Excluding Goodwill)	$ 4,305	$ 4,305
Finite-Lived Intangible Assets, Accumulated Amortization	1,425	1,206
Intangible Assets, Net (Excluding Goodwill)	2,880	3,099
Amortization of Intangible Assets	219	$ 220	$ 223
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	213
Finite-Lived Intangible Assets, Amortization Expense, Year Two	209
Finite-Lived Intangible Assets, Amortization Expense, Year Three	209
Finite-Lived Intangible Assets, Amortization Expense, Year Four	207
Finite-Lived Intangible Assets, Amortization Expense, Year Five	$ 203
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	15 years

Summary of Significant Accou_11

Summary of Significant Accounting Policies Operations and Maintenance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	$ 363	$ 342	$ 349

Summary of Significant Accou_12

Summary of Significant Accounting Policies Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets and Liabilities [Line Items]
Current regulatory assets	$ 66	$ 60
Non-current regulatory assets	245	288
Total regulatory assets(a)	311	348
Current regulatory liabilities	29	107
Non-current regulatory liabilities	206	236
Total regulatory liabilities(b)	235	$ 343
Regulatory assets recoverable without earning a return	$ 98
Regulatory assets, weighted average remaining recovery period	23 years
Remaining Amounts of Regulatory Liabilities Subject to Crediting Period	$ 136
Remaining Recovery Period of Regulatory Liabilities Subject to Defined Crediting Period	18 years
Remaining Amounts of Regulatory Liabilities Not Subject to Defined Crediting Period	$ 70
Loss on Disposal of Assets [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	176
Income Tax Gross Up on AFUDC Equity [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	53
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	$ 82

Summary of Significant Accou_13

Summary of Significant Accounting Policies Earnings per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	May 25, 2017	May 24, 2017
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ 1,481	$ 27	$ 552
Basic Weighted Average Common Shares Outstanding	2,216	2,230	2,230
Basic Earnings Per Common Share	$ 0.66	$ 0.01	$ 0.25
Class of Warrant or Right, Exercise Price of Warrants or Rights					$ 40
Number of Warrants Expired				293
Unvested restricted stock awards
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	12	10	8
Warrants to purchase our Class P shares
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements		116	293
Convertible trust preferred securities
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	3	3	8
Mandatory convertible preferred stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	48	58	58
Unvested restricted stock awards
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Unvested Restricted Stock Awards, Issued and Non Issued	13
Class P
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ 1,473	$ 22	$ 548
Participating Securities [Member] | Unvested restricted stock awards
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ (8)	$ (5)	$ (4)

Divestitures and Acquisition Sa

Divestitures and Acquisition Sale of Trans Mountain pipeline System and ts Expansion Project (Details) $ in Millions, $ in Millions	Feb. 01, 2019USD ($)	Jan. 04, 2019	Jan. 03, 2019USD ($)	Jan. 03, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Aug. 31, 2018USD ($)	Aug. 31, 2018CAD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on impairments and divestitures, net						$ 167	$ 13	$ 387
Proceeds from the TMPL Sale, net of cash disposed (Note 3)						2,998	0	0
Repayments of debt						14,591	$ 11,064	$ 10,060
Trans Mountain and Trans Mountain Expansion Project [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration									$ 3,400	$ 4,430
Contractual purchase price										$ 4,500
Loss on impairments and divestitures, net						(596)
Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments to noncontrolling interests			$ 900	$ 1,200
Repayments of commercial paper			400
Kinder Morgan, Inc. | Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from the TMPL Sale, net of cash disposed (Note 3)			$ 1,900	$ 2,500
Repayments of debt	$ 1,300
Kinder Morgan Canada Limited [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Approved reduction in stated capital					$ 1,450
Kinder Morgan Canada Limited [Member] | Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage			70.00%	70.00%
Reverse stock split ratio		0.33
Working Capital Adjustments [Member] | Trans Mountain and Trans Mountain Expansion Project [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on impairments and divestitures, net						$ 26

Divestitures and Acquisition _2

Divestitures and Acquisition Sale of Interest in Canadian Business (Details) $ / shares in Units, $ in Millions, $ in Millions	May 30, 2017USD ($)shares	May 30, 2017CAD ($)$ / sharesshares	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contributions from noncontrolling interests - net proceeds from KML IPO			$ 0	$ 1,245	$ 0
Noncontrolling Interest, Increase from Sale of Parent Equity Interest				1,049
Property, plant and equipment, net			37,897	40,155
Other non-current assets			1,355	1,582
Total Assets			78,866	79,055
Current portion of debt			3,388	2,828
Total other current liabilities			7,557	6,181
Long-term debt			33,936	35,015
Other long-term liabilities and deferred credits			2,176	2,735
Total Liabilities			43,669	43,931
Kinder Morgan Canada Limited Partnership [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total current assets			3,204	270
Property, plant and equipment, net			719	2,956
Other non-current assets			8	322
Total Assets			3,931	3,548
Current portion of debt			0	0
Total other current liabilities			2,353	236
Long-term debt			0	0
Other long-term liabilities and deferred credits			52	414
Total Liabilities			$ 2,405	650
Accumulated other comprehensive loss
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling Interest, Increase from Sale of Parent Equity Interest				51
Non-controlling interests
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling Interest, Increase from Sale of Parent Equity Interest				684
Kinder Morgan Canada Limited [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners		30.00%
Kinder Morgan Canada Limited [Member] | KML Special Voting Shares [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Controlling Interest, Ownership Percentage by Parent		100.00%
Kinder Morgan Canada Limited [Member] | KML Voting Shares [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Controlling Interest, Ownership Percentage by Parent		70.00%
Sale of Equity Interest in Canadian Business [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contributions from noncontrolling interests - net proceeds from KML IPO				1,245
Adjustments to Additional Paid in Capital, Other				314
Deferred Income Tax Adjustment due to IPO				166
Sale of Equity Interest in Canadian Business [Member] | Restricted Voting Shares [Member] | Kinder Morgan Canada Limited [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Shares, Issued | shares	102,942,000	102,942,000
Shares Issued, Price Per Share | $ / shares		$ 17
Proceeds from Issuance Initial Public Offering	$ 1,299	$ 1,750
Sale of Equity Interest in Canadian Business [Member] | Accumulated other comprehensive loss | Kinder Morgan Canada Limited [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Foreign Currency Translation Gains (Losses)				(81)
Sale of Equity Interest in Canadian Business [Member] | Non-controlling interests | Kinder Morgan Canada Limited [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling Interest, Increase from Sale of Parent Equity Interest				765
Disposal Group, Including Discontinued Operation, Foreign Currency Translation Gains (Losses)				$ 81
Sale of Equity Interest in Canadian Business [Member] | Kinder Morgan Canada Limited Partnership [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners		30.00%
Controlling Interest Percentage Retained After Partial Sale	70.00%	70.00%

Divestitures and Acquisition _3

Divestitures and Acquisition Sale of Noncontrolling Interest in ELC (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Feb. 28, 2017
Property, Plant and Equipment [Line Items]
Contributions from investment partner	$ 181	$ 485	$ 0
Sale of Equity Interest in Elba Liquification Company LLC [Member]
Property, Plant and Equipment [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners				49.00%
Controlling Interest, Ownership Percentage by Parent				51.00%
Contributions from investment partner	$ 386

Divestitures and Acquisition Te

Divestitures and Acquisition Terminals Asset Sale (Details) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Jun. 30, 2017	Oct. 31, 2016USD ($)
Long Lived Assets Held-for-sale [Line Items]
Loss on impairments and divestitures, net		$ 167	$ 13	$ 387
Terminal Asset Sale [Member]
Long Lived Assets Held-for-sale [Line Items]
Consideration on transaction						$ 100
Loss on impairments and divestitures, net				81
Goodwill, period increase (decrease)				$ 7
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Terminal Asset Sale [Member]
Long Lived Assets Held-for-sale [Line Items]
Number of terminals	8			8
Proceeds from sale of assets	$ 37
Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Terminal Asset Sale [Member]
Long Lived Assets Held-for-sale [Line Items]
Number of terminals					11

Divestitures and Acquisition _4

Divestitures and Acquisition Sale of Equity Interest in SNG (Details) - USD ($) $ in Millions	Sep. 01, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of equity interests in subsidiaries, net		$ 0	$ 0	$ 1,401
Loss on impairments and divestitures, net		$ 167	$ 13	387
Bear Creek Storage
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity Method Investment, Ownership Percentage		75.00%
Sale Equity Interest in SNG [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Equity Interest Sold	50.00%
Proceeds from sale of equity interests in subsidiaries, net	$ 1,400
Loss on impairments and divestitures, net				$ 84
Sale Equity Interest in SNG [Member] | Southern Natural Gas Company LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
SNG | Bear Creek Storage
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity Method Investment, Ownership Percentage		25.00%
SNG | Sale Equity Interest in SNG [Member] | Bear Creek Storage
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity Method Investment, Ownership Percentage	50.00%

Divestitures and Acquisition Ac

Divestitures and Acquisition Acquisition of BP Products North America Inc. (BP) Terminal Assets (Details) $ in Millions	Feb. 01, 2016USD ($)Terminals	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)Terminals
Business Acquisition [Line Items]
Proceeds from noncontrolling interests		$ 19	$ 12	$ 117
BP Terminal Assets [Member]
Business Acquisition [Line Items]
Number of terminals wholly owned | Terminals	1
Number of terminals | Terminals	15
Payments to acquire businesses, gross	$ 349
Property, plant and equipment acquired	396
Current assets acquired	2
Liabilities assumed	$ 49
New Joint Venture with BP [Member] | BP Terminal Assets [Member]
Business Acquisition [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	75.00%
Number of terminals contributed to equity investment | Terminals	14
BP [Member] | New Joint Venture with BP [Member] | BP Terminal Assets [Member]
Business Acquisition [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	25.00%
Proceeds from noncontrolling interests				$ 84
Terminals
Business Acquisition [Line Items]
Number of terminals | Terminals				20

Impairments (Details)

Impairments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)Terminals	Sep. 01, 2016
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairment of long-lived assets and equity investments	$ 437	$ 172	$ 1,013
(Gain) Loss on Sale of Assets and Asset Impairment Charges	167	13	387
Loss (Gain) on impairments and divestitures of equity investments, net	270	150	610
Gain (Loss) on Disposition of Assets		0	0
Revenues	14,144	13,705	13,058
Trans Mountain,Trans Mountain Expansion Project and Other Related Assets [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Gain (Loss) on Disposition of Assets	(595)
Sale Equity Interest in SNG [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gain) Loss on Sale of Assets and Asset Impairment Charges			84
Disposal Group, Equity Interest Sold				50.00%
Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairment of long-lived assets	600	30	106
(Gain) Loss on Sale of Assets and Asset Impairment Charges	(6)	0	94
Loss (Gain) on impairments and divestitures of equity investments, net	270	150	606
Revenues	9,015
Natural Gas Pipelines | Investee [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairment at equity investee, other than temporary	0	10	7
Natural Gas Pipelines | Sale Equity Interest in SNG [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Disposal Group, Equity Interest Sold				50.00%
Products Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairment of long-lived assets	36	0	66
(Gain) Loss on Sale of Assets and Asset Impairment Charges	0	0	10
Loss (Gain) on impairments and divestitures of equity investments, net	0	0	(12)
Revenues	1,713
Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairment of long-lived assets	59	3	19
(Gain) Loss on Sale of Assets and Asset Impairment Charges	(6)	(18)	80
Loss (Gain) on impairments and divestitures of equity investments, net	0	0	$ 16
Number of terminals | Terminals			20
Revenues	2,019
Terminals | Deeprock Development [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gain) Loss on Sale of Assets and Asset Impairment Charges		$ (23)
Disposal Group, Equity Interest Sold		40.00%
CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairment of long-lived assets	79	$ (1)	$ 20
(Gain) Loss on Sale of Assets and Asset Impairment Charges	0	0	(1)
Revenues	1,255
CO2 | Investee [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairment at equity investee, other than temporary	0	(4)	9
Other
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gain) Loss on Sale of Assets and Asset Impairment Charges	0	2	(7)
Operating Segments
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
(Gain) Loss on Sale of Assets and Asset Impairment Charges	437	172	1,013
Operating Segments | Products Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Revenues	1,699	1,645	1,631
Cost of Sales [Member] | Natural Gas Pipelines | Colden storage [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairment of long-lived assets		3
MEP
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Equity Method Investments	235	253
MEP | Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (Gain) on impairments and divestitures of equity investments, net			350
Ruby
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Equity Method Investments	750	$ 774
Ruby | Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (Gain) on impairments and divestitures of equity investments, net			$ 250
Pacific Gas and Electric (PG&E) [Member] | Ruby
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Revenues	93
Ruby
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Notes receivable from affiliates	$ 55

Income Taxes Income Tax Disclos

Income Taxes Income Tax Disclosures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Results of Operations, Income before Income Taxes [Abstract]
U.S.	$ 1,739	$ 1,976	$ 1,466
Foreign	767	185	172
Income Before Income Taxes	2,506	2,161	1,638
Current tax expense (benefit) [Abstract]
Federal	(22)	(137)	(148)
State	(45)	(16)	(28)
Foreign	249	18	6
Total	182	(135)	(170)
Deferred tax expense (benefit) [Abstract]
Federal	425	2,022	998
State	55	4	51
Foreign	(75)	47	38
Total	405	2,073	1,087
Effective Income Tax Rate Reconciliation [Abstract]
Federal income tax	$ 526	$ 756	$ 573
Federal income tax, percent	21.00%	35.00%	35.00%
State deferred tax rate change	$ (7)	$ 10	$ 11
State deferred tax rate change, percent	(0.30%)	0.50%	0.70%
Taxes on foreign earnings, net of federal benefit	$ 131	$ 42	$ 28
Taxes on foreign earnings, net of federal benefit, percent	5.20%	1.90%	1.70%
Net effects of noncontrolling interests	$ (65)	$ (14)	$ (4)
Net effects of noncontrolling interests, percent	(2.60%)	(0.70%)	(0.30%)
State income tax, net of federal benefit	$ 46	$ 38	$ 26
State income tax, net of federal benefit, percent	1.80%	1.80%	1.60%
Dividend received deduction	$ (31)	$ (56)	$ (48)
Dividend received deduction, percent	(1.20%)	(2.60%)	(2.90%)
Adjustments to uncertain tax positions	$ (47)	$ (12)	$ (23)
Adjustments to uncertain tax positions, percent	(1.90%)	(0.60%)	(1.40%)
Valuation allowance on investment and tax credits	$ 14	$ 13	$ 34
Valuation allowance on investment and tax credits, percent	0.50%	0.60%	2.10%
Impact of the 2017 Tax Reform	$ 0	$ 1,240	$ 0
Impact of the 2017 Tax Reform, percent	0.00%	57.40%	0.00%
Nondeductible goodwill	$ 58	$ 0	$ 301
Nondeductible goodwill, percent	2.30%	0.00%	18.50%
General business credit	$ (64)	$ (95)	$ 0
General business credit, percent	(2.60%)	(4.40%)	(0.00%)
Other	$ 26	$ 16	$ 19
Other, percent	1.20%	0.80%	1.10%
Total	$ 587	$ 1,938	$ 917
Total, percent	23.40%	89.70%	56.10%
Deferred Tax Assets [Abstract]
Employee benefits	$ 238	$ 251
Accrued expenses	76	73
Net operating loss, capital loss and tax credit carryforwards	1,526	1,113
Derivative instruments and interest rate and currency swaps	9	12
Debt fair value adjustments	33	37
Investments	177	968
Other	0	6
Valuation allowance	(178)	(171)
Total deferred tax assets	1,881	2,289
Deferred Tax Liabilities, Gross [Abstract]
Property, plant and equipment	270	225
Other	45	20
Total deferred tax liabilities	315	245
Net deferred tax assets	1,566	2,044
Canada
Income Tax Disclosures [Line Items]
Income Tax Expense	168	58	$ 38
Mexico
Income Tax Disclosures [Line Items]
Income Tax Expense	$ 6	$ 7	$ 6

Income Taxes Deferred Tax Asset

Income Taxes Deferred Tax Assets and Valuation Allowances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Valuation Allowance [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 7
Deferred Tax Assets, Operating Loss Carryforwards	1,249	$ 935
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	260	178
Deferred Tax Assets, Valuation Allowance	178	171
Tax Adjustments, Settlements, and Unusual Provisions	(8)
Deferred Tax Assets, Capital Loss Carryforwards	17
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax Increase (Decrease)		(137)
Proceeds from Income Tax Refunds	145
Capital Loss Carryforward [Member]
Valuation Allowance [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	17
Foreign Currency Gain (Loss) [Member]
Valuation Allowance [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	(6)
SEC Schedule, 12-09, Valuation Allowance, Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	(4)
SEC Schedule, 12-09, Valuation Allowance, Deferred Tax Asset [Member]
Valuation Allowance [Line Items]
Deferred Tax Assets, Valuation Allowance	$ 140	$ 133

Income Taxes Deferred Tax Ass_2

Income Taxes Deferred Tax Asset Expiration Periods (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Income Tax Examination [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	$ 260	$ 178
Deferred Tax Assets, Capital Loss Carryforwards	17
Foreign Tax Authority [Member]
Income Tax Examination [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Foreign	112
Tax Credit Carryforwards	17
State and Local Jurisdiction [Member] | Domestic Tax Authority [Member]
Income Tax Examination [Line Items]
Operating Loss Carryforwards	3,700
Indefinite Tax Period [Member] | Domestic Tax Authority [Member]
Income Tax Examination [Line Items]
Operating Loss Carryforwards	1,400
Expires from 2019 - 2037 [Member] | Domestic Tax Authority [Member]
Income Tax Examination [Line Items]
Operating Loss Carryforwards	3,400
General Business Tax Credit Carryforward [Member]
Income Tax Examination [Line Items]
Tax Credit Carryforwards	241
Capital Loss Carryforward [Member]
Income Tax Examination [Line Items]
Operating Loss Carryforwards	$ 17

Income Taxes Unrecognized Tax B

Income Taxes Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Balance at beginning of period	$ 97	$ 122	$ 148
Additions based on current year tax positions	3	3	3
Additions based on prior year tax positions	7	0	7
Reductions based on prior year tax positions	0	0	(1)
Reductions based on settlements with taxing authority	(73)	(22)	(26)
Reductions due to lapse in statute of limitations	0	(2)	(9)
Impact of the 2017 Tax Reform	0	(4)	0
Balance at end of period	34	97	122
Unrecognized Tax Benefits,Other Disclosure [Abstract]
Income Tax Examination, Penalties and Interest Expense (Benefit)	(15)	(9)	2
Income Tax Examination, Interest Accrued				$ 2	$ 19	$ 28
Income Tax Examination, Penalties Accrued				1	0
Unrecognized Tax Benefits	$ 97	$ 122	$ 148	34	$ 97	$ 122
Decrease in Unrecognized Tax Benefits is Reasonably Possible				21
Unrecognized tax benefits balance reasonably possible next year				$ 13

Income Taxes 2017 Tax Reform (D

Income Taxes 2017 Tax Reform (Details) - USD ($) $ in Millions	Jan. 01, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Contingency [Line Items]
Federal income tax		21.00%	35.00%	35.00%
New Federal Income Tax Rate	21.00%
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ 0	$ 1,240	$ 0
Impact of the 2017 Tax Reform on Expense		26	16	$ 19
Impact of 2017 Tax Reform [Member]
Income Tax Contingency [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount			1,240
Impact of the 2017 Tax Reform on Expense		2
Impact of 2017 Tax Reform [Member] | after tax [Member]
Income Tax Contingency [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		27	144
Impact of 2017 Tax Reform [Member] | pre-tax [Member]
Income Tax Contingency [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ 36	$ 219

Property, Plant and Equipment C

Property, Plant and Equipment Classes and Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 15,359	$ 14,175
Property, Plant and Equipment, Net, Excluding Nondepreciable Assets	34,207	35,704
Property, plant and equipment, net	37,897	40,155
Depreciation, Depletion and Amortization, Property, Plant and Equipment	2,057	2,022	$ 1,970
Pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	19,727	20,157
Equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	24,392	24,152
Other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	5,447	5,570
Land [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,378	1,456
Construction work in progress [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,312	2,995
Natural Gas Pipelines Regulated
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 12,349	$ 14,055

Property, Plant and Equipment A

Property, Plant and Equipment Asset Retirement Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	$ 213	$ 208
Asset Retirement Obligation, Current	$ 4	$ 4

Investments Equity investments

Investments Equity investments (Details) $ in Millions	Sep. 01, 2019	Jan. 01, 2019	Dec. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)
Investment [Line Items]
Long-term Investments			$ 7,481	$ 7,298
Citrus Corporation
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Total equity investments			$ 1,708	1,698
SNG
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Total equity investments			$ 1,536	1,495
Ruby
Investment [Line Items]
Total equity investments			$ 750	774
NGPL Holdings, LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Total equity investments			$ 733	687
Gulf LNG Holdings Group LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Total equity investments			$ 361	461
Plantation Pipe Line Company
Investment [Line Items]
Equity Method Investment, Ownership Percentage			51.17%
Total equity investments			$ 344	331
Utopia Holding L.L.C.
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Total equity investments			$ 333	276
EagleHawk
Investment [Line Items]
Equity Method Investment, Ownership Percentage			25.00%
Total equity investments			$ 299	314
Gulf Coast Express LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			35.00%
Total equity investments			$ 240	0
MEP
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Total equity investments			$ 235	253
Red Cedar Gathering company
Investment [Line Items]
Equity Method Investment, Ownership Percentage			49.00%
Total equity investments			$ 191	187
Watco Companies, LLC
Investment [Line Items]
Common Unit, Issued | shares			13,000
Profit participation rate			0.40%
Total equity investments			$ 185	182
Watco Companies, LLC | Preferred stock
Investment [Line Items]
Common Unit, Issued | shares			100,000
Quarterly preferred distribution rate			3.25%
Watco Companies, LLC | Preferred Class B
Investment [Line Items]
Common Unit, Issued | shares			50,000
Quarterly preferred distribution rate			3.00%
Watco Companies, LLC | Common Units
Investment [Line Items]
Equity Method Investment, Ownership Percentage			3.20%
Double Eagle Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Total equity investments			$ 140	149
Liberty Pipeline Group LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Total equity investments			$ 66	71
Bear Creek Storage
Investment [Line Items]
Equity Method Investment, Ownership Percentage			75.00%
Total equity investments			$ 65	63
Sierrita Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			35.00%
Total equity investments			$ 55	55
Permian Highway Pipeline
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Total equity investments			$ 45	0
FEP
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Total equity investments			$ 44	112
Cortez Pipeline Company
Investment [Line Items]
Equity Method Investment, Ownership Percentage			52.98%
All others
Investment [Line Items]
Total equity investments			$ 151	$ 190
Energy Transfers Partners L.P. | Citrus Corporation
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Energy Transfers Partners L.P. | MEP
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Energy Transfers Partners L.P. | Liberty Pipeline Group LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Southern Natural Gas Company LLC | SNG
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Southern Natural Gas Company LLC | Bear Creek Storage
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Pembina Pipeline Company | Ruby
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Brookfield Infrastructure Partners L.P. | NGPL Holdings, LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
GE Energy Financial Services, The Blackstone Group L.P. and Others | Gulf LNG Holdings Group LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Riverstone Investment Group LLC | Utopia Holding L.L.C.
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
BHP Billiton Petroleum | EagleHawk
Investment [Line Items]
Equity Method Investment, Ownership Percentage			75.00%
DCP GCX Pipeline LLC | Gulf Coast Express LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			25.00%
Florida Gas Transmission Company, L.L.C.
Investment [Line Items]
Miles Of Pipeline			5,300
Targa GCX Pipeline LLC | Gulf Coast Express LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			25.00%
Altus Midstream Company | Gulf Coast Express LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			15.00%
Southern Ute Indian Tribe | Red Cedar Gathering company
Investment [Line Items]
Equity Method Investment, Ownership Percentage			51.00%
Magellan Midstream Partners | Double Eagle Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
TGP | Bear Creek Storage
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
MGI Enterprises U.S. LLC | Sierrita Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			35.00%
MIT Pipeline Investment Americas, Inc. | Sierrita Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage			30.00%
BCP PHP, LLC | Permian Highway Pipeline
Investment [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Mobil Cortez Pipeline Inc. | Cortez Pipeline Company
Investment [Line Items]
Equity Method Investment, Ownership Percentage			33.25%
Cortez Vickers Pipeline Company | Cortez Pipeline Company
Investment [Line Items]
Equity Method Investment, Ownership Percentage			13.77%
SNG | Bear Creek Storage
Investment [Line Items]
Equity Method Investment, Ownership Percentage			25.00%
Subsequent Event | Permian Highway Pipeline
Investment [Line Items]
Equity Method Investment, Ownership Percentage	26.67%	40.00%
Subsequent Event | Altus Midstream Company | Permian Highway Pipeline
Investment [Line Items]
Equity Method Investment, Ownership Percentage	26.67%
Subsequent Event | Anchor Shipper | Permian Highway Pipeline
Investment [Line Items]
Equity Method Investment, Ownership Percentage		20.00%
Subsequent Event | BCP PHP, LLC | Permian Highway Pipeline
Investment [Line Items]
Equity Method Investment, Ownership Percentage	26.67%	40.00%

Investments Investments (Detail

Investments Investments (Details)	Dec. 31, 2018
Florida Gas Transmission Company, L.L.C.
Schedule of Equity Method Investments [Line Items]
Miles Of Pipeline	5,300
Energy Transfers Partners L.P. | Fayetteville Express
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Citrus Corporation
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Citrus Corporation | Energy Transfers Partners L.P.
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%

Investments Equity Earnings (De

Investments Equity Earnings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	$ 887	$ 578	$ 497
Amortization of excess costs	(95)	(61)	(59)
Gulf LNG Holdings Group LLC
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	209	47	48
Citrus Corporation
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	169	108	102
SNG
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	141	77	58
NGPL Holdco LLC
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	66	10	12
FEP
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	55	53	51
Plantation Pipe Line Company
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	55	46	37
Cortez Pipeline Company
Net Investment Income [Line Items]
Impairment at equity investee, other than temporary		(4)	9
Income (Loss) from Equity Method Investments	36	44	24
MEP
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	31	38	40
Ruby
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	26	44	15
Watco Companies LLC
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	21	19	25
Red Cedar Gathering company
Net Investment Income [Line Items]
Impairment at equity investee, other than temporary		10
Income (Loss) from Equity Method Investments	18	14	24
Utopia Holding L.L.C.
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	14	0	0
Double Eagle Pipeline LLC
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	10	7	5
Bear Creek Storage
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	9	8	2
EagleHawk
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	7	24	10
Liberty Pipeline Group LLC
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	7	9	11
Sierrita Pipeline LLC
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	7	7	7
Gulf Coast Express LLC
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	2	0	0
All others
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	$ 4	$ 23	$ 26

Investments Summary of Signific

Investments Summary of Significant Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Revenues	$ 5,129	$ 4,703	$ 4,084
Costs and expenses	3,371	3,398	3,056
Net income	1,758	1,305	$ 1,028
Current assets	1,496	956
Non-current assets	23,396	22,344
Current liabilities	2,715	1,241
Non-current liabilities	9,555	10,605
Partners’/owners’ equity	$ 12,622	$ 11,454

Goodwill Rollforward (Details)

Goodwill Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Historical Goodwill			$ 27,715
Accumulated impairment losses			(5,563)
Goodwill	$ 21,965	$ 22,162	22,152
Currency translation	(8)	13
Divestitures(a)	(190)	(3)
Other	1
Natural Gas Pipelines Regulated
Goodwill [Line Items]
Historical Goodwill			15,892
Accumulated impairment losses			(1,643)
Goodwill	14,249	14,249	14,249
Currency translation	0	0
Divestitures(a)	0	0
Other	0
Natural Gas Pipelines-Nonregulated
Goodwill [Line Items]
Historical Goodwill			5,812
Accumulated impairment losses			(1,597)
Goodwill	4,215	4,215	4,215
Currency translation	0	0
Divestitures(a)	0	0
Other	0
CO2
Goodwill [Line Items]
Historical Goodwill			1,528
Accumulated impairment losses			0
Goodwill	1,528	1,528	1,528
Currency translation	0	0
Divestitures(a)	0	0
Other	0
Products Pipelines
Goodwill [Line Items]
Historical Goodwill			2,125
Accumulated impairment losses			(1,197)
Goodwill	928	928	928
Currency translation	0	0
Divestitures(a)	0	0
Other	0
Products Pipelines Terminals
Goodwill [Line Items]
Historical Goodwill			221
Accumulated impairment losses			(70)
Goodwill	151	151	151
Currency translation	0	0
Divestitures(a)	0	0
Other	0
Terminals
Goodwill [Line Items]
Historical Goodwill			1,575
Accumulated impairment losses			(679)
Goodwill	894	893	896
Currency translation	0	0
Divestitures(a)	0	(3)
Other	1
Kinder Morgan Canada
Goodwill [Line Items]
Historical Goodwill			562
Accumulated impairment losses			(377)
Goodwill	0	198	$ 185
Currency translation	(8)	13
Divestitures(a)	(190)	$ 0
Other	$ 0

Debt (Details)

Debt (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 36,593	$ 36,916
Less: Current portion of debt	3,388	2,828
Long Term Debt Non-current Excluding Debt Fair Value Adjustments	$ 33,205	$ 34,088
Preferred Stock, Liquidation Preference Per Share	$ 1,000	$ 1,000
Preferred stock, shares outstanding (in shares)	0	1,600,000
Preferred Stock, Dividend Rate, Percentage	9.75%	9.75%
Debt fair value adjustments	$ 731	$ 927
Capital Trust [Member]
Debt Instrument [Line Items]
Controlling Interest, Ownership Percentage by Parent	100.00%
Credit facility and commercial paper borrowings
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 433	365
6.00%, due January 2018
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	0	750
Less: Current portion of debt	$ 0	$ 750
Interest rate, stated percentage	6.00%	6.00%
7.00%, due February 2018
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 0	$ 82
Less: Current portion of debt	$ 0	$ 82
Interest rate, stated percentage	7.00%	7.00%
5.95%, due February 2018
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 0	$ 975
Less: Current portion of debt	$ 0	$ 975
Interest rate, stated percentage	5.95%	5.95%
7.25%, due June 2018
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 0	$ 477
Less: Current portion of debt	$ 0	$ 477
Interest rate, stated percentage	7.25%	7.25%
9.00%, due February 2019
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 500	$ 500
Less: Current portion of debt	$ 500	$ 0
Interest rate, stated percentage	9.00%	9.00%
2.65%, due February 2019
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 800	$ 800
Less: Current portion of debt	$ 800	$ 0
Interest rate, stated percentage	2.65%	2.65%
3.05%, due December 2019
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 1,500	$ 1,500
Less: Current portion of debt	$ 1,500	$ 0
Interest rate, stated percentage	3.05%	3.05%
6.85%, due February 2020
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 700	$ 700
Interest rate, stated percentage	6.85%	6.85%
6.50%, due April 2020
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 535	$ 535
Interest rate, stated percentage	6.50%	6.50%
5.30%, due September 2020
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 600	$ 600
Interest rate, stated percentage	5.30%	5.30%
6.50%, due September 2020
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 349	$ 349
Interest rate, stated percentage	6.50%	6.50%
5.00%, due February 2021
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 750	$ 750
Interest rate, stated percentage	5.00%	5.00%
3.50%, due March 2021
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 750	$ 750
Interest rate, stated percentage	3.50%	3.50%
5.80%, due March 2021
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 400	$ 400
Interest rate, stated percentage	5.80%	5.80%
5.00%, due October 2021
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 500	$ 500
Interest rate, stated percentage	5.00%	5.00%
4.15%, due March 2022
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 375	$ 375
Interest rate, stated percentage	4.15%	4.15%
1.50%, due March 2022
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 860	$ 900
Translation Adjustment Functional to Reporting Currency, Increase (Decrease), Gross of Tax	$ 46	$ 86
Interest rate, stated percentage	1.50%	1.50%
3.95%, due September 2022
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 1,000	$ 1,000
Interest rate, stated percentage	3.95%	3.95%
3.15%, due January 2023
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 1,000	$ 1,000
Interest rate, stated percentage	3.15%	3.15%
Floating rate, due January 2023
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 250	$ 250
3.45%, due February 2023
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 625	$ 625
Interest rate, stated percentage	3.45%	3.45%
3.50%, due September 2023
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 600	$ 600
Interest rate, stated percentage	3.50%	3.50%
5.625%, due November 2023
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 750	$ 750
Interest rate, stated percentage	5.63%	5.63%
4.15%, due February 2024
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 650	$ 650
Interest rate, stated percentage	4.15%	4.15%
4.30%, due May 2024
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 600	$ 600
Interest rate, stated percentage	4.30%	4.30%
4.25%, due September 2024
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 650	$ 650
Interest rate, stated percentage	4.25%	4.25%
4.30%, due June 2025
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 1,500	$ 1,500
Interest rate, stated percentage	4.30%	4.30%
6.70%, due February 2027
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 7	$ 7
Interest rate, stated percentage	6.70%	6.70%
2.25%, due March 2027
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 573	$ 600
Translation Adjustment Functional to Reporting Currency, Increase (Decrease), Gross of Tax	$ 30	$ 57
Interest rate, stated percentage	2.25%	2.25%
6.67%, due November 2027
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 7	$ 7
Interest rate, stated percentage	6.67%	6.67%
4.30%, due March 2028
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 1,250	$ 0
Interest rate, stated percentage	4.30%	4.30%
7.25%, due March 2028
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 32	$ 32
Interest rate, stated percentage	7.25%	7.25%
6.95%, due June 2028
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 31	$ 31
Interest rate, stated percentage	6.95%	6.95%
8.05%, due October 2030
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 234	$ 234
Interest rate, stated percentage	8.05%	8.05%
7.40%, due March 2031
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 300	$ 300
Interest rate, stated percentage	7.40%	7.40%
7.80%, due August 2031
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 537	$ 537
Interest rate, stated percentage	7.80%	7.80%
7.75%, due January 2032
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 1,005	$ 1,005
Interest rate, stated percentage	7.75%	7.75%
7.75%, due March 2032
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 300	$ 300
Interest rate, stated percentage	7.75%	7.75%
7.30%, due August 2033
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 500	$ 500
Interest rate, stated percentage	7.30%	7.30%
5.30%, due December 2034
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 750	$ 750
Interest rate, stated percentage	5.30%	5.30%
5.80%, due March 2035
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 500	$ 500
Interest rate, stated percentage	5.80%	5.80%
7.75%, due October 2035
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 1	$ 1
Interest rate, stated percentage	7.75%	7.75%
6.40%, due January 2036
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 36	$ 36
Interest rate, stated percentage	6.40%	6.40%
6.50%, due February 2037
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 400	$ 400
Interest rate, stated percentage	6.50%	6.50%
7.42%, due February 2037
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 47	$ 47
Interest rate, stated percentage	7.42%	7.42%
6.95%, due January 2038
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 1,175	$ 1,175
Interest rate, stated percentage	6.95%	6.95%
6.50%, due September 2039
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 600	$ 600
Interest rate, stated percentage	6.50%	6.50%
6.55%, due September 2040
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 400	$ 400
Interest rate, stated percentage	6.55%	6.55%
7.50%, due November 2040
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 375	$ 375
Interest rate, stated percentage	7.50%	7.50%
6.375%, due March 2041
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 600	$ 600
Interest rate, stated percentage	6.38%	6.38%
5.625%, due September 2041
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 375	$ 375
Interest rate, stated percentage	5.63%	5.63%
5.00%, due August 2042
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 625	$ 625
Interest rate, stated percentage	5.00%	5.00%
4.70%, due November 2042
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 475	$ 475
Interest rate, stated percentage	4.70%	4.70%
5.00%, due March 2043
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 700	$ 700
Interest rate, stated percentage	5.00%	5.00%
5.50%, due March 2044
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 750	$ 750
Interest rate, stated percentage	5.50%	5.50%
5.40%, due September 2044
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 550	$ 550
Interest rate, stated percentage	5.40%	5.40%
5.55%, due June 2045
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 1,750	$ 1,750
Interest rate, stated percentage	5.55%	5.55%
5.05%, due February 2046
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 800	$ 800
Interest rate, stated percentage	5.05%	5.05%
5.20%, due March 2048
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 750	$ 0
Interest rate, stated percentage	5.20%	5.20%
7.45%, due March 2098
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 26	$ 26
Interest rate, stated percentage	7.45%	7.45%
7.00%, due March 2027 | TGP
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 300	$ 300
Interest rate, stated percentage	7.00%	7.00%
7.00%, due October 2028 | TGP
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 400	$ 400
Interest rate, stated percentage	7.00%	7.00%
8.375%, due June 2032 | TGP
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 240	$ 240
Interest rate, stated percentage	8.38%	8.38%
7.625%, due April 2037 | TGP
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 300	$ 300
Interest rate, stated percentage	7.63%	7.63%
8.625%, due January 2022 | EPNG [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 260	$ 260
Interest rate, stated percentage	8.63%	8.63%
7.50%, due November 2026 | EPNG [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 200	$ 200
Interest rate, stated percentage	7.50%	7.50%
8.375%, due June 2032 | EPNG [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 300	$ 300
Interest rate, stated percentage	8.38%	8.38%
4.15%, due August 2026 | CIG [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 375	$ 375
Interest rate, stated percentage	4.15%	4.15%
6.85%, due June 2037 | CIG [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 100	$ 100
Interest rate, stated percentage	6.85%	6.85%
EPC Building, LLC, promissory note, 3.967%, due December 2035 | EPC Building LLC [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 409	$ 421
Interest rate, stated percentage	3.97%	3.97%
Trust I Preferred Securities, 4.75%, due March 2028
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Price	$ 25.18
Trust I Preferred Securities, 4.75%, due March 2028 | Class P
Debt Instrument [Line Items]
Preferred Stock, Conversion, Shares	0.7197
Trust I Preferred Securities, 4.75%, due March 2028 | Capital Trust I [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 221	$ 221
Interest rate, stated percentage	4.75%	4.75%
Trust Convertible Preferred Securities Outstanding (in shares)	4,400,000
Preferred Stock, Liquidation Preference Per Share	$ 50
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057 | Kinder Morgan G.P., Inc. [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 100	$ 100
Preferred stock, shares outstanding (in shares)	100,000	100,000
Preferred stock, par value (in dollars per share)	$ 1,000	$ 1,000
Preferred Stock, Dividend Rate, Percentage	3.8975%
Other miscellaneous debt
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	$ 250	$ 278
Senior Notes [Member]
Debt Instrument [Line Items]
Redemption price of debt as a percentage of face amount	100.00%
1.50%, due March 2022 and 2.25%, due March 2027 [Member] | Euro Member Countries, Euro
Debt Instrument [Line Items]
Foreign Currency Exchange Rate, Translation	1.1467	1.2005

Debt Current Portion of Debt (D

Debt Current Portion of Debt (Details) - USD ($) $ in Millions	Feb. 01, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Nov. 16, 2018
Debt Instrument [Line Items]
Current portion of debt		$ 3,388	$ 2,828
Debt, Weighted Average Interest Rate		5.15%	5.02%
Repayments of debt		$ 14,591	$ 11,064	$ 10,060
$500 million, 364-day credit facility due November 15, 2019
Debt Instrument [Line Items]
Current portion of debt		0	0
$4 billion credit facility due November 16, 2023
Debt Instrument [Line Items]
Current portion of debt		0	0
$5 billion, five-year credit facility due November 26, 2019, -% and 2.99%, respectively
Debt Instrument [Line Items]
Current portion of debt		$ 0	$ 125
Line of Credit Facility, Current Borrowing Capacity					$ 5,000
Debt, Weighted Average Interest Rate		0.00%	2.99%
Commercial paper notes, 3.10% and 2.02%, respectively
Debt Instrument [Line Items]
Current portion of debt		$ 433	$ 240
Debt, Weighted Average Interest Rate		3.10%	2.02%
KML 2018 Credit Facility
Debt Instrument [Line Items]
Current portion of debt		$ 0	$ 0
KML 2018 Credit Facility | Canada, Dollars
Debt Instrument [Line Items]
Foreign Currency Exchange Rate, Translation		0.7330	0.7971
6.00%, due January 2018
Debt Instrument [Line Items]
Current portion of debt		$ 0	$ 750
Debt Instrument, Interest Rate, Stated Percentage		6.00%	6.00%
7.00%, due February 2018
Debt Instrument [Line Items]
Current portion of debt		$ 0	$ 82
Debt Instrument, Interest Rate, Stated Percentage		7.00%	7.00%
5.95%, due February 2018
Debt Instrument [Line Items]
Current portion of debt		$ 0	$ 975
Debt Instrument, Interest Rate, Stated Percentage		5.95%	5.95%
7.25%, due June 2018
Debt Instrument [Line Items]
Current portion of debt		$ 0	$ 477
Debt Instrument, Interest Rate, Stated Percentage		7.25%	7.25%
9.00%, due February 2019
Debt Instrument [Line Items]
Current portion of debt		$ 500	$ 0
Debt Instrument, Interest Rate, Stated Percentage		9.00%	9.00%
9.00%, due February 2019 | Subsequent Event
Debt Instrument [Line Items]
Repayments of debt	$ 500
Debt Instrument, Interest Rate, Stated Percentage	9.00%
2.65%, due February 2019
Debt Instrument [Line Items]
Current portion of debt		$ 800	$ 0
Debt Instrument, Interest Rate, Stated Percentage		2.65%	2.65%
2.65%, due February 2019 | Subsequent Event
Debt Instrument [Line Items]
Repayments of debt	$ 800
Debt Instrument, Interest Rate, Stated Percentage	2.65%
3.05%, due December 2019
Debt Instrument [Line Items]
Current portion of debt		$ 1,500	$ 0
Debt Instrument, Interest Rate, Stated Percentage		3.05%	3.05%
Trust I Preferred Securities, 4.75%, due March 2028
Debt Instrument [Line Items]
Current portion of debt		$ 111	$ 111
Debt Instrument, Interest Rate, Stated Percentage		4.75%
Current portion - Other debt
Debt Instrument [Line Items]
Current portion of debt		$ 44	$ 68

Credit Facilities and Restricti

Credit Facilities and Restrictive Covenants (Details) $ in Millions, $ in Millions	Aug. 31, 2018USD ($)	Aug. 31, 2018CAD ($)	May 30, 2018CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2018CAD ($)	Nov. 16, 2018USD ($)
Line of Credit Facility [Line Items]
Repayments of Debt				$ 14,591	$ 11,064	$ 10,060
$5 billion, five-year credit facility due November 26, 2019, -% and 2.99%, respectively
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity								$ 5,000
$4 billion credit facility due November 16, 2023
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity								4,000
$4 billion credit facility due November 16, 2023 | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage				0.10%
$4 billion credit facility due November 16, 2023 | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage				0.30%
$500 million, 364-day credit facility due November 15, 2019
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity								$ 500
$500 million, 364-day credit facility due November 15, 2019 | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage				0.09%
$500 million, 364-day credit facility due November 15, 2019 | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage				0.28%
Commercial Paper [Member]
Line of Credit Facility [Line Items]
Commercial Paper, Current Borrowing Capacity				$ 4,000
Debt Instrument, Term				270 days
364-day Due 2019 And 5-year Due 2023 Senior Unsecured Revolving Credit Facilities [Member]
Line of Credit Facility [Line Items]
Maximum ratio of consolidated total funded debt to consolidated earnings before interest income taxes DDA				5.50			5.50
Letters of Credit Outstanding, Amount				$ 99
Remaining borrowing capacity				$ 3,968
364-day Due 2019 And 5-year Due 2023 Senior Unsecured Revolving Credit Facilities [Member] | LIBOR Alternate Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				0.10%
364-day Due 2019 And 5-year Due 2023 Senior Unsecured Revolving Credit Facilities [Member] | LIBOR Alternate Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.00%
364-day Due 2019 And 5-year Due 2023 Senior Unsecured Revolving Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.00%
364-day Due 2019 And 5-year Due 2023 Senior Unsecured Revolving Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				2.00%
364-day Due 2019 And 5-year Due 2023 Senior Unsecured Revolving Credit Facilities [Member] | Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				0.50%
364-day Due 2019 And 5-year Due 2023 Senior Unsecured Revolving Credit Facilities [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.00%
KML 2018 Credit Facility
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity				$ 367			$ 500
Maximum ratio of consolidated total funded debt to consolidated earnings before interest income taxes DDA				5			5
Letters of Credit Outstanding, Amount				$ 8			$ 11
Remaining borrowing capacity				$ 359			489
KML 2018 Credit Facility | Backstop letter of credit [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount							$ 8
KML 2018 Credit Facility | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage				0.20%
KML 2018 Credit Facility | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage				0.45%
KML 2018 Credit Facility | Bankers Acceptance [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.00%
KML 2018 Credit Facility | Bankers Acceptance [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				2.25%
KML 2018 Credit Facility | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.00%
KML 2018 Credit Facility | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				2.25%
KML 2018 Credit Facility | Prime Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.25%
KML 2018 Credit Facility | US bank rate loans [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate				1.25%
KML Temporary Credit Facility [Member]
Line of Credit Facility [Line Items]
Repayments of Debt	$ 102	$ 133
KML 2017 Credit Facility [Member]
Line of Credit Facility [Line Items]
Repayments of Debt			$ 100
Write off of Deferred Debt Issuance Cost				$ 46
Commercial Paper [Member] | 364-day Due 2019 And 5-year Due 2023 Senior Unsecured Revolving Credit Facilities [Member]
Line of Credit Facility [Line Items]
Commercial Paper				$ 433

Debt Maturities of Debt (Detail

Debt Maturities of Debt (Details) $ in Millions	Dec. 31, 2018USD ($)
Debt Disclosure [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 3,388
Long-term Debt, Maturities, Repayments of Principal in Year Two	2,205
Long-term Debt, Maturities, Repayments of Principal in Year Three	2,422
Long-term Debt, Maturities, Repayments of Principal in Year Four	2,518
Long-term Debt, Maturities, Repayments of Principal in Year Five	3,250
Long-term Debt, Maturities, Repayments of Principal after Year Five	22,810
Total debt outstanding	$ 36,593

Debt Debt Fair Value Adjustment

Debt Debt Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Amortization Period of Deferred Gain (Loss) on Discontinuation of Fair Value Hedge	16 years
Purchase accounting debt fair value adjustments	$ 658	$ 719
Carrying value adjustment to hedged debt	2	115
Unamortized portion of proceeds received from the early termination of interest rate swap agreements	275	297
Unamortized debt discounts, net	(74)	(74)
Unamortized debt issuance costs	(130)	(130)
Total debt fair value adjustments	$ 731	$ 927

Debt Interest Rates, Interest R

Debt Interest Rates, Interest Rate Swaps and Contingent Debt (Details)	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt, Weighted Average Interest Rate	5.15%	5.02%

Share-based Compensation and _3

Share-based Compensation and Employee Benefits (Share-based Compensation - Narrative) (Details) - Restricted Stock [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Nonemployee Directors[Member] | Class P
Share-based Compensation [Abstract]
Shares of Class P common stock authorized under the plan	250,000
Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Nonemployee Directors[Member] | Class P | Six Month Vesting Period [Member]
Share-based Compensation [Abstract]
Grants during the period (shares)	25,800	17,740	31,880
Value of shares granted	$ 0.5	$ 0.4	$ 0.4
Award vesting period	6 months
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P
Share-based Compensation [Abstract]
Shares of Class P common stock authorized under the plan	33,000,000
Grants during the period (shares)	5,389,476	3,221,691	2,816,599
Intrinsic value of restricted stock vested	$ 42	$ 30	$ 25
Expense related to restricted stock awards	63	65	66
Amounts capitalized related to restricted stock awards	13	9	$ 9
Unrecognized compensation costs	$ 127	$ 127
Unrecognized compensation costs, weighted average remaining amortization period	2 years 3 months 26 days	2 years 3 months 26 days
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P | Minimum [Member]
Share-based Compensation [Abstract]
Award vesting period	1 year
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P | Maximum [Member]
Share-based Compensation [Abstract]
Award vesting period	10 years
KML Restricted Share Unit Plan for Employees [Member]
Share-based Compensation [Abstract]
Expense related to restricted stock awards	$ 6	$ 1
Amounts capitalized related to restricted stock awards	2	$ 1
Unrecognized compensation costs	$ 3
Unrecognized compensation costs, weighted average remaining amortization period	2 years 1 month 6 days

Share-based Compensation and _4

Share-based Compensation and Employee Benefits (Summary of Activity and Related Balances of Restricted Stock Awards) (Details) - Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] - Restricted Stock [Member] - Class P - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Shares
Outstanding at beginning of period (shares)	10,518,344	9,038,137	7,645,105
Granted (shares)	5,389,476	3,221,691	2,816,599
Vested (shares)	(2,371,193)	(1,501,939)	(1,226,652)
Forfeited (shares)	(382,022)	(239,545)	(196,915)
Outstanding at end of period (shares)	13,154,605	10,518,344	9,038,137
Weighted Average Grant Date Fair Value
Outstanding at beginning of period (dollars per share)	$ 28.21	$ 32.72	$ 37.91
Granted (dollars per share)	17.73	19.52	21.36
Vested (dollars per share)	36.34	36.67	38.53
Forfeited (dollars per share)	23.26	28.34	35.74
Outstanding at end of period (dollars per share)	$ 22.59	$ 28.21	$ 32.72

Share-based Compensation and _5

Share-based Compensation and Employee Benefits (Summary of Future Vesting of Outstanding Restricted Stock Awards) (Details) - Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] - Restricted Stock [Member] - Class P - shares	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	13,154,605	10,518,344	9,038,137	7,645,105
2019 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	4,048,963
2020 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	3,537,544
2021 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	4,814,403
2022 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	152,104
2023 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	121,093
Thereafter [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards outstanding	480,498

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Components of Accumulated Other Comprehensive Income/Loss
Expected amortization in next year	$ 40
Expected amortization in next year, unrecognized net actuarial loss	(42)
Expected amortization in next year, unrecognized prior service (credit)	$ (2)
Pension Benefits [Member]
Pension Plans and OPEB
Percentage of employees covered	100.00%
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 27	$ 39	$ 10
Components of Accumulated Other Comprehensive Income/Loss
Accumulated benefit obligation	2,535	2,840
Expected Payment of Future Benefits and Employer Contributions
Expected employer contributions in next year	$ 60
Pension Benefits [Member] | Minimum [Member] | Equity Securities [Member]
Plan Assets
Target allocation percentage	34.00%
Pension Benefits [Member] | Minimum [Member] | Fixed Income Securities [Member]
Plan Assets
Target allocation percentage	37.00%
Pension Benefits [Member] | Minimum [Member] | Cash [Member]
Plan Assets
Target allocation percentage	0.00%
Pension Benefits [Member] | Minimum [Member] | Alternative Investments [Member]
Plan Assets
Target allocation percentage	0.00%
Pension Benefits [Member] | Minimum [Member] | Company Securities [Member]
Plan Assets
Target allocation percentage	0.00%
Pension Benefits [Member] | Maximum [Member] | Equity Securities [Member]
Plan Assets
Target allocation percentage	59.00%
Pension Benefits [Member] | Maximum [Member] | Fixed Income Securities [Member]
Plan Assets
Target allocation percentage	57.00%
Pension Benefits [Member] | Maximum [Member] | Cash [Member]
Plan Assets
Target allocation percentage	5.00%
Pension Benefits [Member] | Maximum [Member] | Alternative Investments [Member]
Plan Assets
Target allocation percentage	2.00%
Pension Benefits [Member] | Maximum [Member] | Company Securities [Member]
Plan Assets
Target allocation percentage	10.00%
Pension Benefits [Member] | U.S.
Pension Plans and OPEB
Vesting period	3 years
OPEB [Member]
Pension Plans and OPEB
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ (17)	(14)	(5)
Components of Accumulated Other Comprehensive Income/Loss
Accumulated benefit obligation whose accumulated benefit obligations exceeded the fair value of plan assets	293	373
Accumulated benefit obligation whose accumulated benefit obligations exceeded the fair value of plan assets, fair value of plan assets	70	84
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	7.26%
Ultimate health care cost trend rate	4.54%
OPEB [Member] | Minimum [Member] | Equity Securities [Member]
Plan Assets
Target allocation percentage	42.00%
OPEB [Member] | Minimum [Member] | Fixed Income Securities [Member]
Plan Assets
Target allocation percentage	25.00%
OPEB [Member] | Minimum [Member] | Cash [Member]
Plan Assets
Target allocation percentage	0.00%
OPEB [Member] | Maximum [Member] | Equity Securities [Member]
Plan Assets
Target allocation percentage	67.00%
OPEB [Member] | Maximum [Member] | Fixed Income Securities [Member]
Plan Assets
Target allocation percentage	51.00%
OPEB [Member] | Maximum [Member] | Cash [Member]
Plan Assets
Target allocation percentage	20.00%
OPEB [Member] | U.S.
Other Postretirement Benefit Plans
Medicare participation, age	65
Savings plan - defined contribution plan [Member]
Savings Plan
Percentage of eligible compensation contributed	5.00%
Plan cost	$ 48	$ 47	$ 47

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of period	$ 2,982	$ 2,884
Service cost	52	40	$ 36
Interest cost	84	88	89
Actuarial (gain) loss	(172)	155
Benefits paid	(175)	(180)
Participant contributions	0	3
Medicare Part D subsidy receipts	0	0
Exchange rate changes	0	13
Settlements	0	(21)
Other	(205)	0
Benefit obligation at end of period	2,566	2,982	2,884
Change in plan assets:
Fair value of plan assets at beginning of period	2,296	2,160
Actual return on plan assets	(128)	292
Employer contributions	30	32
Participant contributions	0	3
Medicare Part D subsidy receipts	0	0
Benefits paid	(175)	(180)
Exchange rate changes	0	10
Settlements	0	(21)
Other	(159)	0
Fair value of plan assets at end of period	1,864	2,296	2,160
Funded status - net liability at December 31,	(702)	(686)
OPEB [Member]
Change in benefit obligation:
Benefit obligation at beginning of period	425	473
Service cost	1	1	1
Interest cost	12	13	16
Actuarial (gain) loss	(53)	(16)
Benefits paid	(33)	(38)
Participant contributions	1	2
Medicare Part D subsidy receipts	1	1
Exchange rate changes	0	1
Settlements	0	0
Other	(15)	(12)
Benefit obligation at end of period	339	425	473
Change in plan assets:
Fair value of plan assets at beginning of period	335	332
Actual return on plan assets	(5)	29
Employer contributions	7	9
Participant contributions	1	2
Medicare Part D subsidy receipts	1	1
Benefits paid	(33)	(38)
Exchange rate changes	0	0
Settlements	0	0
Other	0	0
Fair value of plan assets at end of period	306	335	$ 332
Funded status - net liability at December 31,	$ (33)	$ (90)

Share-based Compensation and _8

Share-based Compensation and Employee Benefits (Components of Funded Status) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Non-current benefit asset	$ 0	$ 0
Current benefit liability	0	0
Non-current benefit liability	(702)	(686)
Funded status - net liability at December 31,	(702)	(686)
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Non-current benefit asset	190	198
Current benefit liability	(13)	(15)
Non-current benefit liability	(210)	(273)
Funded status - net liability at December 31,	(33)	(90)
OPEB [Member] | Other Affiliates [Member]
Defined Benefit Plan Disclosure [Line Items]
Non-current benefit asset	$ 32	$ 33

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, 2018	Dec. 31, 2017
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Unrecognized net actuarial (loss) gain	$ (653)	$ (635)
Unrecognized prior service (cost) credit	(3)	(4)
Accumulated other comprehensive (loss) income	(656)	(639)
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Unrecognized net actuarial (loss) gain	117	88
Unrecognized prior service (cost) credit	14	17
Accumulated other comprehensive (loss) income	$ 131	$ 105

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 1,864	$ 2,296	$ 2,160
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	743	1,015
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	308	529
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	435	486
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	1,121	1,281
Pension Benefits [Member] | Cash [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	6
Pension Benefits [Member] | Cash [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	6
Pension Benefits [Member] | Cash [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Cash [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Short-term Investment Funds [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	7	65
Pension Benefits [Member] | Short-term Investment Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Short-term Investment Funds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	7	65
Pension Benefits [Member] | Short-term Investment Funds [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	227	278
Pension Benefits [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	227	278
Pension Benefits [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Guaranteed Insurance Contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value		0	16
Pension Benefits [Member] | Mutual Funds [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	81	245
Pension Benefits [Member] | Mutual Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	81	245
Pension Benefits [Member] | Mutual Funds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Mutual Funds [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Fixed Income Securities [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	422	416
Pension Benefits [Member] | Fixed Income Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Fixed Income Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	422	416
Pension Benefits [Member] | Fixed Income Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Derivatives [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	6	5
Pension Benefits [Member] | Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	6	5
Pension Benefits [Member] | Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
Pension Benefits [Member] | Defined Benefit Plan, Common Collective Trust [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 857	$ 895
Pension Benefits [Member] | Common Collective Trusts Invested in Equity Securities [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	63.00%	64.00%
Pension Benefits [Member] | Common Collective Trusts Invested in Fixed Income Securities [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	37.00%	36.00%
Pension Benefits [Member] | Private Equity Funds [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 215	$ 337
Pension Benefits [Member] | Private Equity Funds Invested in Fixed Income Securities [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	71.00%	52.00%
Pension Benefits [Member] | Private Equity Funds Invested in Equity Securities [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	29.00%	48.00%
Pension Benefits [Member] | Limited Partnership [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 49	$ 49
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	306	335	332
OPEB [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	56	123
OPEB [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	1	67
OPEB [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	4	7
OPEB [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	51	49
OPEB [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	250	212
OPEB [Member] | Short-term Investment Funds [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	4	7
OPEB [Member] | Short-term Investment Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB [Member] | Short-term Investment Funds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	4	7
OPEB [Member] | Short-term Investment Funds [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	16
OPEB [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	16
OPEB [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB [Member] | Master Limited Partnerships [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	50
OPEB [Member] | Master Limited Partnerships [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	50
OPEB [Member] | Master Limited Partnerships [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB [Member] | Master Limited Partnerships [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB [Member] | Guaranteed Insurance Contracts [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	51	49
OPEB [Member] | Guaranteed Insurance Contracts [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB [Member] | Guaranteed Insurance Contracts [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB [Member] | Guaranteed Insurance Contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	51	49	$ 47
OPEB [Member] | Mutual Funds [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	1	1
OPEB [Member] | Mutual Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	1	1
OPEB [Member] | Mutual Funds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB [Member] | Mutual Funds [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	0
OPEB [Member] | Defined Benefit Plan, Common Collective Trust [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 250	$ 68
OPEB [Member] | Common Collective Trusts Invested in Equity Securities [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	60.00%	71.00%
OPEB [Member] | Common Collective Trusts Invested in Fixed Income Securities [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of category allocated to investments	40.00%	29.00%
OPEB [Member] | Fixed Income Trusts [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	$ 0	$ 66
OPEB [Member] | Limited Partnership [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total plan assets fair value	0	78
Class P | Pension Benefits [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Amount of KMI securities invested in	$ 94	110
Class P | OPEB [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Amount of KMI securities invested in		$ 2

Share-based Compensation and_11

Share-based Compensation and Employee Benefits (Schedule of Changes in Plans’ Assets Included in Level 3) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of period	$ 2,296	$ 2,160
Realized and Unrealized Gains (Losses), net	(128)	292
Fair value of plan assets at end of period	1,864	2,296
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of period	0
Fair value of plan assets at end of period	0	0
Pension Benefits [Member] | Guaranteed Insurance Contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of period	0	16
Transfers In (Out)		0
Realized and Unrealized Gains (Losses), net		0
Purchases (Sales), net		(16)
Fair value of plan assets at end of period		0
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of period	335	332
Realized and Unrealized Gains (Losses), net	(5)	29
Fair value of plan assets at end of period	306	335
OPEB [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of period	49
Fair value of plan assets at end of period	51	49
OPEB [Member] | Guaranteed Insurance Contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of period	49	47
Transfers In (Out)	0	0
Realized and Unrealized Gains (Losses), net	4	5
Purchases (Sales), net	(2)	(3)
Fair value of plan assets at end of period	$ 51	$ 49

Share-based Compensation and_12

Share-based Compensation and Employee Benefits (Schedule of Expected Payment of Future Benefits and Employer Contributions) (Details) $ in Millions	Dec. 31, 2018USD ($)
Pension Benefits [Member]
Expected Future Benefit Payments:
2,019	$ 234
2,020	233
2,021	225
2,022	223
2,023	214
2024 - 2028	969
OPEB [Member]
Expected Future Benefit Payments:
2,019	33
2,020	32
2,021	32
2,022	31
2,023	29
2024 - 2028	127
Expected Future Reductions Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003:
2,019	2
2,020	2
2,021	2
2,022	2
2,023	2
2024 - 2028	$ 13

Share-based Compensation and_13

Share-based Compensation and Employee Benefits (Schedule of Weighted-Average Actuarial Assumptions) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Assumptions related to benefit obligations:
Discount rate	4.26%	3.56%	3.83%
Rate of compensation increase	3.50%	3.53%	3.52%
Assumptions related to benefit costs:
Expected return on plan assets	7.25%	7.07%	7.31%
Rate of compensation increase	3.50%	3.52%	3.51%
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
UBIT rate	21.00%	21.00%	21.00%
Assumptions related to benefit obligations:
Discount rate	4.16%	3.48%	3.69%
Assumptions related to benefit costs:
Expected return on plan assets	7.08%	6.84%	7.07%
Benefit obligation [Member] | Pension Benefits [Member]
Assumptions related to benefit costs:
Discount rate	3.56%	3.83%	4.05%
Benefit obligation [Member] | OPEB [Member]
Assumptions related to benefit costs:
Discount rate	3.48%	3.69%	3.91%
Discount rate for interest on benefit obligations [Member] | Pension Benefits [Member]
Assumptions related to benefit costs:
Discount rate	3.13%	3.09%	3.24%
Discount rate for interest on benefit obligations [Member] | OPEB [Member]
Assumptions related to benefit costs:
Discount rate	3.08%	3.05%	3.18%
Discount rate for service cost [Member] | Pension Benefits [Member]
Assumptions related to benefit costs:
Discount rate	3.56%	3.88%	4.15%
Discount rate for service cost [Member] | OPEB [Member]
Assumptions related to benefit costs:
Discount rate	3.82%	4.15%	4.36%
Discount rate for interest on service cost [Member] | Pension Benefits [Member]
Assumptions related to benefit costs:
Discount rate	3.14%	3.24%	3.50%
Discount rate for interest on service cost [Member] | OPEB [Member]
Assumptions related to benefit costs:
Discount rate	3.76%	3.95%	4.17%

Share-based Compensation and_14

Share-based Compensation and Employee Benefits (Schedule of One-Percentage Point Change in Assumed Health Care Cost Trends) (Details) - OPEB [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
One-percentage point increase:
Aggregate of service cost and interest cost	$ 1	$ 1
Accumulated postretirement benefit obligation	16	22
One-percentage point decrease:
Aggregate of service cost and interest cost	(1)	(1)
Accumulated postretirement benefit obligation	$ (14)	$ (19)

Share-based Compensation and_15

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Components of net benefit cost:
Service cost	$ 52	$ 40	$ 36
Interest cost	84	88	89
Expected return on assets	(149)	(147)	(151)
Amortization of prior service cost (credit)	0	1	1
Amortization of net actuarial loss (gain)	40	52	35
Curtailment and settlement loss	0	5	0
Net benefit (credit) cost	27	39	10
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net loss (gain) arising during period	105	17	116
Prior service cost (credit) arising during period	0	0	0
Amortization or settlement recognition of net actuarial (loss) gain	(87)	(64)	(34)
Amortization of prior service (cost) credit	(1)	(1)	0
Exchange rate changes	0	0	1
Total recognized in total other comprehensive (income) loss	17	(48)	83
Total recognized in net benefit cost (credit) and other comprehensive (income) loss	44	(9)	93
OPEB [Member]
Components of net benefit cost:
Service cost	1	1	1
Interest cost	12	13	16
Expected return on assets	(20)	(19)	(19)
Amortization of prior service cost (credit)	(4)	(3)	(3)
Amortization of net actuarial loss (gain)	(6)	(6)	0
Curtailment and settlement loss	0	0	0
Net benefit (credit) cost	(17)	(14)	(5)
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss:
Net loss (gain) arising during period	(32)	(25)	(48)
Prior service cost (credit) arising during period	0	0	0
Amortization or settlement recognition of net actuarial (loss) gain	3	6	0
Amortization of prior service (cost) credit	3	1	1
Exchange rate changes	0	0	0
Total recognized in total other comprehensive (income) loss	(26)	(18)	(47)
Total recognized in net benefit cost (credit) and other comprehensive (income) loss	(43)	(32)	$ (52)
OPEB [Member] | Other Affiliates [Member]
Components of net benefit cost:
Net benefit (credit) cost	$ (4)	$ (4)

Share-based Compensation and_16

Share-based Compensation and Employee Benefits (Other Plans) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Multiemployer Plan, Individually Insignificant Multiemployer Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 8	$ 8	$ 8

Stockholders' Equity Mandatory

Stockholders' Equity Mandatory Convertible Preferred Stock (Details) - $ / shares	Oct. 26, 2018	Jul. 18, 2018	Apr. 18, 2018	Jan. 17, 2018	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage					9.75%	9.75%
Preferred Stock, Liquidation Preference Per Share					$ 1,000	$ 1,000
9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference
Class of Stock [Line Items]
Share issued (in shares)	1,600,000
Preferred Stock, Dividend Rate, Percentage	9.75%				9.75%
Preferred Stock, Liquidation Preference Per Share	$ 1,000
Preferred Stock, Dividends Per Share, Declared		$ 24.375	$ 24.375	$ 24.375
Common Stock [Member] | Mandatorily Redeemable Preferred Stock [Member]
Class of Stock [Line Items]
Conversion of Stock, Shares Converted					58,000,000

Common Equity (Details)

Common Equity (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 16, 2019	Jan. 02, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jul. 19, 2017	May 25, 2017	May 24, 2017	Jun. 12, 2015	Dec. 19, 2014
Class of Stock [Line Items]
Stock Repurchase Program, Authorized Amount						$ 2,000
Stock Repurchased During Period, Value			$ 273	$ 250
Dividends Per Common Share Declared for the Period			$ 0.8	$ 0.5	$ 0.5
Warrant Repurchase Program, Authorized Amount									$ 100
Unexercised Warrants							293,000,000
Class of Warrant or Right, Exercise Price of Warrants or Rights								$ 40
Class P
Class of Stock [Line Items]
Dividends Per Common Share Declared for the Period			0.80	0.50	0.50
Per common share cash dividend paid in the period			$ 0.725	$ 0.50	$ 0.50
Subsequent Event
Class of Stock [Line Items]
Stock Repurchased During Period, Value		$ 2
Dividends Per Common Share Declared for the Period	$ 0.20
Equity distribution agreement [Member] | 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]
Stock Repurchased During Period, Shares			15,000,000	14,000,000
Common stock | Subsequent Event
Class of Stock [Line Items]
Stock Repurchased During Period, Shares		100,000

Stockholders' Equity Noncontrol

Stockholders' Equity Noncontrolling Interests (Details) $ / shares in Units, $ in Millions, $ in Millions	Jan. 03, 2019USD ($)	Jan. 03, 2019CAD ($)	Dec. 08, 2017USD ($)shares	Dec. 08, 2017CAD ($)$ / sharesshares	Aug. 15, 2017USD ($)shares	Aug. 15, 2017CAD ($)$ / sharesshares	May 30, 2017shares	Dec. 31, 2018USD ($)$ / shares	Dec. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)shares	Dec. 31, 2017CAD ($)shares	Dec. 31, 2016USD ($)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest								$ 853	$ 853	$ 1,488
Dividends, Preferred Stock, Cash									128	156		$ 156
Kinder Morgan Canada Limited [Member]
Cash distributions paid in the period to the public									38	13
Value of Restricted Shares Issued in Lieu of Cash Dividends									$ 14	$ 5
Share distributions paid in the period to the public under KML’s DRIP | shares									1,092,791	418,989	418,989
Restricted Voting Shares in Public Offering [Member] | Kinder Morgan Canada Limited [Member]
Share issued (in shares) | shares							102,942,000
Restricted Voting Shares [Member] | Kinder Morgan Canada Limited [Member]
Total value of distributions paid in the period									$ 52	$ 18
Cumulative Redeemable Minimum Rate Reset Preferred Shares, Series 1 and 3 [Member] [Domain] | Kinder Morgan Canada Limited [Member]
Dividends, Preferred Stock, Cash									$ 21
Cumulative Redeemable Minimum Rate Reset Preferred Shares, Series 1 [Member] | Kinder Morgan Canada Limited [Member]
Share issued (in shares) | shares					12,000,000	12,000,000
Preferred Stock, Series 1 Offering Price, Per Share | $ / shares						$ 25
Proceeds from Issuance of Preferred Stock and Preference Stock					$ 235	$ 300
Net Proceeds from issuance of Preferred Stock										230	$ 293
Preferred Shares, Annualized Dividend Per Share | $ / shares								$ 1.3125
Dividends, Preferred Stock, Cash										3
Cumulative Redeemable Minimum Rate Reset Preferred Shares, Series 3 [Member] | Kinder Morgan Canada Limited [Member]
Share issued (in shares) | shares			10,000,000	10,000,000
Proceeds from Issuance of Preferred Stock and Preference Stock			$ 195	$ 250
Preferred Stock, Series 3 Offering Price, Per Share | $ / shares				$ 25
Net Proceeds from issuance of Preferred Stock										189	$ 243
Preferred Shares, Annualized Dividend Per Share | $ / shares								$ 1.3000
Minimum [Member] | Kinder Morgan Canada Limited [Member]
Market Discount for the Dividend Paid on Restricted Voting Shares									0.00%
Maximum [Member] | Kinder Morgan Canada Limited [Member]
Market Discount for the Dividend Paid on Restricted Voting Shares									5.00%
Subsequent Event
Payments to Noncontrolling Interests	$ 900	$ 1,200
Noncontrolling Interest [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest								$ 853	$ 853	1,488
Kinder Morgan Canada Limited [Member]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners							30.00%
Kinder Morgan Canada Limited Partnership [Member] | Noncontrolling Interest [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest								514	514	1,163
Others [Member] [Member] | Noncontrolling Interest [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest								$ 339	$ 339	$ 325

Related Party Transactions Affi

Related Party Transactions Affiliated Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
RELATED PARTY ASSETS
Accounts receivable, net	$ 48	$ 34
Other current assets	2	8
Deferred charges and other assets	55	23
Total Assets	105	65
RELATED PARTY LIABILITIES [Abstract]
Current portion of debt	6	6
Accounts payable	26	18
Other current liabilities	7	4
Long-term debt	148	155
Other long-term liabilities and deferred credits	34	35
Total Liabilities	221	218
RELATED PARTY REVENUES [Abstract]
Total Revenues	14,144	13,705	$ 13,058
RELATED PARTY COST OF SALES [Abstract]
Costs of sales	4,421	4,345	3,429
Other Operating Income (Expense), Net	3	1	1
Affiliated Entity [Member]
RELATED PARTY REVENUES [Abstract]
Total Revenues	265	162	142
RELATED PARTY COST OF SALES [Abstract]
Costs of sales	63	20	38
Other Operating Income (Expense), Net	(91)	(100)	(75)
Services [Member]
RELATED PARTY REVENUES [Abstract]
Total Revenues	7,931	7,901	8,146
Services [Member] | Affiliated Entity [Member]
RELATED PARTY REVENUES [Abstract]
Total Revenues	171	73	71
Revenues—Product sales and other
RELATED PARTY REVENUES [Abstract]
Total Revenues	2,932	2,751	2,458
Revenues—Product sales and other | Affiliated Entity [Member]
RELATED PARTY REVENUES [Abstract]
Total Revenues	$ 94	$ 89	$ 71

Related Party Transactions Note

Related Party Transactions Notes Receivable (Details)	Dec. 31, 2018
MEP
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Plantation Pipe Line Company
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	51.17%

Related Party Transactions Subs

Related Party Transactions Subsequent Event (Details)	Dec. 31, 2018
MEP
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	50.00%

Commitments and Contingent Li_3

Commitments and Contingent Liabilities Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 122
Operating Leases, Future Minimum Payments, Due in Two Years	107
Operating Leases, Future Minimum Payments, Due in Three Years	102
Operating Leases, Future Minimum Payments, Due in Four Years	97
Operating Leases, Future Minimum Payments, Due in Five Years	81
Operating Leases, Future Minimum Payments, Due Thereafter	353
Operating Leases, Future Minimum Payments Due	862
Operating Leases, Rent Expense	$ 155	$ 140	$ 138
Minimum [Member]
Operating Leased Assets [Line Items]
Lessee, Operating Lease, Term of Contract	1 year
Maximum [Member]
Operating Leased Assets [Line Items]
Lessee, Operating Lease, Term of Contract	35 years

Commitments and Contingent Li_4

Commitments and Contingent Liabilities Contingent Debt (Details) - Indirect Guarantee of Indebtedness [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 714	$ 1,070
Number of equity investees subject to contingent obligation	4	3
Cortez Pipeline Company
Guarantor Obligations [Line Items]
Percentage of Debt Guaranteed	50.00%
Cortez Expansion Capital Corp [Member]
Guarantor Obligations [Line Items]
Percentage of Debt Guaranteed	100.00%
Revolving Credit Facility [Member] | Cortez Pipeline Company
Guarantor Obligations [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 50
Revolving Credit Facility [Member] | Cortez Expansion Capital Corp [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	27
Senior Notes [Member] | Cortez Pipeline Company
Guarantor Obligations [Line Items]
Senior Notes	100
Notes Payable to Banks [Member] | Cortez Expansion Capital Corp [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 120

Energy Commodity Price Risk Man

Energy Commodity Price Risk Managment (Details) - Energy Related Derivative	Dec. 31, 2018MMBblsBcf
Designated as Hedging Instrument [Member] | Crude Oil Fixed Price [Member]
Derivative [Line Items]
Net Open Position Long/(Short)	(21.6)
Designated as Hedging Instrument [Member] | Crude Oil Basis [Member]
Derivative [Line Items]
Net Open Position Long/(Short)	(13.7)
Designated as Hedging Instrument [Member] | Natural Gas Fixed Price [Member]
Derivative [Line Items]
Net Open Position Long/(Short) | Bcf	(33.3)
Designated as Hedging Instrument [Member] | Natural Gas Basis [Member]
Derivative [Line Items]
Net Open Position Long/(Short) | Bcf	(26.1)
Not Designated as Hedging Instrument [Member] | Crude Oil Fixed Price [Member]
Derivative [Line Items]
Net Open Position Long/(Short)	(0.5)
Not Designated as Hedging Instrument [Member] | Crude Oil Basis [Member]
Derivative [Line Items]
Net Open Position Long/(Short)	(4.5)
Not Designated as Hedging Instrument [Member] | Natural Gas Fixed Price [Member]
Derivative [Line Items]
Net Open Position Long/(Short) | Bcf	(4.5)
Not Designated as Hedging Instrument [Member] | Natural Gas Basis [Member]
Derivative [Line Items]
Net Open Position Long/(Short) | Bcf	(26.9)
Not Designated as Hedging Instrument [Member] | NGL and other fixed price
Derivative [Line Items]
Net Open Position Long/(Short)	(3.2)

Interest Rate Risk Managment (D

Interest Rate Risk Managment (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value Hedging [Member] | Interest rate contract
Derivative [Line Items]
Derivative, Notional Amount	$ 10,575	$ 9,575

Risk Management Foreign Currenc

Risk Management Foreign Currency Risk Management (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017
Derivative [Line Items]
Cross-currency Swap Agreements	$ 1,358
KMI 1.50% Senior Notes Due 2022 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.50%	1.50%	1.50%
Debt Instrument, Term	7 years
KMI 2.25% Senior Notes Due 2027 [Member]
Derivative [Line Items]
Debt Instrument, Term	12 years
Currency Swap [Member] | KMI 1.50% Senior Notes Due 2022 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.79%	3.79%
Currency Swap [Member] | KMI 2.25% Senior Notes Due 2027 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.67%	4.67%
Net Investment Hedging [Member] | Currency Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 1,888	$ 2,450

Risk Management Fair Value of D

Risk Management Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Asset derivatives	$ 551	$ 458
Liability derivatives	(171)	(172)
Energy Related Derivative
Derivatives, Fair Value [Line Items]
Asset derivatives	157	33
Liability derivatives	(11)	(59)
Interest rate contract
Derivatives, Fair Value [Line Items]
Asset derivatives	126	190
Liability derivatives	(108)	(50)
Currency Swap [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	191	160
Liability derivatives	0	0
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	529	450
Liability derivatives	(166)	(148)
Designated as Hedging Instrument [Member] | Energy Related Derivative
Derivatives, Fair Value [Line Items]
Asset derivatives	199	79
Liability derivatives	(45)	(77)
Designated as Hedging Instrument [Member] | Energy Related Derivative | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	135	65
Designated as Hedging Instrument [Member] | Energy Related Derivative | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(45)	(53)
Designated as Hedging Instrument [Member] | Energy Related Derivative | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	64	14
Designated as Hedging Instrument [Member] | Energy Related Derivative | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	0	(24)
Designated as Hedging Instrument [Member] | Interest rate contract
Derivatives, Fair Value [Line Items]
Asset derivatives	133	205
Liability derivatives	(115)	(65)
Designated as Hedging Instrument [Member] | Interest rate contract | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	12	41
Designated as Hedging Instrument [Member] | Interest rate contract | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(37)	(3)
Designated as Hedging Instrument [Member] | Interest rate contract | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	121	164
Designated as Hedging Instrument [Member] | Interest rate contract | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(78)	(62)
Designated as Hedging Instrument [Member] | Currency Swap [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	197	166
Liability derivatives	(6)	(6)
Designated as Hedging Instrument [Member] | Currency Swap [Member] | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	91	0
Designated as Hedging Instrument [Member] | Currency Swap [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(6)	(6)
Designated as Hedging Instrument [Member] | Currency Swap [Member] | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	106	166
Designated as Hedging Instrument [Member] | Currency Swap [Member] | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	0	0
Not Designated as Hedging Instrument [Member] | Energy Related Derivative | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	22	8
Not Designated as Hedging Instrument [Member] | Energy Related Derivative | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(5)	(22)
Not Designated as Hedging Instrument [Member] | Energy Related Derivative | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Not Designated as Hedging Instrument [Member] | Energy Related Derivative | Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	0	(2)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	22	8
Liability derivatives	$ (5)	$ (24)

Risk Management FV Hedging Effe

Risk Management FV Hedging Effect on Income Statements Location (Details) - Designated as Hedging Instrument [Member] - Fair Value Hedging [Member] - Interest Expense [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Interest Rate Contract
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ (122)	$ (103)	$ (180)
Hedged Fixed Rate Debt
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 113	$ 105	$ 160

Risk Management Effect of Deriv

Risk Management Effect of Derivative Contracts on the Income Statement (Details) - Designated as Hedging Instrument [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative (effective portion)(a)	$ 145	$ 227	$ (164)
Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)	(109)	268	183
Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	(65)	11	(12)
Loss to be reclassified within twelve months	165
Net Investment Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)	26	0	0
Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	0	0	0
Interest rate contract | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative (effective portion)(a)	3	0	(3)
Interest rate contract | Earnings from Equity Investments [Member] | Cash Flow Hedging [Member]
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 contract | Interest Expense [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)	(4)	(5)	(4)
Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	0	0	0
Interest rate contract | Costs of sales | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Inventory Write-down	21
Energy commodity derivative contracts(a) | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative (effective portion)(a)	201	37	(182)
Energy commodity derivative contracts(a) | Revenues—Natural gas sales | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)	(29)	18	23
Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	0	0	0
Energy commodity derivative contracts(a) | Revenues—Product sales and other | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)	(30)	55	233
Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	(65)	11	(12)
Energy commodity derivative contracts(a) | Costs of sales | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)	21	14	(26)
Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	0	0	0
Currency Swap [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) recognized in OCI on derivative (effective portion)(a)	(59)	190	21
Currency Swap [Member] | Other Nonoperating Income (Expense) [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)	(67)	186	(43)
Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	$ 0	$ 0	$ 0

Risk Management Derivative in N

Risk Management Derivative in Net Investment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Foreign currency contracts	$ 111	$ 145	$ (104)
Net Investment Hedging [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Loss on impairments and divestitures, net	26	0	0
Other, net	0	0	0
Net Investment Hedging [Member] | Other Comprehensive Income (Loss) | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Foreign currency contracts	91	0	0
Net Investment Hedging [Member] | Other Comprehensive Income (Loss) | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member]
Derivative [Line Items]
Foreign currency contracts	91	0	0
(Gain) loss on divestitures and impairments, net | Net Investment Hedging [Member] | Designated as Hedging Instrument [Member] | Currency Swap [Member]
Derivative [Line Items]
Loss on impairments and divestitures, net	26
(Gain) loss on divestitures and impairments, net | Net Investment Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member]
Derivative [Line Items]
Loss on impairments and divestitures, net	26	0	0
Other Nonoperating Income (Expense) [Member] | Net Investment Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member]
Derivative [Line Items]
Other, net	$ 0	$ 0	$ 0

Risk Management Not Designated

Risk Management Not Designated as Hedges Location Effect on Income Statements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (7)	$ 4	$ 30
Energy Related Derivative
Derivative [Line Items]
Loss on Derivative Instruments, Pretax	4
Derivative, Gain on Derivative		57	73
Revenues—Natural gas sales | Energy Related Derivative
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3	20	(10)
Revenues—Product sales and other | Energy Related Derivative
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(12)	(16)	(26)
Cost of Sales [Member] | Energy Related Derivative
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	2	0	3
Interest Expense [Member] | Interest Rate Contract
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	$ 0	$ 63
Other Current Liabilities [Member] | Contract and Over the Counter | Energy Related Derivative
Derivative [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 16

Risk Management Credit Risks (D

Risk Management Credit Risks (Details) - Energy Related Derivative - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Credit Derivatives [Line Items]
Letters of Credit Outstanding, Amount	$ 0
Initial Margin Requirements	9
Variation Margin Requirements	25
Other Current Liabilities [Member] | Contract and Over the Counter
Credit Derivatives [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 16
Restricted Deposit [Member] | Contract and Over the Counter
Credit Derivatives [Line Items]
Derivative, Collateral, Right to Reclaim Cash		$ 1

Risk Management Risk Management

Risk Management Risk Management Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	Jan. 01, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income [Roll Forward]
Accumulated other comprehensive loss, beginning of period	$ (541)	$ (541)	$ (661)	$ (461)
OCI, before Reclassifications, Net of Tax, Attributable to Parent		(9)	240	(84)
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		329	(171)	(116)
Other Comprehensive Income, KML IPO			51
Impact of adoption of ASU 2018-02	66	(109)
Net current-period other comprehensive (loss) income		211	120	(200)
Accumulated other comprehensive loss, end of period		(330)	(541)	(661)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax, begiining of period	(27)	(27)	(1)	219
OCI, before Reclassifications, Net of Tax, Attributable to Parent		111	145	(104)
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		84	(171)	(116)
Other Comprehensive Income, KML IPO			0
Impact of adoption of ASU 2018-02		(4)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax, Portion Attributable to Parent		191	(26)	(220)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax, end of period		164	(27)	(1)
Accumulated Foreign Currency Adjustment Attributable to Parent [Member]
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Net of Tax, beginning of period	(189)	(189)	(288)	(322)
OCI, before Reclassifications, Net of Tax, Attributable to Parent		(89)	55	34
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		223	0	0
Other Comprehensive Income, KML IPO			44
Impact of adoption of ASU 2018-02		(36)
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax, Portion Attributable to Parent		98	99	34
Accumulated Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Net of Tax, end of period		(91)	(189)	(288)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income [Roll Forward]
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, beginning of period	$ (325)	(325)	(372)	(358)
OCI, before Reclassifications, Net of Tax, Attributable to Parent		(31)	40	(14)
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		22	0	0
Other Comprehensive Income, KML IPO			7
Impact of adoption of ASU 2018-02		(69)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax and Reclassification Adjustment, Attributable to Parent		(78)	47	(14)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, end of period		$ (403)	$ (325)	$ (372)

Fair Value of Derivative Contra

Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ 551	$ 458
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(171)	(172)
Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	221	87
Derivative Asset, Contracts Available for Netting	(39)	(42)
Derivative, Collateral, Obligation to Return Cash, Variation Margin	(25)	(12)
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	157	33
Derivative Liability, Fair Value, Gross Liability	(50)	(101)
Derivative Liability, Not Offset, Policy Election Deduction	39	42
Derivative, Collateral, Right to Reclaim Cash, Variation Margins	0	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(11)	(59)
Interest rate contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	133	205
Derivative Asset, Contracts Available for Netting	(7)	(15)
Derivative, Collateral, Obligation to Return Cash, Variation Margin	0	0
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	126	190
Derivative Liability, Fair Value, Gross Liability	(115)	(65)
Derivative Liability, Not Offset, Policy Election Deduction	7	15
Derivative, Collateral, Right to Reclaim Cash, Variation Margins	0	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(108)	(50)
Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	197	166
Derivative Asset, Contracts Available for Netting	(6)	(6)
Derivative, Collateral, Obligation to Return Cash, Variation Margin	0	0
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	191	160
Derivative Liability, Fair Value, Gross Liability	(6)	(6)
Derivative Liability, Not Offset, Policy Election Deduction	6	6
Derivative, Collateral, Right to Reclaim Cash, Variation Margins	0	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	0
Quoted prices in active markets for identical assets (Level 1) [Member] | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	28	17
Derivative Liability, Fair Value, Gross Liability	(11)	(3)
Quoted prices in active markets for identical assets (Level 1) [Member] | Interest rate contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	0
Quoted prices in active markets for identical assets (Level 1) [Member] | Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 2 [Member] | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	193	70
Derivative Liability, Fair Value, Gross Liability	(39)	(98)
Fair Value, Inputs, Level 2 [Member] | Interest rate contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	133	205
Derivative Liability, Fair Value, Gross Liability	(115)	(65)
Fair Value, Inputs, Level 2 [Member] | Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	197	166
Derivative Liability, Fair Value, Gross Liability	(6)	(6)
Significant unobservable inputs (Level 3) [Member] | Energy Related Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	0
Significant unobservable inputs (Level 3) [Member] | Interest rate contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	0
Significant unobservable inputs (Level 3) [Member] | Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	$ 0	$ 0

Fair Value of Debt (Details)

Fair Value of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 731	$ 927
Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	37,324	37,843
Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 37,469	$ 40,050

Revenue Recognition Schedule of

Revenue Recognition Schedule of Impact to Consolidated Financial Statement Line Items (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	$ 14,144	$ 13,705	$ 13,058
Costs of sales	4,421	4,345	3,429
Operating Income	3,794	3,529	3,538
Natural gas sales [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	3,281	3,053	2,454
Services [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	7,931	7,901	8,146
Product sales and other [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	2,932	$ 2,751	$ 2,458
Accounting Standards Update 2014-09 [Member] | Amounts Without Adoption of Topic 606 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	14,743
Costs of sales	5,020
Operating Income	3,794
Accounting Standards Update 2014-09 [Member] | Amounts Without Adoption of Topic 606 [Member] | Natural gas sales [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	3,339
Accounting Standards Update 2014-09 [Member] | Amounts Without Adoption of Topic 606 [Member] | Services [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	8,134
Accounting Standards Update 2014-09 [Member] | Amounts Without Adoption of Topic 606 [Member] | Product sales and other [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	3,270
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase/(Decrease) [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	(599)
Costs of sales	(599)
Operating Income	0
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase/(Decrease) [Member] | Natural gas sales [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	(58)
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase/(Decrease) [Member] | Services [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	(203)
Accounting Standards Update 2014-09 [Member] | Effect of Change Increase/(Decrease) [Member] | Product sales and other [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total Revenues	$ (338)

Revenue Recognition Schedule _2

Revenue Recognition Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 13,318
Total Revenues	14,144	$ 13,705	$ 13,058
Firm services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,746
Fee-based services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,466
Total services revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	7,212
Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,310
Total Revenues	3,281	3,053	2,454
Product sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,788
Other sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	8
Total sales revenues [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,106
Other revenues [Member]
Disaggregation of Revenue [Line Items]
Total Revenues	826
Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	8,735
Total Revenues	9,015
Natural Gas Pipelines | Firm services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,215
Natural Gas Pipelines | Fee-based services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	860
Natural Gas Pipelines | Total services revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,075
Natural Gas Pipelines | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3,319
Natural Gas Pipelines | Product sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,333
Natural Gas Pipelines | Other sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	8
Natural Gas Pipelines | Total sales revenues [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,660
Natural Gas Pipelines | Other revenues [Member]
Disaggregation of Revenue [Line Items]
Total Revenues	280
Products Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,573
Total Revenues	1,713
Products Pipelines | Firm services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	566
Products Pipelines | Fee-based services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	791
Products Pipelines | Total services revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,357
Products Pipelines | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Products Pipelines | Product sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	216
Products Pipelines | Other sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Products Pipelines | Total sales revenues [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	216
Products Pipelines | Other revenues [Member]
Disaggregation of Revenue [Line Items]
Total Revenues	140
Terminals
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,575
Total Revenues	2,019
Terminals | Firm services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	976
Terminals | Fee-based services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	581
Terminals | Total services revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,557
Terminals | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Terminals | Product sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	18
Terminals | Other sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Terminals | Total sales revenues [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	18
Terminals | Other revenues [Member]
Disaggregation of Revenue [Line Items]
Total Revenues	444
CO2
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,293
Total Revenues	1,255
CO2 | Firm services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2
CO2 | Fee-based services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	67
CO2 | Total services revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	69
CO2 | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2
CO2 | Product sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,222
CO2 | Other sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
CO2 | Total sales revenues [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,224
CO2 | Other revenues [Member]
Disaggregation of Revenue [Line Items]
Total Revenues	(38)
Kinder Morgan Canada
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	167
Total Revenues	170
Kinder Morgan Canada | Firm services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Kinder Morgan Canada | Fee-based services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	167
Kinder Morgan Canada | Total services revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	167
Kinder Morgan Canada | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Kinder Morgan Canada | Product sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Kinder Morgan Canada | Other sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Kinder Morgan Canada | Total sales revenues [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Kinder Morgan Canada | Other revenues [Member]
Disaggregation of Revenue [Line Items]
Total Revenues	3
Corporate, Non-Segment and intersegment eliminations
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(25)
Total Revenues	(28)	$ 8	$ 8
Corporate, Non-Segment and intersegment eliminations | Firm services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(13)
Corporate, Non-Segment and intersegment eliminations | Fee-based services [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Corporate, Non-Segment and intersegment eliminations | Total services revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(13)
Corporate, Non-Segment and intersegment eliminations | Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(11)
Corporate, Non-Segment and intersegment eliminations | Product sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(1)
Corporate, Non-Segment and intersegment eliminations | Other sales [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Corporate, Non-Segment and intersegment eliminations | Total sales revenues [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(12)
Corporate, Non-Segment and intersegment eliminations | Other revenues [Member]
Disaggregation of Revenue [Line Items]
Total Revenues	$ (3)

Revenue Recognition Activity in

Revenue Recognition Activity in Contract Assets and Liabilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Contract Assets
Balance, beginning of period	$ 32
Additions	59
Transfer to Accounts receivable	(67)
Balance, end of period	24
Contract Liabilities
Balance, beginning of period	206
Additions	453
Transfer to Revenues	(360)
Other	(7)
Balance, end of period	292
Contract assets included in Other current assets	14
Contract assets included in Deferred charges and other assets	10
Contract liabilities included in Other current liabilities	80
Contract liabilities included in Other long-term liabilities and deferred credits	$ 212

Revenue Recognition Revenue All

Revenue Recognition Revenue Allocated to Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue allocated to remaining performance obligations for contracted revenue	$ 32,237
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	1 year
Revenue allocated to remaining performance obligations for contracted revenue	$ 4,881
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, period of recognition	2 years
Revenue allocated to remaining performance obligations for contracted revenue	$ 4,182
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	3 years
Revenue allocated to remaining performance obligations for contracted revenue	$ 3,528
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	4 years
Revenue allocated to remaining performance obligations for contracted revenue	$ 3,011
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	5 years
Revenue allocated to remaining performance obligations for contracted revenue	$ 2,497
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
Revenue allocated to remaining performance obligations for contracted revenue	$ 14,138

Reportable Segments Revenues (D

Reportable Segments Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues
Revenues	$ 14,144	$ 13,705	$ 13,058
Natural Gas Pipelines
Revenues
Revenues	9,015
Products Pipelines
Revenues
Revenues	1,713
Terminals
Revenues
Revenues	2,019
CO2
Revenues
Revenues	1,255
Kinder Morgan Canada
Revenues
Revenues	170
Single customer exceeding 10% of total [Member]
Revenues
Revenues	0	0	0
Operating Segments | Products Pipelines
Revenues
Revenues	1,699	1,645	1,631
Operating Segments | Kinder Morgan Canada
Revenues
Revenues	170	256	253
Operating Segments | External Customer [Member] | Natural Gas Pipelines
Revenues
Revenues	9,004	8,608	7,998
Operating Segments | External Customer [Member] | Terminals
Revenues
Revenues	2,017	1,965	1,921
Operating Segments | External Customer [Member] | CO2
Revenues
Revenues	1,255	1,196	1,221
Operating Segments | Intersegment revenues | Natural Gas Pipelines
Revenues
Revenues	11	10	7
Operating Segments | Intersegment revenues | Products Pipelines
Revenues
Revenues	14	16	18
Operating Segments | Intersegment revenues | Terminals
Revenues
Revenues	2	1	1
Corporate, Non-Segment and intersegment eliminations
Revenues
Revenues	$ (28)	$ 8	$ 8
Revenues from External Customers [Member]
Revenues
Concentration Risk, Percentage	10.00%	10.00%	10.00%
Affiliated Entity [Member]
Revenues
Revenues	$ 265	$ 162	$ 142
Affiliated Entity [Member] | Corporate, Non-Segment and intersegment eliminations
Revenues
Revenues		$ 35	$ 34

Reportable Segments Operating e

Reportable Segments Operating expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Operating expenses(b)	$ 7,288	$ 7,215	$ 6,222
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Operating expenses(b)	5,353	5,457	4,393
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Operating expenses(b)	594	487	573
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Operating expenses(b)	818	788	768
Operating Segments | CO2
Segment Reporting Information [Line Items]
Operating expenses(b)	453	394	399
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Operating expenses(b)	72	95	87
Corporate, Non-Segment and intersegment eliminations
Segment Reporting Information [Line Items]
Operating expenses(b)	$ (2)	$ (6)	$ 2

Reportable Segments Other expen

Reportable Segments Other expense (income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Other expense (income)(c)	$ 164	$ 12	$ 386
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other expense (income)(c)	593	26	199
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Other expense (income)(c)	34	0	76
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Other expense (income)(c)	54	(14)	99
Operating Segments | CO2
Segment Reporting Information [Line Items]
Other expense (income)(c)	79	(1)	19
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Other expense (income)(c)	(596)	0	0
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Other expense (income)(c)	$ 0	$ 1	$ (7)

Reportable Segments Depreciatio

Reportable Segments Depreciation, depletion and amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
DD&A	$ 2,297	$ 2,261	$ 2,209
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
DD&A	1,058	1,011	1,041
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
DD&A	228	216	221
Operating Segments | Terminals
Segment Reporting Information [Line Items]
DD&A	484	472	435
Operating Segments | CO2
Segment Reporting Information [Line Items]
DD&A	473	493	446
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
DD&A	29	46	44
Corporate, Non-Segment
Segment Reporting Information [Line Items]
DD&A	$ 25	$ 23	$ 22

Reportable Segments Earnings (l

Reportable Segments Earnings (loss) from equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	$ 522	$ 367	$ (172)
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	391	253	(269)
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	75	48	56
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	22	24	19
Operating Segments | CO2
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	$ 34	$ 42	$ 22

Reportable Segments Other, net-

Reportable Segments Other, net-income(expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Other, net	$ 107	$ 97	$ 78
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other, net	37	49	19
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Other, net	3	(1)	2
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Other, net	2	8	4
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Other, net	26	25	15
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Other, net	$ 39	$ 16	$ 38

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
DD&A	$ (2,297)	$ (2,261)	$ (2,209)
Amortization of excess cost of equity investments	(95)	(61)	(59)
General and administrative and corporate charges	(601)	(688)	(703)
Interest, net	(1,917)	(1,832)	(1,806)
Income tax expense	(587)	(1,938)	(917)
Net Income	1,919	223	721
Total segment EBDA
Segment Reporting Information [Line Items]
Segment EBDA(d)	7,403	6,975	6,364
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(d)	3,580	3,487	3,211
DD&A	(1,058)	(1,011)	(1,041)
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(d)	1,173	1,231	1,067
DD&A	(228)	(216)	(221)
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Segment EBDA(d)	1,171	1,224	1,078
DD&A	(484)	(472)	(435)
Operating Segments | CO2
Segment Reporting Information [Line Items]
Segment EBDA(d)	759	847	827
DD&A	(473)	(493)	(446)
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Segment EBDA(d)	720	186	181
DD&A	(29)	(46)	(44)
Corporate, Non-Segment
Segment Reporting Information [Line Items]
DD&A	(25)	(23)	(22)
General and administrative and corporate charges	$ (588)	$ (660)	$ (652)

Reportable Segments Capital exp

Reportable Segments Capital expenditures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Capital expenditures	$ 2,904	$ 3,188	$ 2,882
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	1,620	1,376	1,227
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	150	127	244
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Capital expenditures	380	888	983
Operating Segments | CO2
Segment Reporting Information [Line Items]
Capital expenditures	397	436	276
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Capital expenditures	332	338	124
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Capital expenditures	$ 25	$ 23	$ 28

Reportable Segments Investments

Reportable Segments Investments (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Investments	$ 7,481	$ 7,298
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments	6,358	6,218
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Investments	839	777
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Investments	268	263
Operating Segments | CO2
Segment Reporting Information [Line Items]
Investments	16	6
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Investments	$ 0	$ 34

Reportable Segments Assets (Det

Reportable Segments Assets (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Assets at December 31	$ 78,866	$ 79,055
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Assets at December 31	5,664	3,382
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets at December 31	51,562	51,173
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Assets at December 31	8,429	8,539
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Assets at December 31	9,283	9,935
Operating Segments | CO2
Segment Reporting Information [Line Items]
Assets at December 31	3,928	3,946
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Assets at December 31	$ 0	$ 2,080

Reportable Segments Geographica

Reportable Segments Geographical information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total Revenues	$ 14,144	$ 13,705	$ 13,058
Long-term assets, excluding goodwill and other intangibles	48,299	51,079	51,606
U.S.
Segment Reporting Information [Line Items]
Total Revenues	13,596	13,073	12,459
Long-term assets, excluding goodwill and other intangibles	47,468	47,928	49,125
Canada
Segment Reporting Information [Line Items]
Total Revenues	447	503	483
Long-term assets, excluding goodwill and other intangibles	748	3,071	2,399
Mexico and other foreign
Segment Reporting Information [Line Items]
Total Revenues	101	129	116
Long-term assets, excluding goodwill and other intangibles	$ 83	$ 80	$ 82

Litigation, Environmental and_2

Litigation, Environmental and Other Contingencies Federal Energy Regulatory Commission Proceedings (Details) - Federal Energy Regulatory Commission [Member] - Various Shippers [Member] - Unfavorable Regulatory Action [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
EPNG [Member] | Opinion 517 issued and implemented (rehearing pending); and Opinion 528 issued. [Member]
EPNG [Abstract]
Loss Contingency, Pending Claims, Number	2
Annual Rate Reductions [Member] | SFPP [Member] | Pending Litigation [Member]
SFPP [Abstract]
Loss Contingency, Damages Sought, Value	$ 30
Revenue Subject to Refund [Member] | SFPP [Member] | Pending Litigation [Member]
SFPP [Abstract]
Loss Contingency, Damages Sought, Value	$ 330

Litigation, Environmental and_3

Litigation, Environmental and Other Contingencies Other Commercial Matters (Details) $ in Millions	May 24, 2016USD ($)	Nov. 30, 2017USD ($)	Apr. 30, 2017USD ($)	Dec. 31, 2018
Brinckerhoff Merger [Member]
Loss Contingencies [Line Items]
Payments to Acquire Businesses, Gross			$ 9,200
Brinckerhoff Merger [Member] | Dismissed [Member] | Attorneys' fee [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value		$ 44
Price Reporting Litigation [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number				2
KANSAS | Price Reporting Litigation [Member] | Dismissed [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 500
WISCONSIN | Price Reporting Litigation [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 300

Litigation, Environmental and_4

Litigation, Environmental and Other Contingencies Litigation General (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Loss Contingency, Information about Litigation Matters [Abstract]
Estimated Litigation Liability	$ 207	$ 350

Litigation, Environmental and_5

Litigation, Environmental and Other Contingencies Environmental Matters (Details)

May 04, 2018USD ($)a

Oct. 05, 2016USD ($)

Jun. 08, 2016USD ($)

Dec. 18, 2015USD ($)

Nov. 08, 2013

Aug. 06, 2013Defendants

Dec. 31, 2010USD ($)Defendants

Dec. 31, 2000Terminals

Dec. 31, 2018USD ($)aTerminalsmiDefendantsParties

Dec. 31, 1969

Dec. 31, 2017USD ($)

Jan. 06, 2017USD ($)

Loss Contingencies [Line Items]

Accrual for Environmental Loss Contingencies

$ 271,000,000

$ 279,000,000

Recorded Third-Party Environmental Recoveries Receivable

$ 13,000,000

$ 13,000,000

Rare Metals Inc. [Member]

Loss Contingencies [Line Items]

Number of Uranium Mines

20

Environmental Protection Agency [Member] | Portland Harbor Superfund Site, Willamette River, Portland, Oregon [Member] | GATX Terminals Corporation (n/k/a KMLT) [Member]

Loss Contingencies [Line Items]

Estimated Remedy Implementation Period

13 years

Number of Liquid Terminals | Terminals

2

4

Accrual for Environmental Loss Contingencies, Gross

$ 750,000,000

$ 1,100,000,000

Number of Parties Involoved In Site Cleanup | Parties

90

Parish of Plaquemines, Louisiana [Member] | Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish [Member] | TGP [Member]

Loss Contingencies [Line Items]

Loss Contingency, Number of Defendants

17

Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona [Member] | Pending Litigation [Member] | SFPP Phoenix Terminal [Member] | Unfavorable Regulatory Action [Member] | KMEP and SFPP [Member]

Loss Contingencies [Line Items]

Loss Contingency, Number of Defendants | Defendants

26

70

Loss Contingency, Damages Sought, Value

$ 175,000,000

Lower Passaic River Study Area | Pending Litigation [Member]

Loss Contingencies [Line Items]

Miles of river | mi

17

Number of Parties at a Joint Defense Group

44

Lower Passaic River Study Area, Lower Portion [Member] | Pending Litigation [Member]

Loss Contingencies [Line Items]

Miles of river | mi

8

Vintage Assets Inc. [Member] | Parish of Plaquemines, Louisiana [Member] | TGP and SNG [Member]

Loss Contingencies [Line Items]

Loss Contingency, Damages Sought, Value

$ 80,000,000

Restore acreage | a

9.6

Percent of legal expenses reimbursed by current property owner

50.00%

Loss Contingency, Damages Awarded, Value

$ 1,104

Area of Land | a

5,000

Minimum [Member] | Lower Passaic River Study Area | Pending Litigation [Member]

Loss Contingencies [Line Items]

Accrual for Environmental Loss Contingencies, Gross

$ 365,000,000

Maximum [Member] | Lower Passaic River Study Area | Pending Litigation [Member]

Loss Contingencies [Line Items]

Accrual for Environmental Loss Contingencies, Gross

$ 3,200,000,000

AOC required engineering and design work [Member] | Lower Passaic River Study Area | Pending Litigation [Member]

Loss Contingencies [Line Items]

Environmental Remediation Expense

$ 165,000,000

Loss Contingency, Number of Defendants | Defendants

120

Loss Contingency, Pending Claims, Number

2

Design [Member] | Lower Passaic River Study Area | Pending Litigation [Member]

Loss Contingencies [Line Items]

Estimated Remedy Implementation Period

4 years

Clean Up Implementation [Member] | Lower Passaic River Study Area | Pending Litigation [Member]

Loss Contingencies [Line Items]

Estimated Remedy Implementation Period

6 years

EPA preferred alternative estimate [Member] | Lower Passaic River Study Area | Pending Litigation [Member]

Loss Contingencies [Line Items]

Environmental Remediation Expense

$ 1,700,000,000

Litigation, Environmental and_6

Litigation, Environmental and Other Contingencies Litigation Other Contingency (Details) $ in Millions	Dec. 31, 2018CAD ($)
Government of Canada [Member] | Trans Mountain,Trans Mountain Expansion Project and Other Related Assets [Member] | Backstop [Member]
Letters of Credit Outstanding, Amount	$ 500
Commitments to Extend Credit [Member] | Trans Mountain and Trans Mountain Expansion Project [Member]
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases	$ 500

Recent Accounting Pronoucemen_2

Recent Accounting Pronoucements (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Assets	$ 78,866	$ 79,055
Liabilities	43,669	$ 43,931
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Assets	500
Liabilities	$ 500

Guarantee of Securities of Su_2

Guarantee of Securities of Subsidiaries Guarantee of Securities of Subsidiaries (Details) $ in Millions	Dec. 31, 2018USD ($)
Parent Issuer and Guarantor
Total debt - KMI and Subsidiaries	$ 15,192
Subsidiary Issuer and Guarantor - KMP
Total debt - KMI and Subsidiaries	17,910
Subsidiary Guarantors
Total debt - KMI and Subsidiaries	2,535
Capitalized Lease Debt Not Subject to Cross Guarantee Agreement	$ 159

Guarantee of Securities of Su_3

Guarantee of Securities of Subsidiaries Income Statement and Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Guarantor Obligations [Line Items]
Total Revenues	$ 14,144	$ 13,705	$ 13,058
Costs of sales	4,421	4,345	3,429
Depreciation, depletion and amortization	2,297	2,261	2,209
Other operating expenses	(3)	(1)	(1)
Total Operating Costs, Expenses and Other	10,350	10,176	9,520
Operating Income	3,794	3,529	3,538
Earnings from equity investments	887	578	497
Interest, net	(1,917)	(1,832)	(1,806)
Amortization of excess cost of equity investments and other, net	107	97	78
Income Before Income Taxes	2,506	2,161	1,638
Income Tax Expense	(587)	(1,938)	(917)
Net Income	1,919	223	721
Net Income Attributable to Noncontrolling Interests	(310)	(40)	(13)
Net Income Attributable to Kinder Morgan, Inc.	1,609	183	708
Preferred Stock Dividends	(128)	(156)	(156)
Net Income Available to Common Stockholders	1,481	27	552
Total other comprehensive (loss) income	338	115	(200)
Comprehensive income	2,257	338	521
Comprehensive income attributable to noncontrolling interests	(328)	(86)	(13)
Comprehensive income attributable to KMI	1,929	252	508
Parent Issuer and Guarantor
Guarantor Obligations [Line Items]
Total Revenues	0	35	34
Costs of sales	0	0	0
Depreciation, depletion and amortization	19	16	18
Other operating expenses	(39)	78	758
Total Operating Costs, Expenses and Other	(20)	94	776
Operating Income	20	(59)	(742)
Earnings from consolidated subsidiaries	2,760	3,575	2,948
Earnings from equity investments	0	0	0
Interest, net	(780)	(701)	(696)
Amortization of excess cost of equity investments and other, net	27	2	33
Income Before Income Taxes	2,027	2,817	1,543
Income Tax Expense	(418)	(2,634)	(835)
Net Income	1,609	183	708
Net Income Attributable to Noncontrolling Interests	0	0	0
Net Income Attributable to Kinder Morgan, Inc.	1,609	183	708
Preferred Stock Dividends	(128)	(156)	(156)
Net Income Available to Common Stockholders	1,481	27	552
Total other comprehensive (loss) income	320	69	(200)
Comprehensive income	1,929	252	508
Comprehensive income attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to KMI	1,929	252	508
Subsidiary Issuer and Guarantor - KMP
Guarantor Obligations [Line Items]
Total Revenues	0	0	0
Costs of sales	0	0	0
Depreciation, depletion and amortization	0	0	0
Other operating expenses	1	1	(36)
Total Operating Costs, Expenses and Other	1	1	(36)
Operating Income	(1)	(1)	36
Earnings from consolidated subsidiaries	2,533	2,681	2,802
Earnings from equity investments	0	0	0
Interest, net	(8)	7	90
Amortization of excess cost of equity investments and other, net	0	0	0
Income Before Income Taxes	2,524	2,687	2,928
Income Tax Expense	68	(5)	(5)
Net Income	2,592	2,682	2,923
Net Income Attributable to Noncontrolling Interests	0	0	0
Net Income Attributable to Kinder Morgan, Inc.	2,592	2,682	2,923
Preferred Stock Dividends	0	0	0
Net Income Available to Common Stockholders	2,592	2,682	2,923
Total other comprehensive (loss) income	290	194	(341)
Comprehensive income	2,882	2,876	2,582
Comprehensive income attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to KMI	2,882	2,876	2,582
Subsidiary Guarantors
Guarantor Obligations [Line Items]
Total Revenues	12,767	12,202	11,572
Costs of sales	4,247	4,124	3,176
Depreciation, depletion and amortization	1,971	1,933	1,872
Other operating expenses	3,693	3,014	2,461
Total Operating Costs, Expenses and Other	9,911	9,071	7,509
Operating Income	2,856	3,131	4,063
Earnings from consolidated subsidiaries	599	419	245
Earnings from equity investments	617	428	(113)
Interest, net	(1,090)	(1,104)	(1,149)
Amortization of excess cost of equity investments and other, net	(18)	13	(18)
Income Before Income Taxes	2,964	2,887	3,028
Income Tax Expense	(61)	237	(33)
Net Income	2,903	3,124	2,995
Net Income Attributable to Noncontrolling Interests	0	0	0
Net Income Attributable to Kinder Morgan, Inc.	2,903	3,124	2,995
Preferred Stock Dividends	0	0	0
Net Income Available to Common Stockholders	2,903	3,124	2,995
Total other comprehensive (loss) income	280	217	(352)
Comprehensive income	3,183	3,341	2,643
Comprehensive income attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to KMI	3,183	3,341	2,643
Subsidiary Non-Guarantors
Guarantor Obligations [Line Items]
Total Revenues	1,526	1,614	1,511
Costs of sales	277	322	266
Depreciation, depletion and amortization	307	312	319
Other operating expenses	23	522	745
Total Operating Costs, Expenses and Other	607	1,156	1,330
Operating Income	919	458	181
Earnings from consolidated subsidiaries	62	59	58
Earnings from equity investments	0	0	0
Interest, net	(39)	(34)	(51)
Amortization of excess cost of equity investments and other, net	3	21	4
Income Before Income Taxes	945	504	192
Income Tax Expense	(176)	464	(44)
Net Income	769	968	148
Net Income Attributable to Noncontrolling Interests	0	0	0
Net Income Attributable to Kinder Morgan, Inc.	769	968	148
Preferred Stock Dividends	0	0	0
Net Income Available to Common Stockholders	769	968	148
Total other comprehensive (loss) income	136	160	55
Comprehensive income	905	1,128	203
Comprehensive income attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to KMI	905	1,128	203
Consolidated KMI
Guarantor Obligations [Line Items]
Total Revenues	14,144	13,705	13,058
Costs of sales	4,421	4,345	3,429
Depreciation, depletion and amortization	2,297	2,261	2,209
Other operating expenses	3,632	3,570	3,882
Total Operating Costs, Expenses and Other	10,350	10,176	9,520
Operating Income	3,794	3,529	3,538
Earnings from consolidated subsidiaries	0	0	0
Earnings from equity investments	617	428	(113)
Interest, net	(1,917)	(1,832)	(1,806)
Amortization of excess cost of equity investments and other, net	12	36	19
Income Before Income Taxes	2,506	2,161	1,638
Income Tax Expense	(587)	(1,938)	(917)
Net Income	1,919	223	721
Net Income Attributable to Noncontrolling Interests	(310)	(40)	(13)
Net Income Attributable to Kinder Morgan, Inc.	1,609	183	708
Preferred Stock Dividends	(128)	(156)	(156)
Net Income Available to Common Stockholders	1,481	27	552
Total other comprehensive (loss) income	338	115	(200)
Comprehensive income	2,257	338	521
Comprehensive income attributable to noncontrolling interests	(328)	(86)	(13)
Comprehensive income attributable to KMI	1,929	252	508
Consolidating Adjustments
Guarantor Obligations [Line Items]
Total Revenues	(149)	(146)	(59)
Costs of sales	(103)	(101)	(13)
Depreciation, depletion and amortization	0	0	0
Other operating expenses	(46)	(45)	(46)
Total Operating Costs, Expenses and Other	(149)	(146)	(59)
Operating Income	0	0	0
Earnings from consolidated subsidiaries	(5,954)	(6,734)	(6,053)
Earnings from equity investments	0	0	0
Interest, net	0	0	0
Amortization of excess cost of equity investments and other, net	0	0	0
Income Before Income Taxes	(5,954)	(6,734)	(6,053)
Income Tax Expense	0	0	0
Net Income	(5,954)	(6,734)	(6,053)
Net Income Attributable to Noncontrolling Interests	(310)	(40)	(13)
Net Income Attributable to Kinder Morgan, Inc.	(6,264)	(6,774)	(6,066)
Preferred Stock Dividends	0	0	0
Net Income Available to Common Stockholders	(6,264)	(6,774)	(6,066)
Total other comprehensive (loss) income	(688)	(525)	638
Comprehensive income	(6,642)	(7,259)	(5,415)
Comprehensive income attributable to noncontrolling interests	(328)	(86)	(13)
Comprehensive income attributable to KMI	$ (6,970)	$ (7,345)	$ (5,428)

Guarantee of Securities of Su_4

Guarantee of Securities of Subsidiaries Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
ASSETS
Cash and cash equivalents	$ 3,280		$ 264	$ 684	$ 229
Other current assets - affiliates	2		8
All other current assets	225		238
Property, plant and equipment, net	37,897		40,155
Investments	7,481		7,298
Goodwill	21,965		22,162	22,152
Deferred income taxes	1,566		2,044
Other non-current assets	1,355		1,582
Total Assets	78,866		79,055
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Long-term debt	33,936		35,015
Notes payable to affiliates	34		35
Total Liabilities	43,669		43,931
Redeemable Noncontrolling Interest	666		0
Total KMI equity	33,678		33,636
Noncontrolling interests	853		1,488
Total Stockholders’ Equity	34,531	$ 35,190	35,124	$ 34,802	$ 35,403
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	78,866		79,055
Parent Issuer and Guarantor
ASSETS
Cash and cash equivalents	8		3
Other current assets - affiliates	4,465		6,214
All other current assets	171		243
Property, plant and equipment, net	231		236
Investments	664		665
Investments in subsidiaries	42,096		37,983
Goodwill	13,789		13,789
Notes receivable from affiliates	945		1,033
Deferred income taxes	3,137		3,635
Other non-current assets	233		254
Total Assets	65,739		64,055
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current portion of debt	1,933		924
Other current liabilities - affiliates	14,189		13,225
All other current liabilities	486		468
Long-term debt	13,474		13,104
Notes payable to affiliates	1,234		2,009
Deferred income taxes	0		0
Other long-term liabilities and deferred credits	745		689
Total Liabilities	32,061		30,419
Redeemable Noncontrolling Interest	0
Total KMI equity	33,678		33,636
Noncontrolling interests	0		0
Total Stockholders’ Equity	33,678		33,636
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	65,739		64,055
Subsidiary Issuer and Guarantor - KMP
ASSETS
Cash and cash equivalents	0		0
Other current assets - affiliates	4,788		5,201
All other current assets	17		59
Property, plant and equipment, net	0		0
Investments	0		0
Investments in subsidiaries	40,049		36,728
Goodwill	22		22
Notes receivable from affiliates	20,345		20,363
Deferred income taxes	0		0
Other non-current assets	105		164
Total Assets	65,326		62,537
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current portion of debt	1,300		975
Other current liabilities - affiliates	14,087		14,188
All other current liabilities	354		347
Long-term debt	16,799		18,206
Notes payable to affiliates	448		448
Deferred income taxes	0		0
Other long-term liabilities and deferred credits	59		117
Total Liabilities	33,047		34,281
Redeemable Noncontrolling Interest	0
Total KMI equity	32,279		28,256
Noncontrolling interests	0		0
Total Stockholders’ Equity	32,279		28,256
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	65,326		62,537
Subsidiary Guarantors
ASSETS
Cash and cash equivalents	0		0
Other current assets - affiliates	23,851		22,402
All other current assets	2,056		1,938
Property, plant and equipment, net	30,750		31,093
Investments	6,718		6,498
Investments in subsidiaries	6,077		5,417
Goodwill	5,166		5,166
Notes receivable from affiliates	247		1,233
Deferred income taxes	0		0
Other non-current assets	3,823		4,080
Total Assets	78,688		77,827
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current portion of debt	30		805
Other current liabilities - affiliates	4,898		6,512
All other current liabilities	1,838		2,055
Long-term debt	3,020		3,052
Notes payable to affiliates	20,543		20,593
Deferred income taxes	503		449
Other long-term liabilities and deferred credits	944		1,462
Total Liabilities	31,776		34,928
Redeemable Noncontrolling Interest	666
Total KMI equity	46,246		42,899
Noncontrolling interests	0		0
Total Stockholders’ Equity	46,246		42,899
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	78,688		77,827
Subsidiary Non-Guarantors
ASSETS
Cash and cash equivalents	3,277		262
Other current assets - affiliates	1,031		858
All other current assets	212		235
Property, plant and equipment, net	6,916		8,826
Investments	99		135
Investments in subsidiaries	4,324		4,232
Goodwill	2,988		3,185
Notes receivable from affiliates	1,043		776
Deferred income taxes	0		0
Other non-current assets	74		183
Total Assets	19,964		18,692
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current portion of debt	125		124
Other current liabilities - affiliates	961		750
All other current liabilities	1,510		508
Long-term debt	643		653
Notes payable to affiliates	355		355
Deferred income taxes	1,068		1,142
Other long-term liabilities and deferred credits	428		467
Total Liabilities	5,090		3,999
Redeemable Noncontrolling Interest	0
Total KMI equity	14,874		14,693
Noncontrolling interests	0		0
Total Stockholders’ Equity	14,874		14,693
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	19,964		18,692
Consolidated KMI
ASSETS
Cash and cash equivalents	3,280		264
Other current assets - affiliates	0		0
All other current assets	2,442		2,451
Property, plant and equipment, net	37,897		40,155
Investments	7,481		7,298
Investments in subsidiaries	0		0
Goodwill	21,965		22,162
Notes receivable from affiliates	0		0
Deferred income taxes	1,566		2,044
Other non-current assets	4,235		4,681
Total Assets	78,866		79,055
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current portion of debt	3,388		2,828
Other current liabilities - affiliates	0		0
All other current liabilities	4,169		3,353
Long-term debt	33,936		35,015
Notes payable to affiliates	0		0
Deferred income taxes	0		0
Other long-term liabilities and deferred credits	2,176		2,735
Total Liabilities	43,669		43,931
Redeemable Noncontrolling Interest	666
Total KMI equity	33,678		33,636
Noncontrolling interests	853		1,488
Total Stockholders’ Equity	34,531		35,124
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	78,866		79,055
Consolidating Adjustments
ASSETS
Cash and cash equivalents	(5)		(1)
Other current assets - affiliates	(34,135)		(34,675)
All other current assets	(14)		(24)
Property, plant and equipment, net	0		0
Investments	0		0
Investments in subsidiaries	(92,546)		(84,360)
Goodwill	0		0
Notes receivable from affiliates	(22,580)		(23,405)
Deferred income taxes	(1,571)		(1,591)
Other non-current assets	0		0
Total Assets	(150,851)		(144,056)
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current portion of debt	0		0
Other current liabilities - affiliates	(34,135)		(34,675)
All other current liabilities	(19)		(25)
Long-term debt	0		0
Notes payable to affiliates	(22,580)		(23,405)
Deferred income taxes	(1,571)		(1,591)
Other long-term liabilities and deferred credits	0		0
Total Liabilities	(58,305)		(59,696)
Redeemable Noncontrolling Interest	0
Total KMI equity	(93,399)		(85,848)
Noncontrolling interests	853		1,488
Total Stockholders’ Equity	(92,546)		(84,360)
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$ (150,851)		$ (144,056)

Guarantee of Securities of Su_5

Guarantee of Securities of Subsidiaries Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	$ 5,043	$ 4,601	$ 4,758
Proceeds from the TMPL Sale, net of cash disposed	2,998	0	0
Acquisitions of investments	(39)	(4)	(333)
Capital expenditures	(2,904)	(3,188)	(2,882)
Proceeds from sales of equity investments	124	0	0
Proceeds from sale of equity interests in subsidiaries, net	0	0	1,401
Sales of property, plant and equipment, investments and other net assets, net of removal costs	(20)	118	330
Contributions to investments	(433)	(684)	(408)
Distributions from equity investments in excess of cumulative earnings	237	374	231
Loans to related party	(31)	(23)
Loans repayments from related parties			35
Other, net	0	4	1
Net Cash Used in Investing Activities	(68)	(3,403)	(1,625)
Issuances of debt	14,751	8,868	8,629
Payments of debt	(14,591)	(11,064)	(10,060)
Debt issue costs	(42)	(70)	(19)
Cash dividends - common shares	(1,618)	(1,120)	(1,118)
Cash dividends - preferred shares	(156)	(156)	(154)
Repurchases of common shares	(273)	(250)	0
Contributions from investment partner	181	485	0
Contributions from noncontrolling interests - net proceeds from KML IPO	0	1,245	0
Contributions from noncontrolling interests - net proceeds from KML preferred share issuances	0	420	0
Contributions from noncontrolling interests - other	19	12	117
Distributions to noncontrolling interests	(78)	(42)	(24)
Other, net	(17)	(9)	(8)
Net Cash Used in Financing Activities	(1,824)	(1,681)	(2,637)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	(146)	22	2
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	3,005	(461)	498
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	326	787	289
Cash, Cash Equivalents, and Restricted Deposits, end of period	3,331	326	787
Parent Issuer and Guarantor
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	(2,758)	(3,184)	(3,981)
Proceeds from the TMPL Sale, net of cash disposed	0
Acquisitions of investments	0	0	(2)
Capital expenditures	(24)	(23)	(27)
Proceeds from sales of equity investments	0
Proceeds from sale of equity interests in subsidiaries, net			0
Sales of property, plant and equipment, investments and other net assets, net of removal costs	9	16	6
Contributions to investments	(12)	(237)	(343)
Distributions from equity investments in excess of cumulative earnings	2,342	2,297	2,417
Funding to affiliates	(6,521)	(4,419)	(2,820)
Loans to related party	0	(23)
Loans repayments from related parties			0
Other, net		0	0
Net Cash Used in Investing Activities	(4,206)	(2,389)	(769)
Issuances of debt	14,143	8,609	8,255
Payments of debt	(12,640)	(9,288)	(7,322)
Debt issue costs	(35)	(12)	(16)
Cash dividends - common shares	(1,618)	(1,120)	(1,118)
Cash dividends - preferred shares	(156)	(156)	(154)
Repurchases of common shares	(273)	(250)
Funding from affiliates	7,560	7,327	5,461
Contributions from investment partner	0	0
Contributions from parents, including net proceeds from KML IPO and preferred share issuance	0	0	0
Contributions from noncontrolling interests - net proceeds from KML IPO		4
Contributions from noncontrolling interests - net proceeds from KML preferred share issuances		0
Contributions from noncontrolling interests - other	0	0	0
Distributions to parents	0	0	0
Distributions to noncontrolling interests	0	0	0
Other, net	(12)	(9)	(8)
Net Cash Used in Financing Activities	6,969	5,105	5,098
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	0	0	0
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	5	(468)	348
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3	471	123
Cash, Cash Equivalents, and Restricted Deposits, end of period	8	3	471
Subsidiary Issuer and Guarantor - KMP
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	3,879	3,911	4,943
Proceeds from the TMPL Sale, net of cash disposed	0
Acquisitions of investments	0	0	0
Capital expenditures	0	0	0
Proceeds from sales of equity investments	0
Proceeds from sale of equity interests in subsidiaries, net			0
Sales of property, plant and equipment, investments and other net assets, net of removal costs	0	0	0
Contributions to investments	0	0	0
Distributions from equity investments in excess of cumulative earnings	0	0	298
Funding to affiliates	(26)	779	(535)
Loans to related party	0	0
Loans repayments from related parties			0
Other, net		1	0
Net Cash Used in Investing Activities	(26)	780	(237)
Issuances of debt	0	0	0
Payments of debt	(975)	(600)	(500)
Debt issue costs	0	0	0
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0	0	0
Repurchases of common shares	0	0
Funding from affiliates	2,028	776	1,116
Contributions from investment partner	0	0
Contributions from parents, including net proceeds from KML IPO and preferred share issuance	0	0	0
Contributions from noncontrolling interests - net proceeds from KML IPO		0
Contributions from noncontrolling interests - net proceeds from KML preferred share issuances		0
Contributions from noncontrolling interests - other	0	0	0
Distributions to parents	(4,907)	(4,902)	(5,286)
Distributions to noncontrolling interests	0	0	0
Other, net	0	0	0
Net Cash Used in Financing Activities	(3,854)	(4,726)	(4,670)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	0	0	0
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	(1)	(35)	36
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1	36	0
Cash, Cash Equivalents, and Restricted Deposits, end of period	0	1	36
Subsidiary Guarantors
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	11,129	11,523	11,641
Proceeds from the TMPL Sale, net of cash disposed	0
Acquisitions of investments	(39)	(4)	(331)
Capital expenditures	(1,995)	(2,390)	(2,258)
Proceeds from sales of equity investments	124
Proceeds from sale of equity interests in subsidiaries, net			1,401
Sales of property, plant and equipment, investments and other net assets, net of removal costs	(34)	94	326
Contributions to investments	(413)	(435)	(54)
Distributions from equity investments in excess of cumulative earnings	234	326	190
Funding to affiliates	(7,419)	(7,040)	(5,062)
Loans to related party	(31)	0
Loans repayments from related parties			35
Other, net		4	3
Net Cash Used in Investing Activities	(9,573)	(9,445)	(5,750)
Issuances of debt	0	0	374
Payments of debt	(784)	(897)	(2,227)
Debt issue costs	0	0	(2)
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0	0	0
Repurchases of common shares	0	0
Funding from affiliates	4,542	3,797	1,959
Contributions from investment partner	181	485
Contributions from parents, including net proceeds from KML IPO and preferred share issuance	19	0	117
Contributions from noncontrolling interests - net proceeds from KML IPO		0
Contributions from noncontrolling interests - net proceeds from KML preferred share issuances		0
Contributions from noncontrolling interests - other	0	0	0
Distributions to parents	(5,514)	(5,472)	(6,116)
Distributions to noncontrolling interests	0	0	0
Other, net	0	0	0
Net Cash Used in Financing Activities	(1,556)	(2,087)	(5,895)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	0	0	0
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	0	(9)	(4)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	0	9	13
Cash, Cash Equivalents, and Restricted Deposits, end of period	0	0	9
Subsidiary Non-Guarantors
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	1,117	1,121	885
Proceeds from the TMPL Sale, net of cash disposed	2,998
Acquisitions of investments	0	0	0
Capital expenditures	(885)	(775)	(597)
Proceeds from sales of equity investments	0
Proceeds from sale of equity interests in subsidiaries, net			0
Sales of property, plant and equipment, investments and other net assets, net of removal costs	5	8	(2)
Contributions to investments	(8)	(12)	(11)
Distributions from equity investments in excess of cumulative earnings	1	0	0
Funding to affiliates	(1,003)	(1,028)	(727)
Loans to related party	0	0
Loans repayments from related parties			0
Other, net		(1)	(2)
Net Cash Used in Investing Activities	1,108	(1,808)	(1,339)
Issuances of debt	608	259	0
Payments of debt	(192)	(279)	(11)
Debt issue costs	(7)	(58)	(1)
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0	0	0
Repurchases of common shares	0	0
Funding from affiliates	839	(192)	608
Contributions from investment partner	0	0
Contributions from parents, including net proceeds from KML IPO and preferred share issuance	0	1,673	0
Contributions from noncontrolling interests - net proceeds from KML IPO		0
Contributions from noncontrolling interests - net proceeds from KML preferred share issuances		0
Contributions from noncontrolling interests - other	0	0	0
Distributions to parents	(317)	(687)	(73)
Distributions to noncontrolling interests	0	0	0
Other, net	(5)	0	0
Net Cash Used in Financing Activities	926	716	523
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	(146)	22	2
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	3,005	51	71
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	323	272	201
Cash, Cash Equivalents, and Restricted Deposits, end of period	3,328	323	272
Consolidated KMI
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	5,043	4,601	4,758
Proceeds from the TMPL Sale, net of cash disposed	2,998
Acquisitions of investments	(39)	(4)	(333)
Capital expenditures	(2,904)	(3,188)	(2,882)
Proceeds from sales of equity investments	124
Proceeds from sale of equity interests in subsidiaries, net			1,401
Sales of property, plant and equipment, investments and other net assets, net of removal costs	(20)	118	330
Contributions to investments	(433)	(684)	(408)
Distributions from equity investments in excess of cumulative earnings	237	374	231
Funding to affiliates	0	0	0
Loans to related party	(31)	(23)
Loans repayments from related parties			35
Other, net		4	1
Net Cash Used in Investing Activities	(68)	(3,403)	(1,625)
Issuances of debt	14,751	8,868	8,629
Payments of debt	(14,591)	(11,064)	(10,060)
Debt issue costs	(42)	(70)	(19)
Cash dividends - common shares	(1,618)	(1,120)	(1,118)
Cash dividends - preferred shares	(156)	(156)	(154)
Repurchases of common shares	(273)	(250)
Funding from affiliates	0	0	0
Contributions from investment partner	181	485
Contributions from parents, including net proceeds from KML IPO and preferred share issuance	0	0	0
Contributions from noncontrolling interests - net proceeds from KML IPO		1,245
Contributions from noncontrolling interests - net proceeds from KML preferred share issuances		420
Contributions from noncontrolling interests - other	19	12	117
Distributions to parents	0	0	0
Distributions to noncontrolling interests	(78)	(42)	(24)
Other, net	(17)	(9)	(8)
Net Cash Used in Financing Activities	(1,824)	(1,681)	(2,637)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	(146)	22	2
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	3,005	(461)	498
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	326	787	289
Cash, Cash Equivalents, and Restricted Deposits, end of period	3,331	326	787
Consolidating Adjustments
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	(8,324)	(8,770)	(8,730)
Proceeds from the TMPL Sale, net of cash disposed	0
Acquisitions of investments	0	0	0
Capital expenditures	0	0	0
Proceeds from sales of equity investments	0
Proceeds from sale of equity interests in subsidiaries, net			0
Sales of property, plant and equipment, investments and other net assets, net of removal costs	0	0	0
Contributions to investments	0	0	0
Distributions from equity investments in excess of cumulative earnings	(2,340)	(2,249)	(2,674)
Funding to affiliates	14,969	11,708	9,144
Loans to related party	0	0
Loans repayments from related parties			0
Other, net		0	0
Net Cash Used in Investing Activities	12,629	9,459	6,470
Issuances of debt	0	0	0
Payments of debt	0	0	0
Debt issue costs	0	0	0
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0	0	0
Repurchases of common shares	0	0
Funding from affiliates	(14,969)	(11,708)	(9,144)
Contributions from investment partner	0	0
Contributions from parents, including net proceeds from KML IPO and preferred share issuance	(19)	(1,673)	(117)
Contributions from noncontrolling interests - net proceeds from KML IPO		1,241
Contributions from noncontrolling interests - net proceeds from KML preferred share issuances		420
Contributions from noncontrolling interests - other	19	12	117
Distributions to parents	10,738	11,061	11,475
Distributions to noncontrolling interests	(78)	(42)	(24)
Other, net	0	0	0
Net Cash Used in Financing Activities	(4,309)	(689)	2,307
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	0	0	0
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	(4)	0	47
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	(1)	(1)	(48)
Cash, Cash Equivalents, and Restricted Deposits, end of period	$ (5)	$ (1)	$ (1)