Kinder Morgan (KMI) 10-K 9 Feb 18 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 08, 2018	Jun. 30, 2017
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 Filer Category	Large Accelerated Filer
Entity Public Float			$ 36,830,209,065
Entity Common Stock, Shares Outstanding		2,206,066,684
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
Natural gas sales	$ 3,053	$ 2,454	$ 2,839
Services	7,901	8,146	8,290
Product sales and other	2,751	2,458	3,274
Total Revenues	13,705	13,058	14,403
Operating Costs, Expenses and Other
Costs of sales	4,345	3,429	4,059
Operations and maintenance	2,472	2,372	2,393
Depreciation, depletion and amortization	2,261	2,209	2,309
General and administrative	673	669	690
Taxes, other than income taxes	398	421	439
Loss on impairment of goodwill	0	0	1,150
Loss on impairments and divestitures, net	13	387	919
Other income, net	(1)	(1)	(3)
Total Operating Costs, Expenses and Other	10,161	9,486	11,956
Operating Income	3,544	3,572	2,447
Other Income (Expense)
Earnings from equity investments	578	497	414
Loss on impairments and divestitures of equity investments, net	(150)	(610)	(30)
Amortization of excess cost of equity investments	(61)	(59)	(51)
Interest, net	(1,832)	(1,806)	(2,051)
Other, net	82	44	43
Total Other Expense	(1,383)	(1,934)	(1,675)
Income Before Income Taxes	2,161	1,638	772
Income Tax Expense	(1,938)	(917)	(564)
Net Income	223	721	208
Net (Income) Loss Attributable to Noncontrolling Interests	(40)	(13)	45
Net Income Attributable to Kinder Morgan, Inc.	183	708	253
Preferred Stock Dividends	(156)	(156)	(26)
Net Income Available to Common Stockholders	$ 27	$ 552	$ 227
Class P Shares
Basic Earnings Per Common Share	$ 0.01	$ 0.25	$ 0.10
Basic Weighted Average Common Shares Outstanding	2,230	2,230	2,187
Diluted Earnings Per Common Share	$ 0.01	$ 0.25	$ 0.10
Diluted Weighted Average Common Shares Outstanding	2,230	2,230	2,193
Dividends Per Common Share Declared for the Period	$ 0.500	$ 0.500	$ 1.605

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Total
Net income	$ 223	$ 721	$ 208
Other comprehensive income (loss), net of tax
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(82), $60 and $(94), respectively)	145	(104)	164
Reclassification of change in fair value of derivatives to net income (net of tax benefit of $97, $67 and $156, respectively)	(171)	(116)	(272)
Foreign currency translation adjustments (net of tax (expense) benefit of $(56), $(20) and $123, respectively)	101	34	(214)
Benefit plan adjustments (net of tax (expense) benefit of $(27), $19 and $69, respectively)	40	(14)	(122)
Total other comprehensive income (loss)	115	(200)	(444)
Comprehensive income (loss)	338	521	(236)
Comprehensive (income) loss attributable to noncontrolling interests	(86)	(13)	45
Comprehensive income (loss) attributable to KMI	$ 252	$ 508	$ (191)

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME, TAX (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Total, Tax
Change in fair value of derivatives utilized for hedging purposes	$ (82)	$ 60	$ (94)
Reclassification of change in fair value of derivatives to net income	97	67	156
Foreign currency translation adjustments	(56)	(20)	123
Benefit plan adjustments	$ (27)	$ 19	$ 69

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 264	$ 684
Restricted deposits	62	103
Accounts receivable, net	1,448	1,370
Fair value of derivative contracts	114	198
Inventories	424	357
Income tax receivable	165	180
Other current assets	238	337
Total current assets	2,715	3,229
Property, plant and equipment, net	40,155	38,705
Investments	7,298	7,027
Goodwill	22,162	22,152
Other intangibles, net	3,099	3,318
Deferred income taxes	2,044	4,352
Deferred charges and other assets	1,582	1,522
Total Assets	79,055	80,305
Current liabilities
Current portion of debt	2,828	2,696
Accounts payable	1,340	1,257
Accrued interest	621	625
Accrued contingencies	291	261
Other current liabilities	1,101	1,085
Total current liabilities	6,181	5,924
Long-term debt
Outstanding	33,988	36,105
Preferred interest in general partner of KMP	100	100
Debt fair value adjustments	927	1,149
Total long-term debt	35,015	37,354
Other long-term liabilities and deferred credits	2,735	2,225
Total long-term liabilities and deferred credits	37,750	39,579
Total Liabilities	43,931	45,503
Commitments and contingencies (Notes 9, 13 and 17)
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,217,110,072 and 2,230,102,384 shares, respectively, issued and outstanding	22	22
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference, 1,600,000 shares issued and outstanding	0	0
Additional paid-in capital	41,909	41,739
Retained deficit	(7,754)	(6,669)
Accumulated other comprehensive loss	(541)	(661)
Total Kinder Morgan, Inc.’s stockholders’ equity	33,636	34,431
Noncontrolling interests	1,488	371
Total Stockholders’ Equity	35,124	34,802
Total Liabilities and Stockholders’ Equity	$ 79,055	$ 80,305

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
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)	1,600,000	1,600,000
Preferred stock, shares outstanding (in shares)	1,600,000	1,600,000
Preferred Stock, Liquidation Preference Per Share	$ 1,000	$ 1,000
Preferred Stock, Dividend Rate, Percentage	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)	2,217,110,072	2,230,102,384
Common stock, shares outstanding (in shares)	2,217,110,072	2,230,102,384

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flows From Operating Activities
Net income	$ 223	$ 721	$ 208
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	2,261	2,209	2,309
Deferred income taxes	2,073	1,087	692
Amortization of excess cost of equity investments	61	59	51
Change in fair market value of derivative contracts	40	64	(166)
Loss (gain) on early extinguishment of debt	4	(45)	0
Loss on impairment of goodwill (Note 4)	0	0	1,150
Loss on impairments and divestitures, net (Note 4)	13	387	919
Loss on impairments and divestitures of equity investments, net (Note 4)	150	610	30
Earnings from equity investments	(578)	(497)	(414)
Distributions of equity investment earnings	426	431	391
Pension contributions and noncash pension benefit expenses (credits)	8	9	(90)
Changes in components of working capital, net of the effects of acquisitions and dispositions
Accounts receivable, net	(78)	(107)	382
Income tax receivable	7	(148)	195
Inventories	(90)	49	34
Other current assets	(25)	(81)	113
Accounts payable	73	144	(154)
Accrued interest, net of interest rate swaps	10	(18)	37
Accrued contingencies and other current liabilities	101	79	(121)
Rate reparations, refunds and other litigation reserve adjustments	(100)	(32)	18
Other, net	22	(126)	(271)
Net Cash Provided by Operating Activities	4,601	4,795	5,313
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired	(4)	(333)	(2,079)
Capital expenditures	(3,188)	(2,882)	(3,896)
Proceeds from sale of equity interests in subsidiaries, net	0	1,401	0
Sales of property, plant and equipment, investments, and other net assets, net of removal costs	118	330	39
Contributions to investments	(684)	(408)	(96)
Distributions from equity investments in excess of cumulative earnings	374	231	228
Other, net	22	(44)	98
Net Cash Used in Investing Activities	(3,362)	(1,705)	(5,706)
Cash Flows From Financing Activities
Issuances of debt	8,868	8,629	14,316
Payments of debt	(11,064)	(10,060)	(15,116)
Debt issue costs	(70)	(19)	(24)
Issuances of common shares (Note 11)	0	0	3,870
Issuance of mandatory convertible preferred stock (Note 11)	0	0	1,541
Cash dividends - common shares (Note 11)	(1,120)	(1,118)	(4,224)
Cash dividends - preferred shares (Note 11)	(156)	(154)	0
Repurchases of shares and warrants (Note 11)	(250)	0	(12)
Contributions from investment partner	485	0	0
Contributions from noncontrolling interests - net proceeds from KML IPO (Note 3)	1,245	0	0
Contributions from noncontrolling interests - net proceeds from KML preferred share issuances (Note 11)	420	0	0
Contributions from noncontrolling interests - other	12	117	11
Distributions to noncontrolling interests	(42)	(24)	(34)
Other, net	(9)	(8)	(11)
Net Cash (Used in) Provided by Financing Activities	(1,681)	(2,637)	317
Effect of Exchange Rate Changes on Cash and Cash Equivalents	22	2	(10)
Net (decrease) increase in Cash and Cash Equivalents	(420)	455	(86)
Cash and Cash Equivalents, beginning of period	684	229	315
Cash and Cash Equivalents, end of period	264	684	229
Noncash Investing and Financing Activities
Assets acquired by the assumption or incurrence of liabilities	0	43	1,681
Net assets contributed to equity investments	0	37	46
Increase in property, plant and equipment from both accruals and contractor retainage	14
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,854	2,050	1,985
Cash (refunded) paid during the period for income taxes, net	$ (140)	$ 4	$ (331)

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
Common stock, shares outstanding (in shares)		2,125,000,000
Preferred stock, shares outstanding (in shares)			0
Total at Dec. 31, 2014	$ 34,426	$ 21	$ 0	$ 36,178	$ (2,106)	$ (17)	$ 34,076	$ 350
Issuances of common shares		103,000,000
Issuances of common shares	3,870	$ 1		3,869			3,870
Issuances of preferred shares			2,000,000
Issuances of preferred shares	1,541			1,541			1,541
Repurchase of Warrants	(12)			(12)			(12)
EP Trust I Preferred security conversions		1,000,000
EP Trust I Preferred security conversions	23			23			23
Warrants exercised	2			2			2
Restricted shares	57			57			57
Net income	208				253		253	(45)
Distributions	(34)						0	(34)
Contributions	11						0	11
Preferred stock dividends	(26)				(26)		(26)
Common stock dividends	(4,224)				(4,224)		(4,224)
Other	5			3			3	2
Other comprehensive loss	(444)					(444)	(444)
Total at Dec. 31, 2015	35,403	$ 22	$ 0	41,661	(6,103)	(461)	35,119	284
Common stock, shares outstanding (in shares)		2,229,000,000
Preferred stock, shares outstanding (in shares)			2,000,000
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures		1,000,000
Restricted shares	66			66			66
Net income	721				708		708	13
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)
Total at Dec. 31, 2016	$ 34,802	$ 22	$ 0	41,739	(6,669)	(661)	34,431	371
Common stock, shares outstanding (in shares)		2,230,000,000
Preferred stock, shares outstanding (in shares)	1,600,000		2,000,000
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures		1,000,000
Stock Repurchased and Retired During Period, Shares		(14,000,000)
Stock Repurchased During Period, Value	$ (250)			(250)			(250)
Restricted shares	65			65			65
Net income	223				183		183	40
KML IPO	1,049			314		51	365	684
KML preferred share issuance	419						0	419
Reparation of Foreign Cash	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)
Impact of adoption of ASU 2016-09 (See Note 5)	8				8		8
Sale and deconsolidation of interest in Deeprock Development, LLC	(30)						0	(30)
Other	(9)			3			3	(12)
Other comprehensive loss	115					69	69	46
Total at Dec. 31, 2017	$ 35,124	$ 22	$ 0	$ 41,909	$ (7,754)	$ (541)	$ 33,636	$ 1,488
Common stock, shares outstanding (in shares)		2,217,000,000
Preferred stock, shares outstanding (in shares)	1,600,000		2,000,000

General (Notes)

General (Notes)	12 Months Ended
	Dec. 31, 2017
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 petroleum products, ethanol and chemicals, and handle products including petroleum coke, steel and coal. We are also a leading producer of CO 2 , which we and others utilize for enhanced oil recovery projects primarily in the Permian basin. Our common stock trades on the NYSE under the symbol “KMI.”

Summary of Significant Accounti

Summary of Significant Accounting Policies Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Significant Accounting Policies [Text Block]	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, the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation. Use of Estimates Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including 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 $62 million and $103 million as of December 31, 2017 and 2016 , respectively. Accounts Receivable, net The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of December 31, 2017 and 2016 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 $35 million and $39 million as of December 31, 2017 and 2016 , 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. Gas Imbalances We value gas imbalances due to or due from interconnecting pipelines at market prices. As of December 31, 2017 and 2016 , our gas imbalance receivables—including both trade and related party receivables—totaled $42 million and $108 million , respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2017 and 2016 , our gas imbalance payables—including both trade and related party payables—totaled $47 million and $45 million , respectively, and we included these amounts within “Other current liabilities” on our accompanying consolidated balance sheets. 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 1.09% 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, 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 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 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. 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 $732 million and $767 million as of December 31, 2017 and 2016 , 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, 2017, this excess investment cost is being amortized over a weighted average life of approximately fourteen years. The second differential, representing equity method goodwill, totaled $956 million for both periods as of December 31, 2017 and 2016 . 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, we have 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. 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 “Goodwill” for further information. Other Intangibles Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets. As of both periods of December 31, 2017 and 2016 , the gross carrying amounts of these intangible assets was $4,305 million and the accumulated amortization was $1,206 million and $987 million , respectively, resulting in net carrying amounts of $3,099 million and $3,318 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, steel 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, 2017 , 2016 and 2015 , the amortization expense on our intangibles totaled $220 million , $223 million and $221 million , respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2018 – 2022) is approximately $214 million , $212 million , $209 million , $209 million , and $206 million , respectively. As of December 31, 2017 , the weighted average amortization period for our intangible assets was approximately sixteen years . Revenue Recognition We recognize revenue as services are rendered or goods are delivered and, if applicable, risk of loss has passed. We recognize natural gas, crude and NGL sales revenue when the commodity is sold to a purchaser at a fixed or determinable price, delivery has occurred and risk of loss has transferred, and collectability of the revenue is reasonably assured. Our sales and purchases of natural gas, crude and NGL are 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 act as an agent and do not have price and related risk of ownership, in which case we recognize revenue on a net basis. In addition to storing and transporting a significant portion of the natural gas volumes we purchase and resell, we provide various types of natural gas storage and transportation services for third-party customers. Under these contracts, the natural gas remains the property of these customers at all times. In many cases, generally described as firm service, the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases, generally described as interruptible service, there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. We provide crude oil and refined petroleum products transportation and storage services to customers. Revenues are recorded when products are delivered and services have been provided, and adjusted according to terms prescribed by the toll settlements with shippers and approved by regulatory authorities. We recognize bulk terminal transfer service revenues based on volumes loaded and unloaded. We recognize liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal throughput revenue based on volumes received and volumes delivered. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when risk of loss has passed. We recognize energy-related product sales revenues based on delivered quantities of product. Revenues from the sale of crude oil, NGL, CO 2 and natural gas production within the CO 2 business segment are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices. Since there is a ready market for oil and gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the buyer. 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 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 $342 million , $349 million and $366 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. 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 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 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 (or loss) of our consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net (Income) Loss Attributable to Noncontrolling Interests.” In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.” Income Taxes Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective 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. 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 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. 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. 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 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. The following table summarizes our regulatory asset and liability balances as of December 31, 2017 and 2016 (in millions): December 31, 2017 2016 Current regulatory assets $ 60 $ 49 Non-current regulatory assets 288 330 Total regulatory assets(a) $ 348 $ 379 Current regulatory liabilities $ 107 $ 101 Non-current regulatory liabilities 236 108 Total regulatory liabilities(b) $ 343 $ 209 _______ (a) Regulatory assets as of December 31, 2017 include (i) $193 million of unamortized losses on disposal of assets; (ii) $55 million income tax gross up on equity AFUDC; and (iii) $100 million of other assets including amounts related to fuel tracker arrangements. Approximately $124 million of the regulatory assets, with a weighted average remaining rec

Acquisitions (Notes)

Acquisitions (Notes)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	Acquisitions and Divestitures Business Combinations There were no significant acquisitions during 2017 . During 2016 and 2015 , we completed the following significant acquisitions. Allocation of Purchase Price As of December 31, 2017 , the purchase allocation for our significant acquisitions completed during the reporting periods are detailed below (in millions): Assignment of Purchase Price Ref. Date Acquisition Purchase price Current assets Property plant & equipment Deferred charges & other Goodwill Debt Other liabilities (1) 2/16 BP Products North America Inc. Terminal Assets $ 349 $ 2 $ 396 $ — $ — $ — $ (49 ) (2) 2/15 Vopak Terminal Assets 158 2 155 — 6 — (5 ) (3) 2/15 Hiland 1,709 79 1,492 1,498 310 (1,413 ) (257 ) After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, goodwill is an intangible asset representing the future economic benefits expected to be derived from an acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that generated our goodwill are both the value of the synergies created between the acquired assets and our pre-existing assets, and our expected ability to grow the business we acquired by leveraging our pre-existing business experience. We apply a look through method of recording deferred income taxes on the outside book-tax basis differences in our investments. As a result, no deferred income taxes are recorded associated with non-deductible goodwill recorded at the investee level. (1) 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. 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” within our accompanying consolidated statement of cash flows for the year ended December 31, 2016. Of the acquired assets, 10 terminals are included in our Terminals business segment and 5 terminals are included in our Products Pipelines business segment based on synergies with each segment’s respective existing operations. (2) Vopak Terminal Assets On February 27, 2015, we acquired three U.S. terminals and one undeveloped site from Royal Vopak (Vopak) for approximately $158 million in cash. The acquisition included (i) a 36 -acre, 1,069,500 -barrel storage facility at Galena Park, Texas that handles base oils, biodiesel and crude oil and is immediately adjacent to our Galena Park terminal facility; (ii) two terminals in North Carolina: one in North Wilmington that handles chemicals and black oil and the other in South Wilmington that is not currently operating; and (iii) an undeveloped waterfront access site in Perth Amboy, New Jersey. We include the acquired assets as part of our Terminals business segment. (3) Hiland On February 13, 2015, we acquired Hiland, a privately held Delaware limited partnership for aggregate consideration of approximately $3,122 million , including assumed debt. Approximately $368 million of the debt assumed was immediately paid down after closing. Hiland’s assets consist primarily of crude oil gathering and transportation pipelines and gas gathering and processing systems, primarily handling production from the Bakken Formation in North Dakota and Montana. The acquired gathering and processing assets are included in our Natural Gas Pipelines business segment while the acquired crude oil transport pipeline (Double H pipeline) is included in our Products Pipelines business segment. Deferred charges and other relates to customer contracts and relationships with a weighted average amortization period as of the acquisition date of 16.4 years . Asset Purchase and Subsequent Sale of Noncontrolling Interest On July 15, 2015, we purchased from Shell US Gas & Power LLC (Shell) its 49% interest in a joint venture, ELC, that was in the pre-construction stage of development for liquefaction facilities at Elba Island, Georgia. The transaction was treated as an asset purchase for the net cash consideration of $185 million . Immediately subsequent to the purchase and before the partial sale discussed below, we had full ownership and control of ELC and prospectively changed our method of accounting for ELC from the equity method to full consolidation. Shell remains subscribed to 100% of the liquefaction capacity. Effective February 28, 2017, we sold a 49% partnership interest in ELC to investment funds managed by EIG Global Energy Partners (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 which are wholly owned by us. In certain limited circumstances which are not expected to occur, EIG has the right to relinquish its interest in ELC and redeem its capital account. As a result of these contingencies, the sale proceeds of $386 million , and subsequent EIG contributions, have been recorded as a deferred credit within “Other long-term liabilities and deferred credits” on our consolidated balance sheet as of December 31, 2017 . EIG is not entitled to any specified return on its capital. Once these contingencies expire, EIG’s capital account will be reflected in Noncontrolling interests on our consolidated balance sheet. Investment Acquisition On December 10, 2015, we and Brookfield Infrastructure Partners L.P. (Brookfield) acquired from Myria Holdings, Inc. the 53% equity interest in NGPL Holdings LLC not previously owned by us and Brookfield, increasing our ownership to 50% with Brookfield owning the remaining 50% . We paid $136 million for our additional 30% interest in NGPL Holdings LLC. See Note 7 “Investments” for additional information regarding our equity interests in NGPL Holdings LLC. Sale of Approximate 30% Interest in Canadian Business On May 30, 2017, our indirectly owned subsidiary, KML, completed an IPO of 102,942,000 restricted voting shares listed on the Toronto Stock Exchange at a price to the public of $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) loss 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 are 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 KML is now 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, 2017 Assets Total current assets $ 270 Property, plant and equipment, net 2,956 Total goodwill, deferred charges and other assets 322 Total assets $ 3,548 Liabilities Current portion of debt $ — Total other current liabilities 236 Long-term debt, excluding current maturities — Total other long-term liabilities and deferred credits 414 Total liabilities $ 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. Our subsidiaries that are the direct owners of our limited partnership interests in KMC LP have guaranteed the obligations of KMC LP’s wholly owned subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, under the Credit Facility (see Note 9 “Debt”), but recourse in respect of such guarantee is limited solely to the limited partnership interests of KMC LP held by such subsidiaries and any proceeds thereof. Additionally, in connection with the Credit Facility, we entered into an Equity Nomination and Support Agreement whereby, among other things, we commit to contribute or cause to be contributed at the time of each drawdown on the construction credit facility or the contingent credit facility either equity or subordinated debt to Kinder Morgan Cochin ULC in an amount sufficient to cause the outstanding indebtedness under the credit facilities and any other funded debt for the TMEP not to exceed 60% of the total project costs for the project as projected over the six month period following the date of such drawdown. Other than such guarantees and the Equity Nomination and Support Agreement, 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. 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, and we classified $61 million as held for sale for the remaining locations which is included within “Other current assets” on our accompanying consolidated balance sheet at 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.

Impairments (Notes)

Impairments (Notes)	12 Months Ended
	Dec. 31, 2017
Impairments [Abstract]
Impairment of Goodwill, Long-lived assets and equity investments [Text Block]	Impairments and Losses on Divestitures During the years ended December 31, 2017 , 2016 , and 2015 , we recorded impairments of certain equity investments, long-lived assets, and intangible assets, and net losses on divestitures totaling $172 million , $1,013 million , and $2,125 million , respectively. During 2015 and 2016, and to a lesser degree in 2017, 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. In addition, an interim goodwill impairment test was performed during the fourth quarter of 2015 resulting in a partial impairment of goodwill in our Natural Gas Pipelines Non-Regulated reporting unit of approximately $1,150 million . See Note 8 “Goodwill” for further information. 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. In certain cases, management’s decisions to dispose of certain assets may trigger an impairment. 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. 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 of our assets, including some equity investments and oil and gas producing properties, have been written down to fair value, 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, 2017 2016 2015 Natural Gas Pipelines Impairment of goodwill $ — $ — $ 1,150 Impairments of long-lived assets(a) 30 106 79 Losses on divestitures of long-lived assets(b) — 94 43 Impairments of equity investments(c) 150 606 26 Impairments at equity investees(d) 10 7 — CO 2 Impairments of long-lived assets(e) (1 ) 20 606 Gains on divestitures of long-lived assets — (1 ) — Impairments at equity investee(d) (4 ) 9 26 Terminals Impairments of long-lived assets(f) 3 19 188 (Gains) losses on divestitures of long-lived assets(g) (18 ) 80 3 Losses on impairments and divestitures of equity investments, net — 16 4 Products Pipelines Impairments of long-lived assets(h) — 66 — Losses (gains) on divestitures of long-lived assets — 10 1 Gain on divestiture of equity investment — (12 ) — Other losses (gains) on divestitures of long-lived assets 2 (7 ) (1 ) Pre-tax losses on impairments and divestitures, net $ 172 $ 1,013 $ 2,125 _______ (a) 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 (NED) Market project. 2015 amount represents $47 million and $32 million of project write-offs in our non-regulated midstream and regulated natural gas pipelines assets, respectively. (b) 2016 amount primarily relates to our sale of a 50% interest in SNG. (c) 2017 amount represents the impairment of our investment in FEP. 2016 amount includes a $350 million impairment of our investment in MEP and a $250 million impairment of our investment in Ruby. 2015 amount is primarily related to an impairment of an investment in a gathering and processing asset in Oklahoma. (d) 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) 2015 amount includes (i) $399 million related to oil and gas properties and (ii) $207 million related to the certain CO 2 source and transportation project write-offs. (f) 2015 amount is primarily related to certain terminals with significant coal operations, including a $175 million impairment of a terminal facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer in February 2016. (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) 2016 amount represents project write-offs associated with the canceled Palmetto project.

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of “Income Before Income Taxes” are as follows (in millions): Year Ended December 31, 2017 2016 2015 U.S. $ 1,976 $ 1,466 $ 611 Foreign 185 172 161 Total Income Before Income Taxes $ 2,161 $ 1,638 $ 772 Components of the income tax provision applicable for federal, foreign and state taxes are as follows (in millions): Year Ended December 31, 2017 2016 2015 Current tax expense (benefit) Federal $ (137 ) $ (148 ) $ (125 ) State (16 ) (28 ) (7 ) Foreign 18 6 4 Total (135 ) (170 ) (128 ) Deferred tax expense (benefit) Federal 2,022 998 653 State 4 51 (4 ) Foreign 47 38 43 Total 2,073 1,087 692 Total tax provision $ 1,938 $ 917 $ 564 We are subject to taxation in Canada and Mexico. In Canada we recognized income tax expense of $58 million , $38 million and $46 million at December 31, 2017, 2016, and 2015, respectively. In Mexico we recognized income tax expense of $7 million , $6 million and $1 million at December 31, 2017, 2016, and 2015, 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, 2017 2016 2015 Federal income tax $ 756 35.0 % $ 573 35.0 % $ 271 35.0 % Increase (decrease) as a result of: State deferred tax rate change 10 0.5 % 11 0.7 % (24 ) (3.1 )% Taxes on foreign earnings, net of federal benefit 42 1.9 % 28 1.7 % 26 3.5 % Net effects of noncontrolling interests (14 ) (0.7 )% (4 ) (0.3 )% 15 2.0 % State income tax, net of federal benefit 38 1.8 % 26 1.6 % 12 1.5 % Dividend received deduction (56 ) (2.6 )% (48 ) (2.9 )% (51 ) (6.6 )% Adjustments to uncertain tax positions (12 ) (0.6 )% (23 ) (1.4 )% (14 ) (1.9 )% Valuation allowance on investment and tax credits 13 0.6 % 34 2.1 % — — % Impact of the 2017 Tax Reform 1,240 57.4 % — — % — — % Nondeductible goodwill — — % 301 18.5 % 323 41.7 % General business credit (95 ) (4.4 )% — — % — — % Other 16 0.8 % 19 1.1 % 6 0.8 % Total $ 1,938 89.7 % $ 917 56.1 % $ 564 72.9 % Deferred tax assets and liabilities result from the following (in millions): December 31, 2017 2016 Deferred tax assets Employee benefits $ 251 $ 401 Accrued expenses 73 118 Net operating loss, capital loss and tax credit carryforwards 1,113 1,307 Derivative instruments and interest rate and currency swaps 12 22 Debt fair value adjustment 37 74 Investments 968 2,804 Other 6 14 Valuation allowances (171 ) (184 ) Total deferred tax assets 2,289 4,556 Deferred tax liabilities Property, plant and equipment 225 177 Other 20 27 Total deferred tax liabilities 245 204 Net deferred tax assets $ 2,044 $ 4,352 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 decreased our valuation allowances in 2017 by $13 million , primarily due to $4 million release for capital loss carryover as a result of the 2016 return to provision adjustment, $5 million release for foreign operating losses and $24 million reduction related to our investment in NGPL as a result of the reduction of federal tax rate, partially offset by $18 million for state net operating losses and $2 million for foreign tax credits. We have 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 at December 31, 2017. As of December 31, 2016, we had deferred tax assets of $1,128 million related to net operating loss carryovers, $175 million related to alternative minimum and foreign tax credits, $4 million related to capital loss carryovers and valuation allowances related to these deferred tax assets of $123 million . We expect to generate taxable income and utilize federal net operating loss carryforwards and tax credits beginning in 2022. Our alternative minimum tax credit carryforwards decreased by $143 million in 2017 as a result of our decision to elect to forgo bonus depreciation on property placed in service in that year. Code Section 168(k)(4) 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. The corporation may receive a cash refund of the excess notwithstanding that it may not otherwise be paying taxes. We received an income tax refund of $144 million in 2017. The tax impact of ASU 2016-09, which was adopted and effective January 1, 2017, resulted in $8 million of deferred tax assets being recorded through a cumulative-effect adjustment to our retained deficit. The previously unrecorded deferred tax asset is related to net operating loss carryovers as a result of the delayed recognition of a windfall tax benefit related to share-based compensation. Post-adoption the excess tax benefits or deficiencies are recognized for income tax purposes in the period in which they occur through the income statement. Expiration Periods for Deferred Tax Assets: As of December 31, 2017, we have U.S. federal net operating loss carryforwards of $3.4 billion , which will expire from 2018 - 2037; state losses of $3.2 billion which will expire from 2018 - 2037; and foreign losses of $134 million which will expire from 2029 - 2036. We also have $8 million of federal alternative minimum tax credits which do not expire; $147 million of general business credits which will expire from 2018 - 2027; and approximately $21 million of foreign tax credits, which will expire from 2018 - 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, 2017 2016 2015 Balance at beginning of period $ 122 $ 148 $ 189 Additions based on current year tax positions 3 3 4 Additions based on prior year tax positions — 7 — Reductions based on prior year tax positions — (1 ) (6 ) Reductions based on settlements with taxing authority (22 ) (26 ) (25 ) Reductions due to lapse in statute of limitations (2 ) (9 ) (14 ) Impact of the 2017 Tax Reform (4 ) — — Balance at end of period $ 97 $ 122 $ 148 We recognize interest and/or penalties related to income tax matters in income tax expense. We recognized a tax benefit of $9 million , expense of $2 million and a benefit of $4 million at December 31, 2017, 2016, and 2015, respectively. As of December 31, 2017 , 2016, and 2015, we had $19 million , $28 million and $24 million , respectively, of accrued interest. We had no accrued penalties as of both December 31, 2017 and 2016 and $2 million in accrued penalties as of December 31, 2015. All of the $97 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 $6 million during the next year to approximately $91 million , primarily due to lapses in statute of limitations 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 2011-2016 in the U.S., 2005-2016 in various states and 2007-2016 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 we recorded to reflect the change in corporate income tax rates may need to be adjusted in subsequent periods. In addition, the 2017 Tax Reform will require a mandatory deemed repatriation of post-1986 undistributed foreign earnings and profits. As of December 31, 2017, we have recorded a provisional amount for this 2017 Tax Reform provision and we are continuing to finalize earnings and profits used in this calculation as well assess other 2017 Tax Reform impacts to complete our analysis on this provision. However, we do not expect this provision of the 2017 Tax Reform to be material to us. 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. We have determined a reasonable estimate of its impact and recorded a provisional regulatory reserve as of December 31, 2017. However, as the impact on the regulatory rate making process is currently uncertain, we have not completed our assessment of the 2017 Tax Reform’s effect on our FERC regulated business. As described above, we continue to assess the impact of the 2017 Tax Reform on our business in order to complete our analysis. Any adjustment to our provisional amounts will be reported in the reporting period in which any such adjustments are determined and may be material in the period in which the adjustments are made.

Property, Plant and Equipment (

Property, Plant and Equipment (Notes)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure [Text Block]	Property, Plant and Equipment, net Classes and Depreciation As of December 31, 2017 and 2016 , our property, plant and equipment, net consisted of the following (in millions): December 31, 2017 2016 Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 20,157 $ 19,341 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 24,152 23,298 Other(a) 5,570 4,780 Accumulated depreciation, depletion and amortization (14,175 ) (12,306 ) 35,704 35,113 Land and land rights-of-way 1,456 1,431 Construction work in process 2,995 2,161 Property, plant and equipment, net $ 40,155 $ 38,705 _______ (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, 2017 and 2016 , property, plant and equipment, net included $14,055 million and $12,900 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 $2,022 million , $1,970 million , and $2,059 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Asset Retirement Obligations As of December 31, 2017 and 2016 , we recognized asset retirement obligations in the aggregate amount of $208 million and $193 million , respectively, of which $4 million and $9 million , respectively, were classified as current. 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, 2017
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, 2017 and 2016 , our investments consisted of the following (in millions): December 31, 2017 2016 Citrus Corporation $ 1,698 $ 1,709 SNG 1,495 1,505 Ruby 774 798 NGPL Holdings LLC 687 475 Gulf LNG Holdings Group, LLC 461 485 Plantation Pipe Line Company 331 333 EagleHawk 314 329 Utopia Holding LLC 276 55 MEP 253 328 Red Cedar Gathering Company 187 191 Watco Companies, LLC 182 180 Double Eagle Pipeline LLC 149 151 FEP 112 101 Liberty Pipeline Group LLC 71 75 Bear Creek Storage 63 61 Sierrita Gas Pipeline LLC 55 57 Fort Union Gas Gathering L.L.C. 12 25 All others 178 169 Total investments $ 7,298 $ 7,027 As shown in the investment balance table above and the earnings (losses) from equity investments table below, our significant equity investments, as of December 31, 2017 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 Lightfoot Capital Partners, LP, which is majority owned by GE Energy Financial Services. • 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; • BHP Billiton Petroleum (Eagle Ford) 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 operates EagleHawk and owns the remaining 75% ownership interest; • 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; • 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; • 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; • 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% equity interest in the 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% ; • Fort Union Gas Gathering LLC—We own a 37.04% equity interest in the Fort Union Gas Gathering LLC. Crestone Powder River LLC, a subsidiary of ONEOK Partners L.P., owns 37.04% ; Powder River Midstream, LLC owns 11.11% ; and Western Gas Wyoming, LLC owns the remaining 14.81% . Western Gas Resources, Inc. serves as operator of Fort Union Gas Gathering LLC; • Cortez Pipeline Company—We operate the Cortez CO 2 pipeline system, and as of December 31, 2017, we owned 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 (losses) from equity investments were as follows (in millions): Year Ended December 31, 2017 2016 2015 Citrus Corporation $ 108 $ 102 $ 96 SNG 77 58 — FEP 53 51 55 Gulf LNG Holdings Group, LLC 47 48 49 Plantation Pipe Line Company 46 37 29 Cortez Pipeline Company(a) 44 24 (3 ) Ruby 44 15 18 MEP 38 40 45 EagleHawk 24 10 24 Watco Companies, LLC 19 25 16 Red Cedar Gathering Company(b) 14 24 26 Fort Union Gas Gathering L.L.C.(c) 10 1 16 NGPL Holdings LLC 10 12 — Liberty Pipeline Group LLC 9 11 9 Bear Creek Storage 8 2 — Sierrita Gas Pipeline LLC 7 7 9 Double Eagle Pipeline LLC 7 5 3 Parkway Pipeline LLC — 14 5 All others 13 11 17 Total earnings from equity investments $ 578 $ 497 $ 414 Amortization of excess costs (61 ) (59 ) (51 ) _______ (a) 2017, 2016 and 2015 amounts include $(4) million , $9 million and $26 million , respectively, representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company. (b) 2017 amount includes non-cash impairment charges of $10 million (pre-tax) related to our investment. (c) 2016 amount includes non-cash impairment charges of $7 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 2017 2016 2015 Revenues $ 4,703 $ 4,084 $ 3,857 Costs and expenses 3,398 3,056 3,408 Net income $ 1,305 $ 1,028 $ 449 December 31, Balance Sheet 2017 2016 Current assets $ 956 $ 892 Non-current assets 22,344 22,170 Current liabilities 1,241 3,532 Non-current liabilities 10,605 9,187 Partners’/owners’ equity 11,454 10,343

Goodwill Goodwill (Notes)

Goodwill Goodwill (Notes)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 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 $ 17,527 $ 5,812 $ 1,528 $ 2,125 $ 221 $ 1,584 $ 556 $ 29,353 Accumulated impairment losses (1,643 ) (1,597 ) — (1,197 ) (70 ) (679 ) (377 ) (5,563 ) December 31, 2015 15,884 4,215 1,528 928 151 905 179 23,790 Currency translation — — — — — — 6 6 Divestitures(a) (1,635 ) — — — — (9 ) — (1,644 ) December 31, 2016 14,249 4,215 1,528 928 151 896 185 22,152 Currency translation — — — — — — 13 13 Divestitures(b) — — — — — (3 ) — (3 ) December 31, 2017 $ 14,249 $ 4,215 $ 1,528 $ 928 $ 151 $ 893 $ 198 $ 22,162 _______ (a) 2016 includes $1,635 million related to the sale of a 50% interest in our SNG natural gas pipeline system by Natural Gas Pipelines Regulated to Southern Company and $9 million related to certain terminal divestitures. (b) 2017 includes $3 million related to certain terminal divestitures. Refer to Note 2 “Summary of Significant Accounting Policies— Goodwill ” for a description of our accounting for goodwill and Note 4 “Impairments and Losses on Divestitures” for further discussion regarding impairments. 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 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, 2017 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, 2017, each of our reporting units indicated a fair value in excess of their respective carrying values and step 2 was not required. The amount of excess fair value over the carrying value ranged from approximately 3% for our Natural Gas Pipelines Non-Regulated reporting unit to 89% for our Products Pipelines Terminals as of May 31, 2017. 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. Due to the effect of commodity prices on market conditions that impacted the energy sector, during the fourth quarter 2015, we conducted an interim test of the recoverability of goodwill as of December 31, 2015, and concluded that the goodwill of our Natural Gas Pipelines - Non-Regulated reporting unit was impaired by $1.15 billion . The fair value estimates of our reporting unit fair value, and in arriving at the fourth quarter 2015 impairment amount, were based on Level 3 inputs of the fair value hierarchy. A continued period of volatile commodity prices could result in further 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 additional 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, 2017
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, 2017 2016 Unsecured term loan facility, variable rate, due January 26, 2019(a) $ — $ 1,000 Senior note, floating rate, due January 15, 2023(a) 250 — Senior notes, 1.50% through 8.05%, due 2017 through 2098(a)(b)(c) 13,136 13,236 Credit facility due November 26, 2019 125 — Commercial paper borrowings 240 — KML Credit Facility(d) — — KMP senior notes, 2.65% through 9.00%, due 2017 through 2044(c)(e) 18,885 19,485 TGP senior notes, 7.00% through 8.375%, due 2017 through 2037(c)(f) 1,240 1,540 EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(c)(g) 760 1,115 CIG senior notes, 4.15% and 6.85%, due 2026 and 2037(c) 475 475 Kinder Morgan Finance Company, LLC, senior notes, 6.00% and 6.40%, due 2018 and 2036(c) 786 786 Hiland Partners Holdings LLC, senior notes, 5.50%, due 2022(a)(h) — 225 EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035 421 433 Trust I preferred securities, 4.75%, due March 31, 2028(i) 221 221 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(j) 100 100 Other miscellaneous debt(k) 277 285 Total debt – KMI and Subsidiaries 36,916 38,901 Less: Current portion of debt(l) 2,828 2,696 Total long-term debt – KMI and Subsidiaries(m) $ 34,088 $ 36,205 _______ (a) On August 10, 2017, we issued $1 billion of unsecured senior notes with a fixed rate of 3.15% and $250 million of unsecured senior notes with a floating rate, both due January 2023. The net proceeds from the notes were primarily used to repay the principal amount of Hiland’s 5.50% senior notes due 2022, plus accrued interest, and to repay the $1 billion term loan facility due 2019. Interest on the 3.15% senior notes due 2023 is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2018, and the notes will mature on January 15, 2023. Interest on the floating rate senior notes due 2023 is payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, beginning on October 15, 2017, and such notes will mature on January 15, 2023. We may redeem all or a part of the 3.15% fixed rate notes at any time at the redemption prices. The floating rate notes are not redeemable prior to maturity. See (b) and (h) below. (b) Amounts include senior notes that are denominated in Euros and have been converted to U.S. dollars and are respectively reported above at the December 31, 2017 exchange rate of 1.2005 U.S. dollars per Euro and the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro. For the year ended December 31, 2017 , our debt balance increased by $186 million as a result of the change in the exchange rate of U.S dollars per Euro. The 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 ”). In June 2017, we repaid $786 million of maturing 7.00% senior notes and in December 2017, we repaid $500 million of maturing 2.00% senior notes. The December 31, 2017 balance includes the $1 billion of unsecured term notes with a fixed rate of 3.15% due January 15, 2023 discussed in (a) above. (c) Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. (d) The KML Credit Facility is denominated in C$ and has been converted to U.S. dollars and reported above at the December 31, 2017 exchange rate of 0.7971 U.S. dollars per C$. See “—Credit Facilities and Restrictive Covenants ” below. (e) In February 2017, we repaid $600 million of maturing 6.00% senior notes. (f) In April 2017, we repaid $300 million of maturing 7.50% senior notes. (g) In April 2017, we repaid $355 million of maturing 5.95% senior notes. (h) In August 2017, we repaid $225 million of the outstanding principal amount of 5.50% senior notes with a maturity date of May 15, 2022 using net proceeds from the sale of the January 2023 notes (see (a) above). We recognized a $3.8 million loss from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2017 consisting of a $9.3 million premium on the debt repaid and a $5.5 million gain from the write-off of unamortized purchase accounting associated with the early extinguished debt. (i) Capital Trust I (Trust I), is a 100% -owned business trust that as of December 31, 2017 , 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 and 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; (ii) $25.18 in cash without interest; and (iii) 1.100 warrants to purchase a share of our Class P common stock. Our warrants expired on May 25, 2017, along with the portion of the mixed consideration that provided for the conversion into 1.100 warrants to purchase a share of our Class P common stock. We have the right to redeem these Trust I Preferred Securities at any time. Because of the substantive conversion rights of the securities into the mixed consideration, we bifurcated the fair value of the Trust I Preferred Securities into debt and equity components and as of December 31, 2017 , the outstanding balance of $221 million (of which $111 million was classified as current) was bifurcated between debt ( $200 million ) and equity ( $21 million ). (j) As of December 31, 2017 and 2016, 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. (k) In conjunction with the construction of the Totem Gas Storage facility (Totem) and the High Plains pipeline (High Plains), CIG’s joint venture partner in WYCO funded 50% of the construction costs. Upon project completion, the advances were converted into a financing obligation to WYCO. As of December 31, 2017 , the principal amounts of the Totem and High Plains financing obligations were $69 million and $88 million , respectively, which will be paid in monthly installments through 2039 based on the initial lease term. The interest rate on these obligations is 15.5% , payable on a monthly basis. (l) 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. (m) Excludes our “Debt fair value adjustments” which, as of December 31, 2017 and 2016 , increased our combined debt balances by $927 million and $1,149 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. 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 19 “Guarantee of Securities of Subsidiaries.” Credit Facilities and Restrictive Covenants KMI On January 26, 2016, we increased the capacity of our revolving credit agreement, initially entered into during 2014, from $4.0 billion to $5.0 billion . The other terms of our revolving credit agreement remain the same. We also maintain a $4.0 billion commercial paper program through the private placement of short-term notes. The notes mature up to 270 days from the date of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less a discount representing an interest factor or if interest bearing, at par. Borrowings under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility. Our credit facility borrowings bear interest at either (i) LIBOR plus an applicable margin ranging from 1.125% 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; and (3) LIBOR Rate for a one month eurodollar loan, plus 1% , plus, in each case, an applicable margin ranging from 0.125% to 1.00% per annum based on our credit rating. Our credit facility included the following restrictive covenants as of December 31, 2017 : • total debt divided by earnings before interest, income taxes, depreciation and amortization may not exceed: • 6.50 : 1.00 , for the period ended on or prior to December 31, 2017; or • 6.25 : 1.00 , for the period ended after December 31, 2017 and on or prior to December 31, 2018; or • 6.00 : 1.00 , for the period ended after December 31, 2018; • certain limitations on indebtedness, including payments and amendments; • certain limitations on entering into mergers, consolidations, sales of assets and investments; • limitations on granting liens; and • prohibitions on making any dividend to shareholders if an event of default exists or would exist upon making such dividend. As of December 31, 2017 , we had $125 million outstanding under our credit facility, $240 million outstanding under our commercial paper program and $107 million in letters of credit. Our availability under this facility as of December 31, 2017 was $4,528 million . As of December 31, 2017 , we were in compliance with all required covenants. KML On June 16, 2017, KML’s indirect subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, entered into a definitive credit agreement establishing (i) a C $4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the TMEP, (ii) a C $1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional TMEP costs (and, subject to the need to fund such additional costs, meeting the Canadian NEB-mandated liquidity requirements) and (iii) a C $500 million revolving working capital facility to be used for working capital and other general corporate purposes (collectively, the “KML Credit Facility”). On January 23, 2018, KML entered into an agreement amending certain terms of its Credit Facility to, among other things, provide additional funding certainty with respect to each tranche of its Credit Facility. The KML Credit Facility has a five -year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. Any undrawn commitments under the KML Credit Facility will incur a standby fee of 0.30% to 0.625% , with the range dependent on the credit ratings of Kinder Morgan Cochin ULC or KML. The KML Credit Facility is guaranteed by KML and all of the non-borrower subsidiaries of KML and are secured by a first lien security interest on all of the assets of KML and the equity and assets of the other guarantors. Draw downs of funds on the KML Credit Facility bear interest dependent on the type of loans requested and are as follows: • bankers’ acceptances or LIBOR loans are at an annual rate of approximately Canadian Dealer Offered Rate (CDOR); • or the LIBOR, as the case may be, plus a fixed spread ranging from 1.50% to 2.50% ; • loans in Canadian dollars or U.S. dollars are at an annual rate of approximately the Canadian prime rate or the U.S. dollar base rate, as the case may be, plus a fixed spread ranging from 0.50% to 1.50% , in each case, with the range dependent on the credit ratings of KML; and • letters of credit (under the working capital facility only) will have issuance fees based on an annual rate of approximately CDOR plus a fixed spread ranging from 1.50% to 2.50% , with the range dependent on the credit ratings of the Company. The foregoing rates and fees will increase by 0.25% upon the fourth anniversary of the KML Credit Facility. The KML Credit Facility includes various financial and other covenants including: • a maximum ratio of consolidated total funded debt to consolidated capitalization of 70% ; • restrictions on ability to incur debt; • restrictions on ability to make dispositions, restricted payments and investments; • restrictions on granting liens and on sale-leaseback transactions; • restrictions on ability to engage in transactions with affiliates; and • restrictions on ability to amend organizational documents and engage in corporate reorganization transactions. As of December 31, 2017 , KML had C $447 million available under its five year C $500 million working capital facility (after reducing the capacity for the C $53.0 million (U.S. $42 million ) in letters of credit) and no amounts outstanding under its C $4.0 billion construction facility or its C $1.0 billion revolving contingent credit facility. As of December 31, 2017 , KML was in compliance with all required covenants. Current Portion of Debt The primary components of our current portion of debt include the following significant series of long-term notes (in millions): As of December 31, 2017 $750 Kinder Morgan Finance Company, LLC, 6.00% senior notes due January 2018 $82 7.00% senior notes due February 2018 $975 KMP 5.95% senior notes due February 2018 $477 7.25% senior notes due June 2018 As of December 31, 2016 $600 KMP 6.00% senior notes due February 2017 $300 TGP 7.50% senior notes due April 2017 $355 EPNG 5.95% senior notes due April 2017 $786 7.00% senior notes due June 2017 $500 2.00% senior notes due December 2017 Subsequent Event—Debt Repayments In January 2018, we repaid $750 million of maturing 6.00% Kinder Morgan Finance Company, LLC senior notes and in February 2018, we repaid $82 million of maturing 7.00% senior notes both listed above in current portion of debt as of December 31, 2017. Maturities of Debt The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2017 , are summarized as follows (in millions): Year Total 2018 $ 2,828 2019 2,820 2020 2,204 2021 2,422 2022 2,558 Thereafter 24,084 Total $ 36,916 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, 2017 , 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 2017 2016 Purchase accounting debt fair value adjustments $ 719 $ 806 Carrying value adjustment to hedged debt 115 220 Unamortized portion of proceeds received from the early termination of interest rate swap agreements 297 342 Unamortized debt discounts, net (74 ) (80 ) Unamortized debt issuance costs (130 ) (139 ) Total debt fair value adjustments $ 927 $ 1,149 Interest Rates, Interest Rate Swaps and Contingent Debt The weighted average interest rate on all of our borrowings was 5.02% during 2017 and 4.95% during 2016 . Information on our interest rate swaps is contained in Note 14 “Risk Management.” 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 Share-based Compensation and Employee Benefits (Notes)	12 Months Ended
	Dec. 31, 2017
Share-based Compensation [Abstract]
Share based compensation and pension and other postretirement benefits disclosure [Text Block]	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 2017 , 2016 and 2015 , we made restricted Class P common stock grants to our non-employee directors of 17,740 , 31,880 and 9,580 , respectively. These grants were valued at time of issuance at $400,000 , $400,000 and $401,000 , 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, 2017 December 31, 2016 December 31, 2015 Shares Weighted Average Shares Weighted Average Shares Weighted Average Grant Date Fair Value Outstanding at beginning of period 9,038,137 $ 32.72 7,645,105 $ 37.91 7,373,294 $ 37.63 Granted 3,221,691 19.52 2,816,599 21.36 1,488,467 38.20 Vested (1,501,939 ) 36.67 (1,226,652 ) 38.53 (817,797 ) 35.66 Forfeited (239,545 ) 28.34 (196,915 ) 35.74 (398,859 ) 38.51 Outstanding at end of period 10,518,344 $ 28.21 9,038,137 $ 32.72 7,645,105 $ 37.91 The intrinsic value of restricted stock awards vested during the years ended December 31, 2017 , 2016 and 2015 was $30 million , $25 million and $31 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 2018 2,272,019 2019 4,268,118 2020 3,647,967 2021 199,850 2022 65,928 Thereafter 64,462 Total Outstanding 10,518,344 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 2017 , 2016 and 2015 , we recorded $65 million , $66 million and $52 million , respectively, in expense related to restricted stock awards and capitalized approximately $9 million , $9 million and $15 million , respectively. At December 31, 2017 and 2016 , unrecognized restricted stock awards compensation costs, less estimated forfeitures, was approximately $112 million and $133 million , respectively. 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, 2017, we recognized $1 million of expense and capitalized $1 million related to these compensation programs. At December 31, 2017, unrecognized compensation costs, less estimated forfeitures associated with KML’s restricted share unit awards, was approximately $8 million . 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 $47 million , $47 million , and $46 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Pension Plans Our U.S. 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. Two of our subsidiaries, Kinder Morgan Canada Inc. and Trans Mountain Pipeline ULC (as general partner of Trans Mountain Pipeline L.P.), are sponsors of pension plans for eligible Canadian and Trans Mountain pipeline employees. The plans include registered defined benefit pension plans, supplemental unfunded arrangements (which provide pension benefits in excess of statutory limits) and defined contributory plans. Benefits under the defined benefit components accrue through career pay or final pay formulas. The net periodic benefit costs, contributions and liability amounts associated with our Canadian plans are not material to our consolidated income statements or balance sheets; however, we began to include the activity and balances associated with our Canadian plans (including our Canadian OPEB plans discussed below) in the following disclosures on a prospective basis beginning in 2016. For the year ended December 31, 2015, the associated net periodic benefit costs for these combined Canadian plans of $12 million were reported separately. Other Postretirement Benefit Plans We and certain of our U.S. 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. Our Canadian subsidiaries also provide OPEB benefits to current and future retirees and their dependents. The U.S. 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. 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, 2017 and 2016 (in millions): Pension Benefits OPEB 2017 2016 2017 2016 Change in benefit obligation: Benefit obligation at beginning of period $ 2,884 $ 2,654 $ 473 $ 509 Service cost 40 36 1 1 Interest cost 88 89 13 16 Actuarial loss (gain) 155 127 (16 ) (42 ) Benefits paid (180 ) (180 ) (38 ) (41 ) Participant contributions 3 3 2 2 Medicare Part D subsidy receipts — — 1 1 Exchange rate changes 13 4 1 1 Settlements (21 ) — — — Other(a) — 151 (12 ) 26 Benefit obligation at end of period 2,982 2,884 425 473 Change in plan assets: Fair value of plan assets at beginning of period 2,160 2,050 332 325 Actual return on plan assets 292 157 29 29 Employer contributions 32 8 9 16 Participant contributions 3 3 2 2 Medicare Part D subsidy receipts — — 1 1 Benefits paid (180 ) (180 ) (38 ) (41 ) Exchange rate changes 10 3 — — Settlements (21 ) — — — Other(a) — 119 — — Fair value of plan assets at end of period 2,296 2,160 335 332 Funded status - net liability at December 31, $ (686 ) $ (724 ) $ (90 ) $ (141 ) _______ (a) 2017 amounts represent December 31, 2016 balances associated with our Plantation Pipeline OPEB plan that are no longer included in these disclosures. 2016 amounts primarily represent December 31, 2015 balances associated with our Canadian pension and OPEB plans for prospective inclusion in these disclosures, which associated net periodic benefit costs were reported separately in years prior to 2016. Components of Funded Status . The following table details the amounts recognized in our balance sheets at December 31, 2017 and 2016 related to our pension and OPEB plans (in millions): Pension Benefits OPEB 2017 2016 2017 2016 Non-current benefit asset(a) $ — $ — $ 198 $ 153 Current benefit liability — — (15 ) (16 ) Non-current benefit liability (686 ) (724 ) (273 ) (278 ) Funded status - net liability at December 31, $ (686 ) $ (724 ) $ (90 ) $ (141 ) _______ (a) 2017 and 2016 OPEB amounts include $33 million and $29 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, 2017 and 2016 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 2017 2016 2017 2016 Unrecognized net actuarial (loss) gain $ (635 ) $ (682 ) $ 88 $ 69 Unrecognized prior service (cost) credit (4 ) (5 ) 17 18 Accumulated other comprehensive (loss) income $ (639 ) $ (687 ) $ 105 $ 87 We anticipate that approximately $34 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 2018 , including approximately $36 million of unrecognized net actuarial loss and approximately $2 million of unrecognized prior service credit. Our accumulated benefit obligation for our pension plans was $2,840 million and $2,834 million at December 31, 2017 and 2016 , respectively. Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $373 million and $415 million at December 31, 2017 and 2016 , respectively. The fair value of these plans’ assets was approximately $84 million and $121 million at December 31, 2017 and 2016 , respectively. Plan Assets. The investment policies and strategies are established by the Fiduciary Committee for the assets of each of the U.S. pension and OPEB plans and by the Pension Committee for the assets of the Canadian pension plans (the “Committees”), which are responsible for investment decisions and management oversight of the plans. The stated philosophy of each of the Committees 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 Committees recognize 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 Committees have each adopted a strategy of using multiple asset classes. As of December 31, 2017 , the allowable range for asset allocations in effect for our U.S. 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, 2017 , the allowable range for asset allocations in effect for our U.S. retiree medical and retiree life insurance plans were 15% to 55% equity, 15% to 47% fixed income, 0% to 20% cash and 13% to 39% MLPs. As of December 31, 2017 , the target asset allocation for our Canadian pension plans that are closed to new participants was 90% fixed income and 10% equity. The target allocation for the remaining Canadian pension plans were 45% fixed income and 55% equity. 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, 2017 and 2016 (in millions): Pension Assets 2017 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Cash $ 6 $ — $ — $ 6 $ 10 $ — $ — $ 10 Short-term investment funds — 65 — 65 — 100 — 100 Mutual funds(a) 245 — — 245 197 — — 197 Equities(b) 278 — — 278 283 — — 283 Fixed income securities(c) — 416 — 416 — 428 — 428 Immediate participation guarantee contract — — — — — — 16 16 Derivatives — 5 — 5 — (2 ) — (2 ) Subtotal $ 529 $ 486 $ — 1,015 $ 490 $ 526 $ 16 1,032 Measured at NAV(d) Common/collective trusts(e) 895 829 Private investment funds(f) 337 290 Private limited partnerships(g) 49 9 Subtotal 1,281 1,128 Total plan assets fair value $ 2,296 $ 2,160 _______ (a) Includes mutual funds which are invested in equity. (b) Plan assets include $110 million and $126 million of KMI Class P common stock for 2017 and 2016 , respectively. (c) For 2016, plan assets include $1 million of KMI debt securities. (d) Plan assets for which fair value was measured using NAV as a practical expedient. (e) Common/collective trust funds were invested in approximately 36% fixed income and 64% equity in 2017 and 39% fixed income and 61% equity in 2016 . (f) Private investment funds were invested in approximately 52% fixed income and 48% equity in 2017 and 54% fixed income and 46% equity in 2016 . (g) Includes assets invested in real estate, venture and buyout funds. 2016 also includes high yield investments. OPEB Assets 2017 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Short-term investment funds $ — $ 7 $ — $ 7 $ — $ 15 $ — $ 15 Equities(a) 16 — — 16 11 — — 11 MLPs 50 — — 50 57 — — 57 Guaranteed insurance contracts — — 49 49 — — 47 47 Mutual funds 1 — — 1 1 — — 1 Subtotal $ 67 $ 7 $ 49 123 $ 69 $ 15 $ 47 131 Measured at NAV(b) Common/collective trusts(c) 68 68 Fixed income trusts 66 64 Limited partnerships(d) 78 69 Subtotal 212 201 Total plan assets fair value $ 335 $ 332 _______ (a) Plan assets include $2 million of KMI Class P common stock for each 2017 and 2016. (b) Plan assets for which fair value was measured using NAV as a practical expedient. (c) Common/collective trust funds were invested in approximately 71% equity and 29% fixed income securities for 2017 and 72% equity and 28% fixed income securities for 2016 . (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, 2017 and 2016 (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 ) $ — 2016 Insurance contracts $ 15 $ — $ 1 $ — $ 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 2017 Insurance contracts $ 47 $ — $ 5 $ (3 ) $ 49 2016 Insurance contracts $ 49 $ — $ (2 ) $ — $ 47 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, 2017 and 2016 . Expected Payment of Future Benefits and Employer Contributions . As of December 31, 2017 , we expect to make the following benefit payments under our plans (in millions): Fiscal year Pension Benefits OPEB(a) 2018 $ 244 $ 36 2019 241 36 2020 242 35 2021 232 34 2022 230 33 2023 - 2027 1,029 149 _______ (a) Includes a reduction of approximately $2 million in each of the years 2018 - 2022 and approximately $13 million in aggregate for 2023 - 2027 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. In 2018 , we expect to contribute approximately $30 million to our U.S. pension plans and $7 million , net of anticipated subsidies, to our U.S. OPEB plans. In 2018 , we expect to contribute approximately $10 million to our Canadian pension plans and $1 million to our Canadian OPEB plan. 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 2017 , 2016 and 2015 : Pension Benefits OPEB 2017 2016 2015 2017 2016 2015 Assumptions related to benefit obligations: Discount rate 3.56 % 3.83 % 4.05 % 3.48 % 3.69 % 3.91 % Rate of compensation increase 3.53 % 3.52 % 3.50 % n/a n/a n/a Assumptions related to benefit costs: Discount rate for benefit obligations 3.83 % 4.05 % 3.66 % 3.69 % 3.91 % 3.56 % Discount rate for interest on benefit obligations 3.09 % 3.24 % 3.66 % 3.05 % 3.18 % 3.56 % Discount rate for service cost 3.88 % 4.15 % 3.66 % 4.15 % 4.36 % 3.56 % Discount rate for interest on service cost 3.24 % 3.50 % 3.66 % 3.95 % 4.17 % 3.56 % Expected return on plan assets(a) 7.07 % 7.31 % 7.50 % 6.84 % 7.07 % 7.08 % Rate of compensation increase 3.52 % 3.51 % 4.50 % 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 2017 , 2016 and 2015 . Prior to 2016, we selected our discount rates by matching the timing and amount of our expected future benefit payments for our pension and other postretirement benefit obligations to the average yields of various high-quality bonds with corresponding maturities. Effective January 1, 2016, we changed our estimate of the service and interest cost components of net periodic benefit cost (credit) for our pension and other postretirement benefit plans. The new estimate utilizes a full yield curve approach in the estimation of these components 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 new estimate provides a more precise measurement of service and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates. The change did not affect the measurement of our pension and postretirement benefit obligations and it was accounted for as a change in accounting estimate, which was applied prospectively. 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 7.71% , 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, 2017 and 2016 (in millions): 2017 2016 One-percentage point increase: Aggregate of service cost and interest cost $ 1 $ 1 Accumulated postretirement benefit obligation 22 27 One-percentage point decrease: Aggregate of service cost and interest cost $ (1 ) $ (1 ) Accumulated postretirement benefit obligation (19 ) (23 ) 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 2017 2016 2015 2017 2016 2015 Components of net benefit cost: Service cost $ 40 $ 36 $ 33 $ 1 $ 1 $ — Interest cost 88 89 99 13 16 21 Expected return on assets (147 ) (151 ) (172 ) (19 ) (19 ) (23 ) Amortization of prior service cost (credit) 1 1 — (3 ) (3 ) (3 ) Amortization of net actuarial loss (gain) 52 35 5 (6 ) — 1 Curtailment and settlement loss 5 — — — — — Net benefit (credit) cost(a) 39 10 (35 ) (14 ) (5 ) (4 ) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 17 116 267 (25 ) (48 ) (49 ) Prior service cost (credit) arising during period — — — — — — Amortization or settlement recognition of net actuarial (loss) gain (64 ) (34 ) (5 ) 6 — (1 ) Amortization of prior service credit (1 ) — — 1 1 1 Exchange rate changes — 1 — — — — Total recognized in total other comprehensive (income) loss (48 ) 83 262 (18 ) (47 ) (49 ) Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ (9 ) $ 93 $ 227 $ (32 ) $ (52 ) $ (53 ) _______ (a) 2017 and 2016 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 , $8 million and $10 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. 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, 2017
Stockholders' Equity Note [Abstract]
Shareholders' Equity	Stockholders’ Equity Common Equity As of December 31, 2017 , 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 year ended December 31, 2017, we repurchased approximately 14 million of our Class P shares for approximately $250 million . Subsequent to December 31, 2017 and through February 8, 2018, we repurchased approximately 13 million of our Class P shares for approximately $250 million . On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the managers party thereto, as sales agents and/or principals, shares of our Class P common stock having an aggregate offering of up to $5.0 billion from time to time during the term of this agreement. During the years ended December 31, 2017 and 2016 we did not issue any Class P common stock under this agreement. During the year ended December 31, 2015, we issued and sold 102,614,508 shares of our Class P common stock pursuant to the equity distribution agreement resulting in net proceeds of $3.9 billion . 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, 2017 2016 2015 Per common share cash dividend declared for the period $ 0.50 $ 0.50 $ 1.605 Per common share cash dividend paid in the period 0.50 0.50 1.93 On January 17, 2018, our board of directors declared a cash dividend of $0.125 per common share for the quarterly period ended December 31, 2017, which is payable on February 15, 2018 to shareholders of record as of January 31, 2018. Warrants During the year ended December 31, 2015, we paid a total of $12 million for the repurchases of 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. Mandatory Convertible Preferred Stock On October 30, 2015, we completed an offering of 32,000,000 depositary shares, each of which represents a 1/20th interest in a share of our 1,600,000 shares of 9.75% Series A mandatory convertible preferred stock, with a liquidating preference of $1,000 per share (equal to a $50 liquidation preference per depositary share). Net proceeds, after underwriting discount and expenses, from the depositary share offering were approximately $1,541 million . The proceeds from the offering were used to repay borrowings under our revolving credit facility and commercial paper debt and for general corporate purposes. Unless converted earlier at the option of the holders, on or around October 26, 2018, each share of convertible preferred stock will automatically convert into between 30.8800 and 36.2840 shares of our common stock (and, correspondingly, each depositary share will convert into between 1.5440 and 1.8142 shares of our common stock), subject to customary anti-dilution adjustments. The conversion range depends on the volume-weighted average price of our common stock over a 20 trading day averaging period immediately prior to that date (Applicable Market Value). If the Applicable Market Value for our common stock is greater than $32.38 or less than $27.56 , the conversion rate per preferred stock will be 30.8800 or 36.2840 , respectively. If the Applicable Market Value is between $32.38 and $27.56 , the conversion rate per preferred stock will be between 30.8800 and 36.2840 . Preferred Stock Dividends Dividends on our mandatory convertible preferred stock are 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. We may pay dividends in cash or, subject to certain limitations, in shares of common stock or any combination of cash and shares of common stock. The terms of the mandatory convertible preferred stock provide that, unless full cumulative dividends have been paid or set aside for payment on all outstanding mandatory convertible preferred stock for all prior dividend periods, no dividends may be declared or paid on common stock. 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, 2017 through April 25, 2017 $24.375 January 18, 2017 April 11, 2017 April 26, 2017 April 26, 2017 through July 25, 2017 24.375 April 19, 2017 July 11, 2017 July 26, 2017 July 26, 2017 through October 25, 2017 24.375 July 19, 2017 October 11, 2017 October 26, 2017 October 26, 2017 through January 25, 2018 24.375 October 18, 2017 January 11, 2018 January 26, 2018 The cash dividend of $24.375 per share of our mandatory convertible preferred stock is equivalent to $1.21875 per depository share. Noncontrolling Interests KML Restricted Voting Shares As discussed in Note 3 “Acquisitions and Divestitures,” 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 established 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). Dividends on the Series 1 Preferred Shares are fixed, cumulative, preferential and C$1.3125 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding November 15, 2022. Dividends on the Series 3 Preferred Shares are fixed, cumulative, preferential and C$1.3000 per share annually, payable quarterly on the 15th day of February, May, August and November, as and when declared by the KML’s board of directors, for the initial fixed rate period to but excluding February 15, 2023. The following table provides information regarding distributions to our noncontrolling interests (in millions except per share and share distribution amounts): Year Ended December 31, 2017 Shares U.S.$ C$ KML Restricted Voting Shares(a) Per restricted voting share declared for the period(b) $0.3821 Per restricted voting share paid in the period $0.1739 0.2196 Total value of distributions paid in the period 18 23 Cash distributions paid in the period to the public 13 16 Share distributions paid in the period to the public under KML’s DRIP 418,989 KML Series 1 Preferred Shares(c) Per Series 1 Preferred Share paid in the period $0.2624 $0.3308 Cash distributions paid in the period to the public 3 4 _______ (a) Represents dividends subsequent to KML’s May 30, 2017 IPO. (b) The U.S.$ equivalent of the dividends declared is calculated based on the exchange rate on the dividend payment date, therefore, the U.S.$ equivalent of the dividend declared for the fourth quarter of 2017 will be calculated using the exchange rate on February 15, 2018. The combined U.S.$ equivalent of the dividends declared for the second and third quarters of 2017 was $0.1739 . (c) Represents dividends subsequent to the issuance of KML’s Series 1 Preferred Shares. On January 17, 2018, KML’s board of directors declared a cash dividend of C$0.328125 per share of its Series 1 Preferred Shares for the period from and including November 15, 2017 through and including February 14, 2018, which is payable on February 15, 2018 to Series 1 Preferred Shareholders of record as of the close of business on January 31, 2018. On January 17, 2018, KML’s board of directors declared a cash dividend of C$0.22082 per share of its Series 3 Preferred Shares for the period from and including December 15, 2017 through and including February 14, 2018, which is payable on February 15, 2018 to Series 3 Preferred Shareholders of record as of the close of business on January 31, 2018.

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2017
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 “Investments” for additional information related to these investments); and (ii) external joint venture partners of 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, 2017 2016 Balance sheet location Accounts receivable, net $ 34 $ 37 Other current assets 8 — Deferred charges and other assets 23 10 $ 65 $ 47 Current portion of debt $ 6 $ 6 Accounts payable 18 28 Other current liabilities 4 9 Long-term debt 155 161 Other long-term liabilities and deferred credits 35 29 $ 218 $ 233 Year Ended December 31, 2017 2016 2015 Income statement location Revenues Services $ 73 $ 71 $ 72 Product sales and other 89 71 71 $ 162 $ 142 $ 143 Operating Costs, Expenses and Other Costs of sales $ 20 $ 38 $ 60 Other operating expenses 100 75 55

Commitments and Contingent Liab

Commitments and Contingent Liabilities (Notes)	12 Months Ended
	Dec. 31, 2017
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, 2017 (in millions): Year Commitment 2018 $ 118 2019 106 2020 81 2021 62 2022 55 Thereafter 300 Total minimum payments $ 722 The remaining terms on our operating leases, including probable elections to exercise renewal options, range from one to forty-one years. Total lease and rental expenses were $140 million , $138 million and $143 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The amount of capital leases included within “Property, plant and equipment, net” in our accompanying consolidated balance sheets as of December 31, 2017 and 2016 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, 2017 and 2016, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $1,070 million and $1,179 million , respectively. Both December 31, 2017 and 2016 amounts are primarily represented by our proportional share of the debt obligations of two equity investees. Under such guarantees we are severally liable for our percentage ownership share of these equity investees’ debt issued in the event of their non-performance. 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 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 100% of the debt issued by another Cortez Pipeline Company subsidiary to fund an expansion project, of which debt consists of a $50 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, and we expect future requirements to perform under quantifiable arrangements will be immaterial. 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 17 “Litigation, Environmental and Other Contingencies” 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, 2017
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. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks. In addition, prior to May 2016, we had legacy power forward and swap contracts related to operations of acquired businesses. Energy Commodity Price Risk Management As of December 31, 2017 , 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 (21.0 ) MMBbl Crude oil basis (7.2 ) MMBbl Natural gas fixed price (46.4 ) Bcf Natural gas basis (21.7 ) Bcf Derivatives not designated as hedging contracts Crude oil fixed price (1.9 ) MMBbl Crude oil basis (1.2 ) MMBbl Natural gas fixed price (9.0 ) Bcf Natural gas basis (23.1 ) Bcf NGL fixed price (4.1 ) MMBbl As of December 31, 2017 , 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 2021. Interest Rate Risk Management As of December 31, 2017 and December 31, 2016 , we had a combined notional principal amount of $9,575 million and $9,775 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, 2017 , the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035. Foreign Currency Risk Management As of both December 31, 2017 and 2016, 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. 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, 2017 2016 2017 2016 Location Fair value Fair value Derivatives designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 65 $ 101 $ (53 ) $ (57 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 14 70 (24 ) (24 ) Subtotal 79 171 (77 ) (81 ) Interest rate swap agreements Fair value of derivative contracts/(Other current liabilities) 41 94 (3 ) — Deferred charges and other assets/(Other long-term liabilities and deferred credits) 164 206 (62 ) (57 ) Subtotal 205 300 (65 ) (57 ) Cross-currency swap agreements Fair value of derivative contracts/(Other current liabilities) — — (6 ) (7 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 166 — — (24 ) Subtotal 166 — (6 ) (31 ) Total 450 471 (148 ) (169 ) Derivatives not designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 8 3 (22 ) (29 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (2 ) (1 ) Total 8 3 (24 ) (30 ) Total derivatives $ 458 $ 474 $ (172 ) $ (199 ) Effect of Derivative Contracts on the Income Statement The following tables summarize the impact of our derivative contracts on 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, 2017 2016 2015 Interest rate swap agreements Interest, net $ (103 ) $ (180 ) $ 25 Hedged fixed rate debt Interest, net $ 105 $ 160 $ (33 ) 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, 2017 2016 2015 2017 2016 2015 2017 2016 2015 Energy commodity derivative contracts $ 24 $ (115 ) $ 201 Revenues—Natural gas sales $ 12 $ 15 $ 54 Revenues—Natural gas sales $ — $ — $ — Revenues—Product sales and other 35 148 236 Revenues—Product sales and other 11 (12 ) 2 Costs of sales 9 (17 ) (15 ) Costs of sales — — — Interest rate swap agreements(c) — (2 ) (4 ) Interest, net (3 ) (3 ) (3 ) Interest, net — — — Cross-currency swap 121 13 (33 ) Other, net 118 (27 ) — Other, net — — — Total $ 145 $ (104 ) $ 164 Total $ 171 $ 116 $ 272 Total $ 11 $ (12 ) $ 2 _______ (a) We expect to reclassify an approximate $1 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of December 31, 2017 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) 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 loss. Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives Year Ended December 31, 2017 2016 2015 Energy commodity derivative contracts Revenues—Natural gas sales $ 20 $ (10 ) $ 17 Revenues—Product sales and other (16 ) (26 ) 176 Costs of sales — 3 (2 ) Interest rate swap agreements Interest, net — 63 (15 ) Total(a) $ 4 $ 30 $ 176 ________ (a) For the years ended December 31, 2017 , 2016 and 2015 includes approximate gains of $57 million , $73 million and $31 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, 2017 and 2016 , we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2017 and December 31, 2016, we had cash margins of $1 million and $37 million , respectively, posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets. The balance at December 31, 2017 , consisted of initial margin requirements of $13 million , offset by variation margin requirements of $12 million . We also use industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize 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, 2017 , based on our current mark to market positions and posted collateral, we estimate that if our credit rating were downgraded one notch we would be required to post $31 million of additional collateral and no additional collateral beyond this $31 million if we were downgraded two notches. 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 as of December 31, 2014 $ 327 $ (108 ) $ (236 ) $ (17 ) Other comprehensive gain (loss) before reclassifications 164 (214 ) (122 ) (172 ) Gains reclassified from accumulated other comprehensive loss (272 ) — — (272 ) Net current-period other comprehensive loss (108 ) (214 ) (122 ) (444 ) Balance as of 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 as of 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 as of December 31, 2017 $ (27 ) $ (189 ) $ (325 ) $ (541 )

Fair Value (Notes)

Fair Value (Notes)	12 Months Ended
	Dec. 31, 2017
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, 2017 Energy commodity derivative contracts(a) $ 17 $ 70 $ — $ 87 $ (42 ) $ (12 ) $ 33 Interest rate swap agreements $ — $ 205 $ — $ 205 $ (15 ) $ — $ 190 Cross-currency swap agreements $ — $ 166 $ — $ 166 $ (6 ) $ — $ 160 As of December 31, 2016 Energy commodity derivative contracts(a) $ 6 $ 168 $ — $ 174 $ (43 ) $ — $ 131 Interest rate swap agreements $ — $ 300 $ — $ 300 $ (18 ) $ — $ 282 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, 2017 Energy commodity derivative contracts(a) $ (3 ) $ (98 ) $ — $ (101 ) $ 42 $ — $ (59 ) Interest rate swap agreements $ — $ (65 ) $ — $ (65 ) $ 15 $ — $ (50 ) Cross-currency swap agreements $ — $ (6 ) $ — $ (6 ) $ 6 $ — $ — As of December 31, 2016 Energy commodity derivative contracts(a) $ (29 ) $ (82 ) $ — $ (111 ) $ 43 $ 37 $ (31 ) Interest rate swap agreements $ — $ (57 ) $ — $ (57 ) $ 18 $ — $ (39 ) Cross-currency swap agreements $ — $ (31 ) $ — $ (31 ) $ — $ — $ (31 ) _______ (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. The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts (in millions): Significant unobservable inputs (Level 3) Year Ended December 31, 2017 2016 Derivatives-net asset (liability) Beginning of period $ — $ (15 ) Total gains or (losses) included in earnings — (9 ) Settlements — 24 End of period $ — $ — The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date $ — $ — During 2016, our Level 3 derivative asset and liability activity consisted primarily of power derivative contracts (which expired in April 2016), where a significant portion of fair value is calculated from underlying market data that is not readily observable. The derived values use industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value, and management would not expect materially different valuation results were we to use different input amounts within reasonable ranges. Fair Value of Financial Instruments The carrying value and estimated fair value of our outstanding debt balances is disclosed below (in millions): December 31, 2017 December 31, 2016 Carrying value Estimated fair value Carrying value Estimated fair value Total debt $ 37,843 $ 40,050 $ 40,050 $ 41,015 We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2017 and 2016 .

Reportable Segments (Notes)

Reportable Segments (Notes)	12 Months Ended
	Dec. 31, 2017
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; • CO 2 —(i) the production, transportation and marketing of CO 2 to oil fields that use CO 2 as a flooding medium for recovering crude oil from mature oil fields to increase production; (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; • 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, chemicals, and ethanol and bulk products, including petroleum coke, steel and coal; and (ii) Jones Act tankers; • 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; and • Kinder Morgan Canada—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, plus the Jet Fuel aviation turbine fuel pipeline that serves the Vancouver (Canada) International Airport. 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 2017, 2016 and 2015, 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, 2017 2016 2015 Revenues Natural Gas Pipelines Revenues from external customers $ 8,608 $ 7,998 $ 8,704 Intersegment revenues 10 7 21 CO 2 1,196 1,221 1,699 Terminals Revenues from external customers 1,965 1,921 1,878 Intersegment revenues 1 1 1 Products Pipelines Revenues from external customers 1,645 1,631 1,828 Intersegment revenues 16 18 3 Kinder Morgan Canada 256 253 260 Corporate and intersegment eliminations(a) 8 8 9 Total consolidated revenues $ 13,705 $ 13,058 $ 14,403 Year Ended December 31, 2017 2016 2015 Operating expenses(b) Natural Gas Pipelines $ 5,457 $ 4,393 $ 4,738 CO 2 394 399 432 Terminals 788 768 836 Products Pipelines 487 573 772 Kinder Morgan Canada 95 87 87 Corporate and intersegment eliminations (6 ) 2 26 Total consolidated operating expenses $ 7,215 $ 6,222 $ 6,891 Year Ended December 31, 2017 2016 2015 Other expense (income)(c) Natural Gas Pipelines $ 26 $ 199 $ 1,269 CO 2 (1 ) 19 606 Terminals (14 ) 99 190 Products Pipelines — 76 2 Kinder Morgan Canada — — (1 ) Corporate 1 (7 ) — Total consolidated other expense (income) $ 12 $ 386 $ 2,066 Year Ended December 31, 2017 2016 2015 DD&A Natural Gas Pipelines $ 1,011 $ 1,041 $ 1,046 CO 2 493 446 556 Terminals 472 435 433 Products Pipelines 216 221 206 Kinder Morgan Canada 46 44 46 Corporate 23 22 22 Total consolidated DD&A $ 2,261 $ 2,209 $ 2,309 Year Ended December 31, 2017 2016 2015 Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments Natural Gas Pipelines $ 253 $ (269 ) $ 285 CO 2 42 22 (5 ) Terminals 24 19 17 Products Pipelines 48 56 36 Total consolidated equity earnings $ 367 $ (172 ) $ 333 Year Ended December 31, 2017 2016 2015 Other, net-income (expense) Natural Gas Pipelines $ 49 $ 19 $ 24 Terminals 8 4 8 Products Pipelines (1 ) 2 4 Kinder Morgan Canada 25 15 8 Corporate 1 4 (1 ) Total consolidated other, net-income (expense) $ 82 $ 44 $ 43 Year Ended December 31, 2017 2016 2015 Segment EBDA(d) Natural Gas Pipelines $ 3,487 $ 3,211 $ 3,067 CO 2 847 827 658 Terminals 1,224 1,078 878 Products Pipelines 1,231 1,067 1,106 Kinder Morgan Canada 186 181 182 Total segment EBDA 6,975 6,364 5,891 DD&A (2,261 ) (2,209 ) (2,309 ) Amortization of excess cost of equity investments (61 ) (59 ) (51 ) General and administrative and corporate charges (660 ) (652 ) (708 ) Interest, net (1,832 ) (1,806 ) (2,051 ) Income tax expense (1,938 ) (917 ) (564 ) Total consolidated net income $ 223 $ 721 $ 208 Year Ended December 31, 2017 2016 2015 Capital expenditures Natural Gas Pipelines $ 1,376 $ 1,227 $ 1,642 CO 2 436 276 725 Terminals 888 983 847 Products Pipelines 127 244 524 Kinder Morgan Canada 338 124 142 Corporate 23 28 16 Total consolidated capital expenditures $ 3,188 $ 2,882 $ 3,896 2017 2016 Investments at December 31 Natural Gas Pipelines $ 6,218 $ 6,185 CO 2 6 — Terminals 263 252 Products Pipelines 777 566 Kinder Morgan Canada 34 20 Corporate — 4 Total consolidated investments $ 7,298 $ 7,027 2017 2016 Assets at December 31 Natural Gas Pipelines $ 51,173 $ 50,428 CO 2 3,946 4,065 Terminals 9,935 9,725 Products Pipelines 8,539 8,329 Kinder Morgan Canada 2,080 1,572 Corporate assets(e) 3,382 6,108 Assets held for sale — 78 Total consolidated assets $ 79,055 $ 80,305 _______ (a) Includes a management fee 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 impairment of goodwill, loss on impairments and divestitures, net and other income, net. (d) Includes revenues, earnings from equity investments, other, net, less operating expenses, and other income, net, loss on impairment of goodwill, and loss on impairments and divestitures, net and loss on impairments and divestitures of equity investments, net. (e) Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, 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 the 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, 2017 2016 2015 Revenues from external customers U.S. $ 13,073 $ 12,459 $ 13,797 Canada 503 483 479 Mexico 129 116 127 Total consolidated revenues from external customers $ 13,705 $ 13,058 $ 14,403 December 31, 2017 2016 2015 Long-term assets, excluding goodwill and other intangibles U.S. $ 47,928 $ 49,125 $ 51,679 Canada 3,071 2,399 2,193 Mexico 80 82 67 Total consolidated long-lived assets $ 51,079 $ 51,606 $ 53,939

Litigation, Environmental and O

Litigation, Environmental and Other Contingencies (Notes)	12 Months Ended
	Dec. 31, 2017
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 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. With respect to the various SFPP related complaints and protest proceedings at the FERC, we estimate that the shippers are seeking approximately $40 million in annual rate reductions and approximately $230 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. 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. EPNG and two intervenors sought rehearing of certain aspects of the decision, and the judicial review sought by certain intervenors has been delayed until the FERC issues an order on rehearing. All refund obligations related to the 2008 rate case were satisfied during calendar year 2015. With respect to the 2010 rate case, EPNG believes it has an appropriate reserve related to the findings in Opinions 517-A and 528-A. NGPL and WIC On January 19, 2017, FERC initiated separate proceedings against NGPL and WIC pursuant to section 5 of the Natural Gas Act. The matters were intended to determine whether NGPL’s and WIC’s current rates were just and reasonable. NGPL and WIC each submitted an Offer of Settlement to the FERC in their respective proceedings. The FERC approved WIC’s Offer of Settlement on November 27, 2017, and the FERC approved NGPL’s Offer of Settlement on January 5, 2018. These settlements will not have a material adverse impact on KMI’s results of operations or cash flows from operations. TMEP Litigation There are numerous legal challenges pending before the Federal Court of Appeal which have been filed by various governmental and non-governmental organizations, Aboriginal groups or other parties that seek judicial review of the recommendation of the NEB and subsequent decision by the Federal Governor in Council to conditionally approve the TMEP. The petitions allege, among other things, that additional consultation, engagement or accommodation is required and that various non-economic impacts of the TMEP were not adequately considered. The remedies sought include requests that the NEB recommendation be quashed, that additional consultations be undertaken, and that the order of the Governor in Council approving the TMEP be quashed. After provincial elections in British Columbia (BC) on May 9, 2017, the New Democratic Party and Green Party formed a majority government. The new BC government sought and was granted limited intervenor status in the Federal Court of Appeal proceedings to argue against the government’s approval of the TMEP. A hearing was conducted by the Federal Court of Appeal from October 2 through October 13, 2017. A decision is expected in the coming months, and is subject to potential further appeal to the Supreme Court of Canada. Although we believe that each of the foregoing appeals lacks merit, in the event an applicant is successful at the Supreme Court of Canada, among other potential impacts, the NEB recommendation or Governor in Council’s approval may be quashed, permits may be revoked, the TMEP may be subject to additional significant regulatory reviews, there may be significant changes to the TMEP plans, further obligations or restrictions may be implemented, or the TMEP may be stopped altogether, which could materially impact the overall feasibility or economic benefits of the TMEP, which in turn would have a material adverse effect on the TMEP and, consequently, our investment in KML. In addition to the judicial reviews of the NEB recommendation report and Governor in Council’s order, two judicial review proceedings have been commenced at the Supreme Court of BC (Squamish Nation; and the City of Vancouver). The petitions allege a duty and failure to consult or accommodate First Nations, and generally, among other claims, that the Province ought not to have approved the TMEP. Each Applicant seeks to quash the Environmental Assessment Certificate (EAC) that was issued by the BC Environmental Assessment Office. On September 29, 2017, the BC government filed evidence in support of the EAC approval in the judicial review proceeding involving the Squamish Nation. Hearings were conducted in October and November 2017, respectively, for the City of Vancouver and the Squamish Nation judicial review proceedings and the Court took the matters under consideration with decisions expected in the coming months. Although we believe that each of the foregoing appeals lacks merit, in the event that an applicant for judicial review is successful, among other potential impacts, the EAC may be quashed, provincial permits may be revoked, the TMEP may be subject to additional significant regulatory reviews, there may be significant changes to the TMEP plans, further obligations or restrictions may be imposed or the TMEP may be stopped altogether. In the event that an applicant is unsuccessful at the Supreme Court of BC, they may further seek to appeal the decision to the BC Court of Appeal. Any decision of the BC Court of Appeal may be appealed to the Supreme Court of Canada. A successful appeal at either of these levels could result in the same types of consequences described above. On October 26, 2017 and November 14, 2017, Trans Mountain filed motions with the NEB. The first motion sought to resolve delays experienced by Trans Mountain in obtaining preliminary plan approvals from the City of Burnaby. The second motion sought to establish an NEB process to backstop provincial and municipal processes in a fair, transparent and expedited fashion. On December 7, 2017, the NEB issued an order granting the relief requested by Trans Mountain in respect of its motion related to Burnaby. On January 19, 2018, the NEB granted, in part, Trans Mountain’s motion by establishing a generic process to hear any future motions as they relate to provincial and municipal permitting issues. Burnaby or other interested parties may seek leave to appeal to the Federal Court of Appeal and, if unsuccessful at the Federal Court of Appeal, may further seek to appeal the decision to the Supreme Court of Canada. A successful appeal at either of these levels could result in either one or both of the NEB orders being quashed. Other Commercial Matters Union Pacific Railroad Company Easements & Related Litigation SFPP and Union Pacific Railroad Company (UPRR) have engaged in litigation since 2004 to determine both the extent, if any, to which rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted, and the circumstances and conditions under which SFPP must pay to relocate its pipeline within the UPRR rights-of-way. In July 2017, UPRR and SFPP reached a confidential settlement of both the rental and relocation litigation. The amount paid by SFPP to settle the rental litigation was within the right-of-way liability previously recorded by SFPP, and the parties generally agreed to share and allocate the cost of future potential relocations. Although the cost sharing mechanism in the settlement is expected to reduce the cost of future relocations, SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations such that it is difficult to quantify the cost of future potential relocations. Such costs could have an adverse effect on our financial position, results of operations, cash flows, and dividends to our shareholders. A purported class action lawsuit was filed in 2015 in a U.S. District Court in California by private landowners who claim to be the lawful owners of subsurface real property allegedly used or occupied by UPRR or SFPP. Substantially similar follow-on lawsuits were filed in federal courts by landowners in Nevada, Arizona and New Mexico. These suits, which are 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, assert claims against UPRR, SFPP, KMGP, and Kinder Morgan Operating L.P. “D” 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 Plaintiffs’ request for interlocutory review of the decisions on class certification. The New Mexico and Nevada lawsuits have been stayed. An additional suit was filed in a U.S. District Court in Arizona by private landowners seeking recovery for claims substantially the same as those made in the purported class actions. SFPP views the litigation involving private landowners as primarily a dispute between UPRR and the plaintiff landowners; as such, we expect the lawsuits will be resolved 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 is 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 seeks 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. As set forth in the terminal use agreement, disputes are meant to be resolved by final and binding arbitration. A three-member arbitration panel conducted an arbitration hearing in January 2017. During fourth quarter 2017 the arbitration panel informed the parties that it expects to issue its decision on or before February 28, 2018. Eni USA has indicated that it will continue to pay the amounts claimed to be due pending resolution of the dispute. The successful assertion by Eni USA of its claim to terminate or amend its payment obligations under the agreement prior to the expiration of its initial term could have an adverse effect on the business, financial position, results of operations, or cash flows of GLNG and distributions to KMI, a 50% shareholder of GLNG. We view the demand for arbitration to be without merit, and we will continue to contest it vigorously. 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, KMR, and EPB that KMI and its subsidiaries did not already own. The suit alleges 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 and which the present suit now alleges were collectively worth as much as $700 million . The suit claims that the alleged failure to obtain sufficient merger consideration for the drop down lawsuits constitutes a breach of the EPB limited partnership agreement and the implied covenant of good faith and fair dealing. The suit also asserts 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. Defendants’ motion to dismiss was granted, and the Court dismissed the suit in its entirety. Brinckerhoff filed a notice to appeal the dismissal. 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. Defendants have moved to dismiss the suit. We continue to believe that both the merger and the drop down transactions were appropriate and in the best interests of EPB, and we intend to continue to defend these lawsuits vigorously. 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 have been settled or dismissed. The remaining cases, which are pending in a U.S. District Court in Nevada, were dismissed, but the dismissal was reversed by the Ninth Circuit Court of Appeals. The U.S. Supreme Court affirmed the Ninth Circuit Court of Appeals in a decision dated April 21, 2015, and the cases were then remanded to the District Court for further consideration and trial, if necessary, of numerous remaining issues. On May 24, 2016, the District Court granted a motion for summary judgment dismissing a lawsuit brought by an industrial consumer in Kansas in which approximately $500 million in damages has been alleged. That ruling has been appealed to the Ninth Circuit Court of Appeals. Settlements have been reached in class actions originally filed in Kansas and Missouri, which settlements received final court approval and have been paid. In the remaining case, a Wisconsin class action in which approximately $300 million in damages has been alleged against all defendants, the District Court denied plaintiff’s motion for class certification. The Ninth Circuit Court of Appeals granted plaintiff’s request for an interlocutory appeal of this ruling. There remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, which may be allocated to us in the remaining lawsuits and therefore, our legal exposure, if any, and costs are not currently determinable. 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, 2017 and 2016 , our total reserve for legal matters was $350 million and $407 million , respectively. The reserve primarily relates to various claims from regulatory proceedings arising in our products and natural gas pipeline segments. 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 cleanup. 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 sued 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. 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 now presented against KMEP and SFPP are 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. We filed an answer in response to the Second Amended Complaint and fact discovery is proceeding. 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 position of the U.S. as owner of the Navajo Reservation, the U.S.’s exploration 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 70 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 comments from the EPA remain 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 one member of the PRP group requiring such member to spend $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. In addition, the EPA has notified PRPs, including EPEC Polymers and EPEC Oil Trust that it intends to propose an allocation for the implementation of the remedy for the lower eight miles of the Passaic River Study area. The allocation process has not been finalized and we anticipate the EPA will propose an allocation during 2018. 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 RI/FS that the CPG is currently preparing for portions of the Site. The draft RI/FS was submitted by the CPG in 2015 and proposes a different remedy than the FFS announced by the EPA. Therefore, the scope of potential EPA claims for the lower eight miles of the Passaic River is not reasonably estimable at this time. Southeast Louisiana Flood Protection Litigation On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (SLFPA) filed a petition for damages and injunctive relief in a state district court for Orleans Parish, Louisiana against TGP, SNG and approximately 100 other energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The SLFPA asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13, 2013,

Recent Accounting Pronoucements

Recent Accounting Pronoucements (Notes)	12 Months Ended
	Dec. 31, 2017
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 606 On May 28, 2014, the FASB issued ASU No. 2014-09, “ Revenue from Contracts with Customers ” followed by a series of related accounting standard updates (collectively referred to as “Topic 606”). Topic 606 is designed to create greater revenue recognition and disclosure comparability in financial statements. The provisions of Topic 606 include a five-step process by which an entity will determine revenue recognition, depicting the transfer of goods or services to customers in amounts reflecting the payment to which an entity expects to be entitled in exchange for those goods or services. Topic 606 requires certain disclosures about contracts with customers and provides more comprehensive guidance for transactions such as service revenue, contract modifications, and multiple-element arrangements. Topic 606 will require that our revenue recognition policy disclosure include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. Topic 606 will require us to reclassify certain gathering and processing service fees currently reflected as revenues within our Natural Gas segment as reductions to Cost of sales in the Consolidated Statements of Income prospectively beginning January 1, 2018. Topic 606 will also require disclosure of significant changes in contract asset and contract liability balances period to period and the amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period, as applicable. We utilized the modified retrospective method to adopt the provisions of this standard effective January 1, 2018, which required us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to our retained deficit balance. In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 will not be revised. The cumulative effect of the adoption of this standard as of January 1, 2018 was not material. ASU No. 2015-11 On July 22, 2015, the FASB issued ASU No. 2015-11, “ Inventory (Topic 330): Simplifying the Measurement of Inventory .” This ASU requires entities to subsequently measure inventory at the lower of cost and net realizable value, and defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. ASU No. 2015-11 was effective January 1, 2017. We adopted ASU No. 2015-11 with no material impact to our financial statements. ASU No. 2016-02 On February 25, 2016, the FASB issued ASU No. 2016-02, “ Leases (Topic 842) .” This ASU requires that lessees recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. ASU 2016-02 will be effective for us as of January 1, 2019. We are currently reviewing the effect of ASU No. 2016-02. ASU No. 2016-09 On March 30, 2016, the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718).” This ASU was issued as part of the FASB’s simplification initiative and affects all entities that issue share-based payment awards to their employees. This ASU covers accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU No. 2016-09 was effective January 1, 2017. We adopted ASU No. 2016-09 with no material impact to our financial statements. See Note 5 “Income Taxes.” 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. We are currently reviewing the effect of ASU No. 2016-13. ASU No. 2016-18 On November 17, 2016, the FASB issued 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 statement of cash flows to explain 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 to be included with cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statement of cash flows. We adopted ASU No. 2016-18 effective January 1, 2018 with no material impact to our financial statements. ASU No. 2017-04 On January 26, 2017, the FASB issued ASU No. 2017-04, “ Simplifying the Test for Goodwill Impairment (Topic 350) ” to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A 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. We are currently reviewing the effect of this ASU to our financial statements. ASU No. 2017-05 On February 22, 2017, the FASB issued ASU No. 2017-05, “ Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): 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 effective January 1, 2018, 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 standard as of January 1, 2018 was less than $100 million . We will also reclassify EIG’s cumulative contribution to ELC of $485 million from “Other long-term liabilities and deferred credits” to a mezzanine equity classification described as “Redeemable noncontrolling interest” on our future consolidated balance sheets. ASU No. 2017-07 On March 10, 2017, the FASB issued 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 addresses how to present the service cost component and the other components of net benefit cost in the income statement. We adopted ASU No. 2017-07 effective January 1, 2018 with no material impact 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 amends and simplifies existing guidance in order to allow companies to more accurately present the economic effects of risk management activities in the financial statements. ASU No. 2017-12 will be effective for us as of January 1, 2019, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements. ASU No. 2018-01 On January 25, 2018, the FASB issued ASU No. 2018-01, “ Land Easement Practical Expedient for Transition to Topic 842 .” This ASU provides an optional transition practical expedient that, if elected, would not require companies to reconsider its accounting for existing or expired land easements before the adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. ASU No. 2018-01 will be effective for us as of January 1, 2019, 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, 2017
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. On September 1, 2016, we sold a 50% equity interest in SNG (see further details discussed in Note 3, “Acquisitions and Divestitures”). Subsequent to the transaction, we deconsolidated SNG and now account for our equity interest in SNG as an equity investment. Our wholly owned subsidiary which holds our interest in SNG is reflected within the Subsidiary Guarantors column of these condensed consolidating financial statements. On December 31, 2017, KMP’s interests in Kinder Morgan Bulk Terminals LLC were transferred to KMI. The following condensed consolidating financial information reflects this transaction for all periods presented. Excluding fair value adjustments, as of December 31, 2017, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $13,750 million , $18,885 million , and $3,310 million of Guaranteed Notes outstanding, respectively. Included in the Subsidiary Guarantors debt balance as presented in the accompanying December 31, 2017 condensed consolidating balance sheet are approximately $162 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 Accoun28

Summary of Significant Accounting Policies Accounting Policy (Policies)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Use of Estimates, Policy [Policy Text Block]	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.
Basis of Accounting, Policy [Policy Text Block]	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, 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.
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]	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 $62 million and $103 million as of December 31, 2017 and 2016 , respectively.
Receivables, Policy [Policy Text Block]	Accounts Receivable, net The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of December 31, 2017 and 2016 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 $35 million and $39 million as of December 31, 2017 and 2016 , respectively.
Inventory, Policy [Policy Text Block]	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.
Gas Balancing Arrangements, Policy [Policy Text Block]	Gas Imbalances We value gas imbalances due to or due from interconnecting pipelines at market prices. As of December 31, 2017 and 2016 , our gas imbalance receivables—including both trade and related party receivables—totaled $42 million and $108 million , respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2017 and 2016 , our gas imbalance payables—including both trade and related party payables—totaled $47 million and $45 million , respectively, and we included these amounts within “Other current liabilities” on our accompanying consolidated balance sheets.
Property, Plant and Equipment, Policy [Policy Text Block]	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 1.09% 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, 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 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 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 Obligation [Policy Text Block]	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.
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]	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. 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 Investments [Policy Text Block]	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 $732 million and $767 million as of December 31, 2017 and 2016 , 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, 2017, this excess investment cost is being amortized over a weighted average life of approximately fourteen years. The second differential, representing equity method goodwill, totaled $956 million for both periods as of December 31, 2017 and 2016 . 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 and Intangible Assets, Goodwill, Policy [Policy Text Block]	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, we have 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. 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 “Goodwill” for further information.
Goodwill and Intangible Assets, Intangible Assets, Policy [Policy Text Block]	Other Intangibles Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, lease value, and technology-based assets. As of both periods of December 31, 2017 and 2016 , the gross carrying amounts of these intangible assets was $4,305 million and the accumulated amortization was $1,206 million and $987 million , respectively, resulting in net carrying amounts of $3,099 million and $3,318 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, steel 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, 2017 , 2016 and 2015 , the amortization expense on our intangibles totaled $220 million , $223 million and $221 million , respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2018 – 2022) is approximately $214 million , $212 million , $209 million , $209 million , and $206 million , respectively. As of December 31, 2017 , the weighted average amortization period for our intangible assets was approximately sixteen years .
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition We recognize revenue as services are rendered or goods are delivered and, if applicable, risk of loss has passed. We recognize natural gas, crude and NGL sales revenue when the commodity is sold to a purchaser at a fixed or determinable price, delivery has occurred and risk of loss has transferred, and collectability of the revenue is reasonably assured. Our sales and purchases of natural gas, crude and NGL are 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 act as an agent and do not have price and related risk of ownership, in which case we recognize revenue on a net basis. In addition to storing and transporting a significant portion of the natural gas volumes we purchase and resell, we provide various types of natural gas storage and transportation services for third-party customers. Under these contracts, the natural gas remains the property of these customers at all times. In many cases, generally described as firm service, the customer pays a two-part rate that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fixed-fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases, generally described as interruptible service, there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. We provide crude oil and refined petroleum products transportation and storage services to customers. Revenues are recorded when products are delivered and services have been provided, and adjusted according to terms prescribed by the toll settlements with shippers and approved by regulatory authorities. We recognize bulk terminal transfer service revenues based on volumes loaded and unloaded. We recognize liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal throughput revenue based on volumes received and volumes delivered. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when risk of loss has passed. We recognize energy-related product sales revenues based on delivered quantities of product. Revenues from the sale of crude oil, NGL, CO 2 and natural gas production within the CO 2 business segment are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices. Since there is a ready market for oil and gas production, we sell the majority of our products soon after production at various locations, at which time title and risk of loss pass to the buyer.
Cost of Sales, Policy [Policy Text Block]	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.
Maintenance Cost, Policy [Policy Text Block]	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 $342 million , $349 million and $366 million for the years ended December 31, 2017 , 2016 and 2015 , respectively.
Regulatory Environmental Costs, Policy [Policy Text Block]	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.
Pension and Other Postretirement Plans, Policy [Policy Text Block]	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.
Consolidation, Subsidiaries or Other Investments, Consolidated Entities, Policy [Policy Text Block]	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 (or loss) of our consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net (Income) Loss Attributable to Noncontrolling Interests.” In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”
Income Tax, Policy [Policy Text Block]	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.
Foreign Currency Transactions and Translations Policy [Policy Text Block]	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.”
Derivatives, Policy [Policy Text Block]	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. 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. 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.
Public Utilities, Policy [Policy Text Block]	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. The following table summarizes our regulatory asset and liability balances as of December 31, 2017 and 2016 (in millions): December 31, 2017 2016 Current regulatory assets $ 60 $ 49 Non-current regulatory assets 288 330 Total regulatory assets(a) $ 348 $ 379 Current regulatory liabilities $ 107 $ 101 Non-current regulatory liabilities 236 108 Total regulatory liabilities(b) $ 343 $ 209 _______ (a) Regulatory assets as of December 31, 2017 include (i) $193 million of unamortized losses on disposal of assets; (ii) $55 million income tax gross up on equity AFUDC; and (iii) $100 million of other assets including amounts related to fuel tracker arrangements. Approximately $124 million of the regulatory assets, with a weighted average remaining recovery period of 17 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, and therefore, it does not earn a return. (b) Regulatory liabilities as of December 31, 2017 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 $20 million of the $236 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 28 years , while the remaining $216 million is not subject to a defined period.
Transfer of net assets between entities under common control [Policy Text Block]	Transfer of Net Assets Between Entities Under Common Control We account for the transfer of net assets between entities under common control by carrying forward the net assets recognized in the balance sheets of each combining entity to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination. Transfers of net assets between entities under common control do not affect the historical income statement or balance sheet of the combined entity.
Earnings Per Share, Policy [Policy Text Block]	Earnings per Share We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares of common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be stock or stock units issued to management employees 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, 2017
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 Accoun30

Summary of Significant Accounting Policies Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Regulatory Assets and Liabilities [Text Block]	The following table summarizes our regulatory asset and liability balances as of December 31, 2017 and 2016 (in millions): December 31, 2017 2016 Current regulatory assets $ 60 $ 49 Non-current regulatory assets 288 330 Total regulatory assets(a) $ 348 $ 379 Current regulatory liabilities $ 107 $ 101 Non-current regulatory liabilities 236 108 Total regulatory liabilities(b) $ 343 $ 209 _______ (a) Regulatory assets as of December 31, 2017 include (i) $193 million of unamortized losses on disposal of assets; (ii) $55 million income tax gross up on equity AFUDC; and (iii) $100 million of other assets including amounts related to fuel tracker arrangements. Approximately $124 million of the regulatory assets, with a weighted average remaining recovery period of 17 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, and therefore, it does not earn a return. (b) Regulatory liabilities as of December 31, 2017 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 $20 million of the $236 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 28 years , while the remaining $216 million is not subject to a defined period.
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	The following tables set forth the allocation of net income available to shareholders of Class P shares and participating securities and the reconciliation of Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding (in millions): Year Ended December 31, 2017 2016 2015 Net Income Available to Common Stockholders $ 27 $ 552 $ 227 Participating securities: Less: Net Income Allocated to Restricted stock awards(a) (5 ) (4 ) (13 ) Net Income Allocated to Class P Stockholders $ 22 $ 548 $ 214 Basic Weighted Average Common Shares Outstanding 2,230 2,230 2,187 Basic Earnings Per Common Share $ 0.01 $ 0.25 $ 0.10 Year Ended December 31, 2017 2016 2015 Basic Weighted Average Common Shares Outstanding 2,230 2,230 2,187 Effect of dilutive securities: Warrants — — 6 Diluted Weighted Average Common Shares Outstanding 2,230 2,230 2,193 _______ (a) As of December 31, 2017 , there were approximately 11 million such restricted stock awards.
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	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, 2017 2016 2015 Unvested restricted stock awards 10 8 7 Warrants to purchase our Class P shares(a) 116 293 291 Convertible trust preferred securities 3 8 8 Mandatory convertible preferred stock(b) 58 58 10 _______ (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) Until our mandatory convertible preferred shares are converted to common shares, on or before the expected mandatory conversion date of October 26, 2018, the holder of each preferred share participates in our earnings by receiving preferred stock dividends.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	As of December 31, 2017 , the purchase allocation for our significant acquisitions completed during the reporting periods are detailed below (in millions): Assignment of Purchase Price Ref. Date Acquisition Purchase price Current assets Property plant & equipment Deferred charges & other Goodwill Debt Other liabilities (1) 2/16 BP Products North America Inc. Terminal Assets $ 349 $ 2 $ 396 $ — $ — $ — $ (49 ) (2) 2/15 Vopak Terminal Assets 158 2 155 — 6 — (5 ) (3) 2/15 Hiland 1,709 79 1,492 1,498 310 (1,413 ) (257 )
Schedule of Variable Interest Entities [Table Text Block]	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, 2017 Assets Total current assets $ 270 Property, plant and equipment, net 2,956 Total goodwill, deferred charges and other assets 322 Total assets $ 3,548 Liabilities Current portion of debt $ — Total other current liabilities 236 Long-term debt, excluding current maturities — Total other long-term liabilities and deferred credits 414 Total liabilities $ 650

Impairments (Tables)

Impairments (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Natural Gas Pipelines Impairment of goodwill $ — $ — $ 1,150 Impairments of long-lived assets(a) 30 106 79 Losses on divestitures of long-lived assets(b) — 94 43 Impairments of equity investments(c) 150 606 26 Impairments at equity investees(d) 10 7 — CO 2 Impairments of long-lived assets(e) (1 ) 20 606 Gains on divestitures of long-lived assets — (1 ) — Impairments at equity investee(d) (4 ) 9 26 Terminals Impairments of long-lived assets(f) 3 19 188 (Gains) losses on divestitures of long-lived assets(g) (18 ) 80 3 Losses on impairments and divestitures of equity investments, net — 16 4 Products Pipelines Impairments of long-lived assets(h) — 66 — Losses (gains) on divestitures of long-lived assets — 10 1 Gain on divestiture of equity investment — (12 ) — Other losses (gains) on divestitures of long-lived assets 2 (7 ) (1 ) Pre-tax losses on impairments and divestitures, net $ 172 $ 1,013 $ 2,125 _______ (a) 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 (NED) Market project. 2015 amount represents $47 million and $32 million of project write-offs in our non-regulated midstream and regulated natural gas pipelines assets, respectively. (b) 2016 amount primarily relates to our sale of a 50% interest in SNG. (c) 2017 amount represents the impairment of our investment in FEP. 2016 amount includes a $350 million impairment of our investment in MEP and a $250 million impairment of our investment in Ruby. 2015 amount is primarily related to an impairment of an investment in a gathering and processing asset in Oklahoma. (d) 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) 2015 amount includes (i) $399 million related to oil and gas properties and (ii) $207 million related to the certain CO 2 source and transportation project write-offs. (f) 2015 amount is primarily related to certain terminals with significant coal operations, including a $175 million impairment of a terminal facility reflecting the impact of an agreement to adjust certain payment terms under a contract with a coal customer in February 2016. (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) 2016 amount represents project write-offs associated with the canceled Palmetto project.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 U.S. $ 1,976 $ 1,466 $ 611 Foreign 185 172 161 Total Income Before Income Taxes $ 2,161 $ 1,638 $ 772
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, 2017 2016 2015 Current tax expense (benefit) Federal $ (137 ) $ (148 ) $ (125 ) State (16 ) (28 ) (7 ) Foreign 18 6 4 Total (135 ) (170 ) (128 ) Deferred tax expense (benefit) Federal 2,022 998 653 State 4 51 (4 ) Foreign 47 38 43 Total 2,073 1,087 692 Total tax provision $ 1,938 $ 917 $ 564
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, 2017 2016 2015 Federal income tax $ 756 35.0 % $ 573 35.0 % $ 271 35.0 % Increase (decrease) as a result of: State deferred tax rate change 10 0.5 % 11 0.7 % (24 ) (3.1 )% Taxes on foreign earnings, net of federal benefit 42 1.9 % 28 1.7 % 26 3.5 % Net effects of noncontrolling interests (14 ) (0.7 )% (4 ) (0.3 )% 15 2.0 % State income tax, net of federal benefit 38 1.8 % 26 1.6 % 12 1.5 % Dividend received deduction (56 ) (2.6 )% (48 ) (2.9 )% (51 ) (6.6 )% Adjustments to uncertain tax positions (12 ) (0.6 )% (23 ) (1.4 )% (14 ) (1.9 )% Valuation allowance on investment and tax credits 13 0.6 % 34 2.1 % — — % Impact of the 2017 Tax Reform 1,240 57.4 % — — % — — % Nondeductible goodwill — — % 301 18.5 % 323 41.7 % General business credit (95 ) (4.4 )% — — % — — % Other 16 0.8 % 19 1.1 % 6 0.8 % Total $ 1,938 89.7 % $ 917 56.1 % $ 564 72.9 %
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Deferred tax assets and liabilities result from the following (in millions): December 31, 2017 2016 Deferred tax assets Employee benefits $ 251 $ 401 Accrued expenses 73 118 Net operating loss, capital loss and tax credit carryforwards 1,113 1,307 Derivative instruments and interest rate and currency swaps 12 22 Debt fair value adjustment 37 74 Investments 968 2,804 Other 6 14 Valuation allowances (171 ) (184 ) Total deferred tax assets 2,289 4,556 Deferred tax liabilities Property, plant and equipment 225 177 Other 20 27 Total deferred tax liabilities 245 204 Net deferred tax assets $ 2,044 $ 4,352
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, 2017 2016 2015 Balance at beginning of period $ 122 $ 148 $ 189 Additions based on current year tax positions 3 3 4 Additions based on prior year tax positions — 7 — Reductions based on prior year tax positions — (1 ) (6 ) Reductions based on settlements with taxing authority (22 ) (26 ) (25 ) Reductions due to lapse in statute of limitations (2 ) (9 ) (14 ) Impact of the 2017 Tax Reform (4 ) — — Balance at end of period $ 97 $ 122 $ 148

Property, Plant and Equipment34

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	As of December 31, 2017 and 2016 , our property, plant and equipment, net consisted of the following (in millions): December 31, 2017 2016 Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 20,157 $ 19,341 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 24,152 23,298 Other(a) 5,570 4,780 Accumulated depreciation, depletion and amortization (14,175 ) (12,306 ) 35,704 35,113 Land and land rights-of-way 1,456 1,431 Construction work in process 2,995 2,161 Property, plant and equipment, net $ 40,155 $ 38,705 _______ (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, 2017	Dec. 31, 2016
Investments [Abstract]
Schedule of earnings from equity investments [Table Text Block]	Our earnings (losses) from equity investments were as follows (in millions): Year Ended December 31, 2017 2016 2015 Citrus Corporation $ 108 $ 102 $ 96 SNG 77 58 — FEP 53 51 55 Gulf LNG Holdings Group, LLC 47 48 49 Plantation Pipe Line Company 46 37 29 Cortez Pipeline Company(a) 44 24 (3 ) Ruby 44 15 18 MEP 38 40 45 EagleHawk 24 10 24 Watco Companies, LLC 19 25 16 Red Cedar Gathering Company(b) 14 24 26 Fort Union Gas Gathering L.L.C.(c) 10 1 16 NGPL Holdings LLC 10 12 — Liberty Pipeline Group LLC 9 11 9 Bear Creek Storage 8 2 — Sierrita Gas Pipeline LLC 7 7 9 Double Eagle Pipeline LLC 7 5 3 Parkway Pipeline LLC — 14 5 All others 13 11 17 Total earnings from equity investments $ 578 $ 497 $ 414 Amortization of excess costs (61 ) (59 ) (51 ) _______ (a) 2017, 2016 and 2015 amounts include $(4) million , $9 million and $26 million , respectively, representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company. (b) 2017 amount includes non-cash impairment charges of $10 million (pre-tax) related to our investment. (c) 2016 amount includes non-cash impairment charges of $7 million (pre-tax) related to our investment.
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, 2017 and 2016 , our investments consisted of the following (in millions): December 31, 2017 2016 Citrus Corporation $ 1,698 $ 1,709 SNG 1,495 1,505 Ruby 774 798 NGPL Holdings LLC 687 475 Gulf LNG Holdings Group, LLC 461 485 Plantation Pipe Line Company 331 333 EagleHawk 314 329 Utopia Holding LLC 276 55 MEP 253 328 Red Cedar Gathering Company 187 191 Watco Companies, LLC 182 180 Double Eagle Pipeline LLC 149 151 FEP 112 101 Liberty Pipeline Group LLC 71 75 Bear Creek Storage 63 61 Sierrita Gas Pipeline LLC 55 57 Fort Union Gas Gathering L.L.C. 12 25 All others 178 169 Total investments $ 7,298 $ 7,027
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):

Goodwill Goodwill (Tables)

Goodwill Goodwill (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 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 $ 17,527 $ 5,812 $ 1,528 $ 2,125 $ 221 $ 1,584 $ 556 $ 29,353 Accumulated impairment losses (1,643 ) (1,597 ) — (1,197 ) (70 ) (679 ) (377 ) (5,563 ) December 31, 2015 15,884 4,215 1,528 928 151 905 179 23,790 Currency translation — — — — — — 6 6 Divestitures(a) (1,635 ) — — — — (9 ) — (1,644 ) December 31, 2016 14,249 4,215 1,528 928 151 896 185 22,152 Currency translation — — — — — — 13 13 Divestitures(b) — — — — — (3 ) — (3 ) December 31, 2017 $ 14,249 $ 4,215 $ 1,528 $ 928 $ 151 $ 893 $ 198 $ 22,162 _______ (a) 2016 includes $1,635 million related to the sale of a 50% interest in our SNG natural gas pipeline system by Natural Gas Pipelines Regulated to Southern Company and $9 million related to certain terminal divestitures. (b) 2017 includes $3 million related to certain terminal divestitures.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 Unsecured term loan facility, variable rate, due January 26, 2019(a) $ — $ 1,000 Senior note, floating rate, due January 15, 2023(a) 250 — Senior notes, 1.50% through 8.05%, due 2017 through 2098(a)(b)(c) 13,136 13,236 Credit facility due November 26, 2019 125 — Commercial paper borrowings 240 — KML Credit Facility(d) — — KMP senior notes, 2.65% through 9.00%, due 2017 through 2044(c)(e) 18,885 19,485 TGP senior notes, 7.00% through 8.375%, due 2017 through 2037(c)(f) 1,240 1,540 EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(c)(g) 760 1,115 CIG senior notes, 4.15% and 6.85%, due 2026 and 2037(c) 475 475 Kinder Morgan Finance Company, LLC, senior notes, 6.00% and 6.40%, due 2018 and 2036(c) 786 786 Hiland Partners Holdings LLC, senior notes, 5.50%, due 2022(a)(h) — 225 EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035 421 433 Trust I preferred securities, 4.75%, due March 31, 2028(i) 221 221 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(j) 100 100 Other miscellaneous debt(k) 277 285 Total debt – KMI and Subsidiaries 36,916 38,901 Less: Current portion of debt(l) 2,828 2,696 Total long-term debt – KMI and Subsidiaries(m) $ 34,088 $ 36,205 _______ (a) On August 10, 2017, we issued $1 billion of unsecured senior notes with a fixed rate of 3.15% and $250 million of unsecured senior notes with a floating rate, both due January 2023. The net proceeds from the notes were primarily used to repay the principal amount of Hiland’s 5.50% senior notes due 2022, plus accrued interest, and to repay the $1 billion term loan facility due 2019. Interest on the 3.15% senior notes due 2023 is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2018, and the notes will mature on January 15, 2023. Interest on the floating rate senior notes due 2023 is payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, beginning on October 15, 2017, and such notes will mature on January 15, 2023. We may redeem all or a part of the 3.15% fixed rate notes at any time at the redemption prices. The floating rate notes are not redeemable prior to maturity. See (b) and (h) below. (b) Amounts include senior notes that are denominated in Euros and have been converted to U.S. dollars and are respectively reported above at the December 31, 2017 exchange rate of 1.2005 U.S. dollars per Euro and the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro. For the year ended December 31, 2017 , our debt balance increased by $186 million as a result of the change in the exchange rate of U.S dollars per Euro. The 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 ”). In June 2017, we repaid $786 million of maturing 7.00% senior notes and in December 2017, we repaid $500 million of maturing 2.00% senior notes. The December 31, 2017 balance includes the $1 billion of unsecured term notes with a fixed rate of 3.15% due January 15, 2023 discussed in (a) above. (c) Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. (d) The KML Credit Facility is denominated in C$ and has been converted to U.S. dollars and reported above at the December 31, 2017 exchange rate of 0.7971 U.S. dollars per C$. See “—Credit Facilities and Restrictive Covenants ” below. (e) In February 2017, we repaid $600 million of maturing 6.00% senior notes. (f) In April 2017, we repaid $300 million of maturing 7.50% senior notes. (g) In April 2017, we repaid $355 million of maturing 5.95% senior notes. (h) In August 2017, we repaid $225 million of the outstanding principal amount of 5.50% senior notes with a maturity date of May 15, 2022 using net proceeds from the sale of the January 2023 notes (see (a) above). We recognized a $3.8 million loss from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2017 consisting of a $9.3 million premium on the debt repaid and a $5.5 million gain from the write-off of unamortized purchase accounting associated with the early extinguished debt. (i) Capital Trust I (Trust I), is a 100% -owned business trust that as of December 31, 2017 , 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 and 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; (ii) $25.18 in cash without interest; and (iii) 1.100 warrants to purchase a share of our Class P common stock. Our warrants expired on May 25, 2017, along with the portion of the mixed consideration that provided for the conversion into 1.100 warrants to purchase a share of our Class P common stock. We have the right to redeem these Trust I Preferred Securities at any time. Because of the substantive conversion rights of the securities into the mixed consideration, we bifurcated the fair value of the Trust I Preferred Securities into debt and equity components and as of December 31, 2017 , the outstanding balance of $221 million (of which $111 million was classified as current) was bifurcated between debt ( $200 million ) and equity ( $21 million ). (j) As of December 31, 2017 and 2016, 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. (k) In conjunction with the construction of the Totem Gas Storage facility (Totem) and the High Plains pipeline (High Plains), CIG’s joint venture partner in WYCO funded 50% of the construction costs. Upon project completion, the advances were converted into a financing obligation to WYCO. As of December 31, 2017 , the principal amounts of the Totem and High Plains financing obligations were $69 million and $88 million , respectively, which will be paid in monthly installments through 2039 based on the initial lease term. The interest rate on these obligations is 15.5% , payable on a monthly basis. (l) 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. (m) Excludes our “Debt fair value adjustments” which, as of December 31, 2017 and 2016 , increased our combined debt balances by $927 million and $1,149 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. 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 19 “Guarantee of Securities of Subsidiaries.” Credit Facilities and Restrictive Covenants KMI On January 26, 2016, we increased the capacity of our revolving credit agreement, initially entered into during 2014, from $4.0 billion to $5.0 billion . The other terms of our revolving credit agreement remain the same. We also maintain a $4.0 billion commercial paper program through the private placement of short-term notes. The notes mature up to 270 days from the date of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less a discount representing an interest factor or if interest bearing, at par. Borrowings under our revolving credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility. Our credit facility borrowings bear interest at either (i) LIBOR plus an applicable margin ranging from 1.125% 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; and (3) LIBOR Rate for a one month eurodollar loan, plus 1% , plus, in each case, an applicable margin ranging from 0.125% to 1.00% per annum based on our credit rating. Our credit facility included the following restrictive covenants as of December 31, 2017 : • total debt divided by earnings before interest, income taxes, depreciation and amortization may not exceed: • 6.50 : 1.00 , for the period ended on or prior to December 31, 2017; or • 6.25 : 1.00 , for the period ended after December 31, 2017 and on or prior to December 31, 2018; or • 6.00 : 1.00 , for the period ended after December 31, 2018; • certain limitations on indebtedness, including payments and amendments; • certain limitations on entering into mergers, consolidations, sales of assets and investments; • limitations on granting liens; and • prohibitions on making any dividend to shareholders if an event of default exists or would exist upon making such dividend. As of December 31, 2017 , we had $125 million outstanding under our credit facility, $240 million outstanding under our commercial paper program and $107 million in letters of credit. Our availability under this facility as of December 31, 2017 was $4,528 million . As of December 31, 2017 , we were in compliance with all required covenants. KML On June 16, 2017, KML’s indirect subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, entered into a definitive credit agreement establishing (i) a C $4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the TMEP, (ii) a C $1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional TMEP costs (and, subject to the need to fund such additional costs, meeting the Canadian NEB-mandated liquidity requirements) and (iii) a C $500 million revolving working capital facility to be used for working capital and other general corporate purposes (collectively, the “KML Credit Facility”). On January 23, 2018, KML entered into an agreement amending certain terms of its Credit Facility to, among other things, provide additional funding certainty with respect to each tranche of its Credit Facility. The KML Credit Facility has a five -year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. Any undrawn commitments under the KML Credit Facility will incur a standby fee of 0.30% to 0.625% , with the range dependent on the credit ratings of Kinder Morgan Cochin ULC or KML. The KML Credit Facility is guaranteed by KML and all of the non-borrower subsidiaries of KML and are secured by a first lien security interest on all of the assets of KML and the equity and assets of the other guarantors. Draw downs of funds on the KML Credit Facility bear interest dependent on the type of loans requested and are as follows: • bankers’ acceptances or LIBOR loans are at an annual rate of approximately Canadian Dealer Offered Rate (CDOR); • or the LIBOR, as the case may be, plus a fixed spread ranging from 1.50% to 2.50% ; • loans in Canadian dollars or U.S. dollars are at an annual rate of approximately the Canadian prime rate or the U.S. dollar base rate, as the case may be, plus a fixed spread ranging from 0.50% to 1.50% , in each case, with the range dependent on the credit ratings of KML; and • letters of credit (under the working capital facility only) will have issuance fees based on an annual rate of approximately CDOR plus a fixed spread ranging from 1.50% to 2.50% , with the range dependent on the credit ratings of the Company. The foregoing rates and fees will increase by 0.25% upon the fourth anniversary of the KML Credit Facility. The KML Credit Facility includes various financial and other covenants including: • a maximum ratio of consolidated total funded debt to consolidated capitalization of 70% ; • restrictions on ability to incur debt; • restrictions on ability to make dispositions, restricted payments and investments; • restrictions on granting liens and on sale-leaseback transactions; • restrictions on ability to engage in transactions with affiliates; and • restrictions on ability to amend organizational documents and engage in corporate reorganization transactions. As of December 31, 2017 , KML had C $447 million available under its five year C $500 million working capital facility (after reducing the capacity for the C $53.0 million (U.S. $42 million ) in letters of credit) and no amounts outstanding under its C $4.0 billion construction facility or its C $1.0 billion revolving contingent credit facility. As of December 31, 2017 , KML was in compliance with all required covenants. Current Portion of Debt The primary components of our current portion of debt include the following significant series of long-term notes (in millions): As of December 31, 2017 $750 Kinder Morgan Finance Company, LLC, 6.00% senior notes due January 2018 $82 7.00% senior notes due February 2018 $975 KMP 5.95% senior notes due February 2018 $477 7.25% senior notes due June 2018 As of December 31, 2016 $600 KMP 6.00% senior notes due February 2017 $300 TGP 7.50% senior notes due April 2017 $355 EPNG 5.95% senior notes due April 2017 $786 7.00% senior notes due June 2017 $500 2.00% senior notes due December 2017 Subsequent Event—Debt Repayments In January 2018, we repaid $750 million of maturing 6.00% Kinder Morgan Finance Company, LLC senior notes and in February 2018, we repaid $82 million of maturing 7.00% senior notes both listed above in current portion of debt as of December 31, 2017. Maturities of Debt The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2017 , are summarized as follows (in millions): Year Total 2018 $ 2,828 2019 2,820 2020 2,204 2021 2,422 2022 2,558 Thereafter 24,084 Total $ 36,916 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, 2017 , 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 2017 2016 Purchase accounting debt fair value adjustments $ 719 $ 806 Carrying value adjustment to hedged debt 115 220 Unamortized portion of proceeds received from the early termination of interest rate swap agreements 297 342 Unamortized debt discounts, net (74 ) (80 ) Unamortized debt issuance costs (130 ) (139 ) Total debt fair value adjustments $ 927 $ 1,149 Interest Rates, Interest Rate Swaps and Contingent Debt The weighted average interest rate on all of our borrowings was 5.02% during 2017 and 4.95% during 2016 . Information on our interest rate swaps is contained in Note 14 “Risk Management.” For information about our contingent debt agreements, see Note 13 “Commitments and Contingent Liabilities— Contingent Debt ”).
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, 2017 2016 Unsecured term loan facility, variable rate, due January 26, 2019(a) $ — $ 1,000 Senior note, floating rate, due January 15, 2023(a) 250 — Senior notes, 1.50% through 8.05%, due 2017 through 2098(a)(b)(c) 13,136 13,236 Credit facility due November 26, 2019 125 — Commercial paper borrowings 240 — KML Credit Facility(d) — — KMP senior notes, 2.65% through 9.00%, due 2017 through 2044(c)(e) 18,885 19,485 TGP senior notes, 7.00% through 8.375%, due 2017 through 2037(c)(f) 1,240 1,540 EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(c)(g) 760 1,115 CIG senior notes, 4.15% and 6.85%, due 2026 and 2037(c) 475 475 Kinder Morgan Finance Company, LLC, senior notes, 6.00% and 6.40%, due 2018 and 2036(c) 786 786 Hiland Partners Holdings LLC, senior notes, 5.50%, due 2022(a)(h) — 225 EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035 421 433 Trust I preferred securities, 4.75%, due March 31, 2028(i) 221 221 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(j) 100 100 Other miscellaneous debt(k) 277 285 Total debt – KMI and Subsidiaries 36,916 38,901 Less: Current portion of debt(l) 2,828 2,696 Total long-term debt – KMI and Subsidiaries(m) $ 34,088 $ 36,205 _______ (a) On August 10, 2017, we issued $1 billion of unsecured senior notes with a fixed rate of 3.15% and $250 million of unsecured senior notes with a floating rate, both due January 2023. The net proceeds from the notes were primarily used to repay the principal amount of Hiland’s 5.50% senior notes due 2022, plus accrued interest, and to repay the $1 billion term loan facility due 2019. Interest on the 3.15% senior notes due 2023 is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2018, and the notes will mature on January 15, 2023. Interest on the floating rate senior notes due 2023 is payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, beginning on October 15, 2017, and such notes will mature on January 15, 2023. We may redeem all or a part of the 3.15% fixed rate notes at any time at the redemption prices. The floating rate notes are not redeemable prior to maturity. See (b) and (h) below. (b) Amounts include senior notes that are denominated in Euros and have been converted to U.S. dollars and are respectively reported above at the December 31, 2017 exchange rate of 1.2005 U.S. dollars per Euro and the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro. For the year ended December 31, 2017 , our debt balance increased by $186 million as a result of the change in the exchange rate of U.S dollars per Euro. The 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 ”). In June 2017, we repaid $786 million of maturing 7.00% senior notes and in December 2017, we repaid $500 million of maturing 2.00% senior notes. The December 31, 2017 balance includes the $1 billion of unsecured term notes with a fixed rate of 3.15% due January 15, 2023 discussed in (a) above. (c) Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. (d) The KML Credit Facility is denominated in C$ and has been converted to U.S. dollars and reported above at the December 31, 2017 exchange rate of 0.7971 U.S. dollars per C$. See “—Credit Facilities and Restrictive Covenants ” below. (e) In February 2017, we repaid $600 million of maturing 6.00% senior notes. (f) In April 2017, we repaid $300 million of maturing 7.50% senior notes. (g) In April 2017, we repaid $355 million of maturing 5.95% senior notes. (h) In August 2017, we repaid $225 million of the outstanding principal amount of 5.50% senior notes with a maturity date of May 15, 2022 using net proceeds from the sale of the January 2023 notes (see (a) above). We recognized a $3.8 million loss from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2017 consisting of a $9.3 million premium on the debt repaid and a $5.5 million gain from the write-off of unamortized purchase accounting associated with the early extinguished debt. (i) Capital Trust I (Trust I), is a 100% -owned business trust that as of December 31, 2017 , 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 and 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; (ii) $25.18 in cash without interest; and (iii) 1.100 warrants to purchase a share of our Class P common stock. Our warrants expired on May 25, 2017, along with the portion of the mixed consideration that provided for the conversion into 1.100 warrants to purchase a share of our Class P common stock. We have the right to redeem these Trust I Preferred Securities at any time. Because of the substantive conversion rights of the securities into the mixed consideration, we bifurcated the fair value of the Trust I Preferred Securities into debt and equity components and as of December 31, 2017 , the outstanding balance of $221 million (of which $111 million was classified as current) was bifurcated between debt ( $200 million ) and equity ( $21 million ). (j) As of December 31, 2017 and 2016, 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. (k) In conjunction with the construction of the Totem Gas Storage facility (Totem) and the High Plains pipeline (High Plains), CIG’s joint venture partner in WYCO funded 50% of the construction costs. Upon project completion, the advances were converted into a financing obligation to WYCO. As of December 31, 2017 , the principal amounts of the Totem and High Plains financing obligations were $69 million and $88 million , respectively, which will be paid in monthly installments through 2039 based on the initial lease term. The interest rate on these obligations is 15.5% , payable on a monthly basis. (l) 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. (m) Excludes our “Debt fair value adjustments” which, as of December 31, 2017 and 2016 , increased our combined debt balances by $927 million and $1,149 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 primary components of our current portion of debt include the following significant series of long-term notes (in millions): As of December 31, 2017 $750 Kinder Morgan Finance Company, LLC, 6.00% senior notes due January 2018 $82 7.00% senior notes due February 2018 $975 KMP 5.95% senior notes due February 2018 $477 7.25% senior notes due June 2018 As of December 31, 2016 $600 KMP 6.00% senior notes due February 2017 $300 TGP 7.50% senior notes due April 2017 $355 EPNG 5.95% senior notes due April 2017 $786 7.00% senior notes due June 2017 $500 2.00% senior notes due December 2017
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, 2017 , are summarized as follows (in millions): Year Total 2018 $ 2,828 2019 2,820 2020 2,204 2021 2,422 2022 2,558 Thereafter 24,084 Total $ 36,916
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 2017 2016 Purchase accounting debt fair value adjustments $ 719 $ 806 Carrying value adjustment to hedged debt 115 220 Unamortized portion of proceeds received from the early termination of interest rate swap agreements 297 342 Unamortized debt discounts, net (74 ) (80 ) Unamortized debt issuance costs (130 ) (139 ) Total debt fair value adjustments $ 927 $ 1,149

Share-based Compensation and 38

Share-based Compensation and Employee Benefits Share-based Compensation and Employee Benefits (Tables)	12 Months Ended
	Dec. 31, 2017
Share-based Compensation [Abstract]
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]	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, 2017 December 31, 2016 December 31, 2015 Shares Weighted Average Shares Weighted Average Shares Weighted Average Grant Date Fair Value Outstanding at beginning of period 9,038,137 $ 32.72 7,645,105 $ 37.91 7,373,294 $ 37.63 Granted 3,221,691 19.52 2,816,599 21.36 1,488,467 38.20 Vested (1,501,939 ) 36.67 (1,226,652 ) 38.53 (817,797 ) 35.66 Forfeited (239,545 ) 28.34 (196,915 ) 35.74 (398,859 ) 38.51 Outstanding at end of period 10,518,344 $ 28.21 9,038,137 $ 32.72 7,645,105 $ 37.91
Share-based Compensation Arrangements by Share-based Payment Award, Restricted Stock Units, Vested and Expected to Vest [Table Text Block]	Following is a summary of the future vesting of our outstanding restricted stock awards: Year Vesting of Restricted Shares 2018 2,272,019 2019 4,268,118 2020 3,647,967 2021 199,850 2022 65,928 Thereafter 64,462 Total Outstanding 10,518,344
Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block]	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, 2017 and 2016 (in millions): Pension Benefits OPEB 2017 2016 2017 2016 Change in benefit obligation: Benefit obligation at beginning of period $ 2,884 $ 2,654 $ 473 $ 509 Service cost 40 36 1 1 Interest cost 88 89 13 16 Actuarial loss (gain) 155 127 (16 ) (42 ) Benefits paid (180 ) (180 ) (38 ) (41 ) Participant contributions 3 3 2 2 Medicare Part D subsidy receipts — — 1 1 Exchange rate changes 13 4 1 1 Settlements (21 ) — — — Other(a) — 151 (12 ) 26 Benefit obligation at end of period 2,982 2,884 425 473 Change in plan assets: Fair value of plan assets at beginning of period 2,160 2,050 332 325 Actual return on plan assets 292 157 29 29 Employer contributions 32 8 9 16 Participant contributions 3 3 2 2 Medicare Part D subsidy receipts — — 1 1 Benefits paid (180 ) (180 ) (38 ) (41 ) Exchange rate changes 10 3 — — Settlements (21 ) — — — Other(a) — 119 — — Fair value of plan assets at end of period 2,296 2,160 335 332 Funded status - net liability at December 31, $ (686 ) $ (724 ) $ (90 ) $ (141 ) _______ (a) 2017 amounts represent December 31, 2016 balances associated with our Plantation Pipeline OPEB plan that are no longer included in these disclosures. 2016 amounts primarily represent December 31, 2015 balances associated with our Canadian pension and OPEB plans for prospective inclusion in these disclosures, which associated net periodic benefit costs were reported separately in years prior to 2016.
Schedule of Net Funded Status [Table Text Block]	Components of Funded Status . The following table details the amounts recognized in our balance sheets at December 31, 2017 and 2016 related to our pension and OPEB plans (in millions): Pension Benefits OPEB 2017 2016 2017 2016 Non-current benefit asset(a) $ — $ — $ 198 $ 153 Current benefit liability — — (15 ) (16 ) Non-current benefit liability (686 ) (724 ) (273 ) (278 ) Funded status - net liability at December 31, $ (686 ) $ (724 ) $ (90 ) $ (141 ) _______ (a) 2017 and 2016 OPEB amounts include $33 million and $29 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 Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]	Components of Accumulated Other Comprehensive (Loss) Income . The following table details the amounts of pre-tax accumulated other comprehensive (loss) income at December 31, 2017 and 2016 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 2017 2016 2017 2016 Unrecognized net actuarial (loss) gain $ (635 ) $ (682 ) $ 88 $ 69 Unrecognized prior service (cost) credit (4 ) (5 ) 17 18 Accumulated other comprehensive (loss) income $ (639 ) $ (687 ) $ 105 $ 87
Fair value of Pension and OPEB assets by level of assets [Table Text Block]	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, 2017 and 2016 (in millions): Pension Assets 2017 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Cash $ 6 $ — $ — $ 6 $ 10 $ — $ — $ 10 Short-term investment funds — 65 — 65 — 100 — 100 Mutual funds(a) 245 — — 245 197 — — 197 Equities(b) 278 — — 278 283 — — 283 Fixed income securities(c) — 416 — 416 — 428 — 428 Immediate participation guarantee contract — — — — — — 16 16 Derivatives — 5 — 5 — (2 ) — (2 ) Subtotal $ 529 $ 486 $ — 1,015 $ 490 $ 526 $ 16 1,032 Measured at NAV(d) Common/collective trusts(e) 895 829 Private investment funds(f) 337 290 Private limited partnerships(g) 49 9 Subtotal 1,281 1,128 Total plan assets fair value $ 2,296 $ 2,160 _______ (a) Includes mutual funds which are invested in equity. (b) Plan assets include $110 million and $126 million of KMI Class P common stock for 2017 and 2016 , respectively. (c) For 2016, plan assets include $1 million of KMI debt securities. (d) Plan assets for which fair value was measured using NAV as a practical expedient. (e) Common/collective trust funds were invested in approximately 36% fixed income and 64% equity in 2017 and 39% fixed income and 61% equity in 2016 . (f) Private investment funds were invested in approximately 52% fixed income and 48% equity in 2017 and 54% fixed income and 46% equity in 2016 . (g) Includes assets invested in real estate, venture and buyout funds. 2016 also includes high yield investments. OPEB Assets 2017 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Short-term investment funds $ — $ 7 $ — $ 7 $ — $ 15 $ — $ 15 Equities(a) 16 — — 16 11 — — 11 MLPs 50 — — 50 57 — — 57 Guaranteed insurance contracts — — 49 49 — — 47 47 Mutual funds 1 — — 1 1 — — 1 Subtotal $ 67 $ 7 $ 49 123 $ 69 $ 15 $ 47 131 Measured at NAV(b) Common/collective trusts(c) 68 68 Fixed income trusts 66 64 Limited partnerships(d) 78 69 Subtotal 212 201 Total plan assets fair value $ 335 $ 332 _______ (a) Plan assets include $2 million of KMI Class P common stock for each 2017 and 2016. (b) Plan assets for which fair value was measured using NAV as a practical expedient. (c) Common/collective trust funds were invested in approximately 71% equity and 29% fixed income securities for 2017 and 72% equity and 28% fixed income securities for 2016 . (d) Limited partnerships were invested in global equity securities.
Schedule of Changes in Accumulated Postemployment Benefit Obligations [Table Text Block]	The following tables present the changes in our pension and OPEB plans’ assets included in Level 3 for the years ended December 31, 2017 and 2016 (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 ) $ — 2016 Insurance contracts $ 15 $ — $ 1 $ — $ 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 2017 Insurance contracts $ 47 $ — $ 5 $ (3 ) $ 49 2016 Insurance contracts $ 49 $ — $ (2 ) $ — $ 47 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, 2017 and 2016 .
Schedule of Expected Benefit Payments [Table Text Block]	Expected Payment of Future Benefits and Employer Contributions . As of December 31, 2017 , we expect to make the following benefit payments under our plans (in millions): Fiscal year Pension Benefits OPEB(a) 2018 $ 244 $ 36 2019 241 36 2020 242 35 2021 232 34 2022 230 33 2023 - 2027 1,029 149 _______ (a) Includes a reduction of approximately $2 million in each of the years 2018 - 2022 and approximately $13 million in aggregate for 2023 - 2027 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
Schedule of Assumptions Used [Table Text Block]	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 2017 , 2016 and 2015 : Pension Benefits OPEB 2017 2016 2015 2017 2016 2015 Assumptions related to benefit obligations: Discount rate 3.56 % 3.83 % 4.05 % 3.48 % 3.69 % 3.91 % Rate of compensation increase 3.53 % 3.52 % 3.50 % n/a n/a n/a Assumptions related to benefit costs: Discount rate for benefit obligations 3.83 % 4.05 % 3.66 % 3.69 % 3.91 % 3.56 % Discount rate for interest on benefit obligations 3.09 % 3.24 % 3.66 % 3.05 % 3.18 % 3.56 % Discount rate for service cost 3.88 % 4.15 % 3.66 % 4.15 % 4.36 % 3.56 % Discount rate for interest on service cost 3.24 % 3.50 % 3.66 % 3.95 % 4.17 % 3.56 % Expected return on plan assets(a) 7.07 % 7.31 % 7.50 % 6.84 % 7.07 % 7.08 % Rate of compensation increase 3.52 % 3.51 % 4.50 % 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 2017 , 2016 and 2015 .
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]	A one -percentage point change in assumed health care cost trends would have the following effects as of December 31, 2017 and 2016 (in millions): 2017 2016 One-percentage point increase: Aggregate of service cost and interest cost $ 1 $ 1 Accumulated postretirement benefit obligation 22 27 One-percentage point decrease: Aggregate of service cost and interest cost $ (1 ) $ (1 ) Accumulated postretirement benefit obligation (19 ) (23 )
Schedule of Net Benefit Costs [Table Text Block]	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 2017 2016 2015 2017 2016 2015 Components of net benefit cost: Service cost $ 40 $ 36 $ 33 $ 1 $ 1 $ — Interest cost 88 89 99 13 16 21 Expected return on assets (147 ) (151 ) (172 ) (19 ) (19 ) (23 ) Amortization of prior service cost (credit) 1 1 — (3 ) (3 ) (3 ) Amortization of net actuarial loss (gain) 52 35 5 (6 ) — 1 Curtailment and settlement loss 5 — — — — — Net benefit (credit) cost(a) 39 10 (35 ) (14 ) (5 ) (4 ) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 17 116 267 (25 ) (48 ) (49 ) Prior service cost (credit) arising during period — — — — — — Amortization or settlement recognition of net actuarial (loss) gain (64 ) (34 ) (5 ) 6 — (1 ) Amortization of prior service credit (1 ) — — 1 1 1 Exchange rate changes — 1 — — — — Total recognized in total other comprehensive (income) loss (48 ) 83 262 (18 ) (47 ) (49 ) Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ (9 ) $ 93 $ 227 $ (32 ) $ (52 ) $ (53 ) _______ (a) 2017 and 2016 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, 2017
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, 2017 2016 2015 Per common share cash dividend declared for the period $ 0.50 $ 0.50 $ 1.605 Per common share cash dividend paid in the period 0.50 0.50 1.93
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, 2017 through April 25, 2017 $24.375 January 18, 2017 April 11, 2017 April 26, 2017 April 26, 2017 through July 25, 2017 24.375 April 19, 2017 July 11, 2017 July 26, 2017 July 26, 2017 through October 25, 2017 24.375 July 19, 2017 October 11, 2017 October 26, 2017 October 26, 2017 through January 25, 2018 24.375 October 18, 2017 January 11, 2018 January 26, 2018
Schedule of Distributions by Noncontrolling Interests [Table Text Block]	The following table provides information regarding distributions to our noncontrolling interests (in millions except per share and share distribution amounts): Year Ended December 31, 2017 Shares U.S.$ C$ KML Restricted Voting Shares(a) Per restricted voting share declared for the period(b) $0.3821 Per restricted voting share paid in the period $0.1739 0.2196 Total value of distributions paid in the period 18 23 Cash distributions paid in the period to the public 13 16 Share distributions paid in the period to the public under KML’s DRIP 418,989 KML Series 1 Preferred Shares(c) Per Series 1 Preferred Share paid in the period $0.2624 $0.3308 Cash distributions paid in the period to the public 3 4 _______ (a) Represents dividends subsequent to KML’s May 30, 2017 IPO. (b) The U.S.$ equivalent of the dividends declared is calculated based on the exchange rate on the dividend payment date, therefore, the U.S.$ equivalent of the dividend declared for the fourth quarter of 2017 will be calculated using the exchange rate on February 15, 2018. The combined U.S.$ equivalent of the dividends declared for the second and third quarters of 2017 was $0.1739 . (c) Represents dividends subsequent to the issuance of KML’s Series 1 Preferred Shares.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Schedule of Related Party Transactions [Table Text Block]	December 31, 2017 2016 Balance sheet location Accounts receivable, net $ 34 $ 37 Other current assets 8 — Deferred charges and other assets 23 10 $ 65 $ 47 Current portion of debt $ 6 $ 6 Accounts payable 18 28 Other current liabilities 4 9 Long-term debt 155 161 Other long-term liabilities and deferred credits 35 29 $ 218 $ 233 Year Ended December 31, 2017 2016 2015 Income statement location Revenues Services $ 73 $ 71 $ 72 Product sales and other 89 71 71 $ 162 $ 142 $ 143 Operating Costs, Expenses and Other Costs of sales $ 20 $ 38 $ 60 Other operating expenses 100 75 55

Commitments and Contingent Li41

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 (in millions): Year Commitment 2018 $ 118 2019 106 2020 81 2021 62 2022 55 Thereafter 300 Total minimum payments $ 722

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments [Table Text Block]	As of December 31, 2017 , 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 (21.0 ) MMBbl Crude oil basis (7.2 ) MMBbl Natural gas fixed price (46.4 ) Bcf Natural gas basis (21.7 ) Bcf Derivatives not designated as hedging contracts Crude oil fixed price (1.9 ) MMBbl Crude oil basis (1.2 ) MMBbl Natural gas fixed price (9.0 ) Bcf Natural gas basis (23.1 ) Bcf NGL fixed price (4.1 ) 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, 2017 2016 2017 2016 Location Fair value Fair value Derivatives designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 65 $ 101 $ (53 ) $ (57 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 14 70 (24 ) (24 ) Subtotal 79 171 (77 ) (81 ) Interest rate swap agreements Fair value of derivative contracts/(Other current liabilities) 41 94 (3 ) — Deferred charges and other assets/(Other long-term liabilities and deferred credits) 164 206 (62 ) (57 ) Subtotal 205 300 (65 ) (57 ) Cross-currency swap agreements Fair value of derivative contracts/(Other current liabilities) — — (6 ) (7 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 166 — — (24 ) Subtotal 166 — (6 ) (31 ) Total 450 471 (148 ) (169 ) Derivatives not designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 8 3 (22 ) (29 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (2 ) (1 ) Total 8 3 (24 ) (30 ) Total derivatives $ 458 $ 474 $ (172 ) $ (199 )
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance	The following tables summarize the impact of our derivative contracts on 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, 2017 2016 2015 Interest rate swap agreements Interest, net $ (103 ) $ (180 ) $ 25 Hedged fixed rate debt Interest, net $ 105 $ 160 $ (33 ) 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, 2017 2016 2015 2017 2016 2015 2017 2016 2015 Energy commodity derivative contracts $ 24 $ (115 ) $ 201 Revenues—Natural gas sales $ 12 $ 15 $ 54 Revenues—Natural gas sales $ — $ — $ — Revenues—Product sales and other 35 148 236 Revenues—Product sales and other 11 (12 ) 2 Costs of sales 9 (17 ) (15 ) Costs of sales — — — Interest rate swap agreements(c) — (2 ) (4 ) Interest, net (3 ) (3 ) (3 ) Interest, net — — — Cross-currency swap 121 13 (33 ) Other, net 118 (27 ) — Other, net — — — Total $ 145 $ (104 ) $ 164 Total $ 171 $ 116 $ 272 Total $ 11 $ (12 ) $ 2 _______ (a) We expect to reclassify an approximate $1 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of December 31, 2017 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) 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 loss. Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives Year Ended December 31, 2017 2016 2015 Energy commodity derivative contracts Revenues—Natural gas sales $ 20 $ (10 ) $ 17 Revenues—Product sales and other (16 ) (26 ) 176 Costs of sales — 3 (2 ) Interest rate swap agreements Interest, net — 63 (15 ) Total(a) $ 4 $ 30 $ 176 ________ (a) For the years ended December 31, 2017 , 2016 and 2015 includes approximate gains of $57 million , $73 million and $31 million , respectively, associated with natural gas, crude and NGL derivative contract settlements.
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	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 as of December 31, 2014 $ 327 $ (108 ) $ (236 ) $ (17 ) Other comprehensive gain (loss) before reclassifications 164 (214 ) (122 ) (172 ) Gains reclassified from accumulated other comprehensive loss (272 ) — — (272 ) Net current-period other comprehensive loss (108 ) (214 ) (122 ) (444 ) Balance as of 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 as of 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 as of December 31, 2017 $ (27 ) $ (189 ) $ (325 ) $ (541 )

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 Energy commodity derivative contracts(a) $ 17 $ 70 $ — $ 87 $ (42 ) $ (12 ) $ 33 Interest rate swap agreements $ — $ 205 $ — $ 205 $ (15 ) $ — $ 190 Cross-currency swap agreements $ — $ 166 $ — $ 166 $ (6 ) $ — $ 160 As of December 31, 2016 Energy commodity derivative contracts(a) $ 6 $ 168 $ — $ 174 $ (43 ) $ — $ 131 Interest rate swap agreements $ — $ 300 $ — $ 300 $ (18 ) $ — $ 282 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, 2017 Energy commodity derivative contracts(a) $ (3 ) $ (98 ) $ — $ (101 ) $ 42 $ — $ (59 ) Interest rate swap agreements $ — $ (65 ) $ — $ (65 ) $ 15 $ — $ (50 ) Cross-currency swap agreements $ — $ (6 ) $ — $ (6 ) $ 6 $ — $ — As of December 31, 2016 Energy commodity derivative contracts(a) $ (29 ) $ (82 ) $ — $ (111 ) $ 43 $ 37 $ (31 ) Interest rate swap agreements $ — $ (57 ) $ — $ (57 ) $ 18 $ — $ (39 ) Cross-currency swap agreements $ — $ (31 ) $ — $ (31 ) $ — $ — $ (31 ) _______ (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, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts (in millions): Significant unobservable inputs (Level 3) Year Ended December 31, 2017 2016 Derivatives-net asset (liability) Beginning of period $ — $ (15 ) Total gains or (losses) included in earnings — (9 ) Settlements — 24 End of period $ — $ — The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date $ — $ —
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, 2017 December 31, 2016 Carrying value Estimated fair value Carrying value Estimated fair value Total debt $ 37,843 $ 40,050 $ 40,050 $ 41,015

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Financial information by segment follows (in millions): Year Ended December 31, 2017 2016 2015 Revenues Natural Gas Pipelines Revenues from external customers $ 8,608 $ 7,998 $ 8,704 Intersegment revenues 10 7 21 CO 2 1,196 1,221 1,699 Terminals Revenues from external customers 1,965 1,921 1,878 Intersegment revenues 1 1 1 Products Pipelines Revenues from external customers 1,645 1,631 1,828 Intersegment revenues 16 18 3 Kinder Morgan Canada 256 253 260 Corporate and intersegment eliminations(a) 8 8 9 Total consolidated revenues $ 13,705 $ 13,058 $ 14,403 Year Ended December 31, 2017 2016 2015 Operating expenses(b) Natural Gas Pipelines $ 5,457 $ 4,393 $ 4,738 CO 2 394 399 432 Terminals 788 768 836 Products Pipelines 487 573 772 Kinder Morgan Canada 95 87 87 Corporate and intersegment eliminations (6 ) 2 26 Total consolidated operating expenses $ 7,215 $ 6,222 $ 6,891 Year Ended December 31, 2017 2016 2015 Other expense (income)(c) Natural Gas Pipelines $ 26 $ 199 $ 1,269 CO 2 (1 ) 19 606 Terminals (14 ) 99 190 Products Pipelines — 76 2 Kinder Morgan Canada — — (1 ) Corporate 1 (7 ) — Total consolidated other expense (income) $ 12 $ 386 $ 2,066 Year Ended December 31, 2017 2016 2015 DD&A Natural Gas Pipelines $ 1,011 $ 1,041 $ 1,046 CO 2 493 446 556 Terminals 472 435 433 Products Pipelines 216 221 206 Kinder Morgan Canada 46 44 46 Corporate 23 22 22 Total consolidated DD&A $ 2,261 $ 2,209 $ 2,309 Year Ended December 31, 2017 2016 2015 Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments Natural Gas Pipelines $ 253 $ (269 ) $ 285 CO 2 42 22 (5 ) Terminals 24 19 17 Products Pipelines 48 56 36 Total consolidated equity earnings $ 367 $ (172 ) $ 333 Year Ended December 31, 2017 2016 2015 Other, net-income (expense) Natural Gas Pipelines $ 49 $ 19 $ 24 Terminals 8 4 8 Products Pipelines (1 ) 2 4 Kinder Morgan Canada 25 15 8 Corporate 1 4 (1 ) Total consolidated other, net-income (expense) $ 82 $ 44 $ 43 Year Ended December 31, 2017 2016 2015 Segment EBDA(d) Natural Gas Pipelines $ 3,487 $ 3,211 $ 3,067 CO 2 847 827 658 Terminals 1,224 1,078 878 Products Pipelines 1,231 1,067 1,106 Kinder Morgan Canada 186 181 182 Total segment EBDA 6,975 6,364 5,891 DD&A (2,261 ) (2,209 ) (2,309 ) Amortization of excess cost of equity investments (61 ) (59 ) (51 ) General and administrative and corporate charges (660 ) (652 ) (708 ) Interest, net (1,832 ) (1,806 ) (2,051 ) Income tax expense (1,938 ) (917 ) (564 ) Total consolidated net income $ 223 $ 721 $ 208 Year Ended December 31, 2017 2016 2015 Capital expenditures Natural Gas Pipelines $ 1,376 $ 1,227 $ 1,642 CO 2 436 276 725 Terminals 888 983 847 Products Pipelines 127 244 524 Kinder Morgan Canada 338 124 142 Corporate 23 28 16 Total consolidated capital expenditures $ 3,188 $ 2,882 $ 3,896 2017 2016 Investments at December 31 Natural Gas Pipelines $ 6,218 $ 6,185 CO 2 6 — Terminals 263 252 Products Pipelines 777 566 Kinder Morgan Canada 34 20 Corporate — 4 Total consolidated investments $ 7,298 $ 7,027 2017 2016 Assets at December 31 Natural Gas Pipelines $ 51,173 $ 50,428 CO 2 3,946 4,065 Terminals 9,935 9,725 Products Pipelines 8,539 8,329 Kinder Morgan Canada 2,080 1,572 Corporate assets(e) 3,382 6,108 Assets held for sale — 78 Total consolidated assets $ 79,055 $ 80,305 _______ (a) Includes a management fee 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 impairment of goodwill, loss on impairments and divestitures, net and other income, net. (d) Includes revenues, earnings from equity investments, other, net, less operating expenses, and other income, net, loss on impairment of goodwill, and loss on impairments and divestitures, net and loss on impairments and divestitures of equity investments, net. (e) Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, 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 the reportable segments.
Schedule of Revenue 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, 2017 2016 2015 Revenues from external customers U.S. $ 13,073 $ 12,459 $ 13,797 Canada 503 483 479 Mexico 129 116 127 Total consolidated revenues from external customers $ 13,705 $ 13,058 $ 14,403 December 31, 2017 2016 2015 Long-term assets, excluding goodwill and other intangibles U.S. $ 47,928 $ 49,125 $ 51,679 Canada 3,071 2,399 2,193 Mexico 80 82 67 Total consolidated long-lived assets $ 51,079 $ 51,606 $ 53,939

Summary of Significant Accoun45

Summary of Significant Accounting Policies Cash Equivalents and Restricted Deposits (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Restricted deposits	$ 62	$ 103

Summary of Significant Accoun46

Summary of Significant Accounting Policies Accounts Receivable, Net (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Allowance for Doubtful Accounts Receivable	$ 35	$ 39

Summary of Significant Accoun47

Summary of Significant Accounting Policies Gas Imbalances (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Gas imbalance receivable	$ 42	$ 108
Gas imbalance payable	$ 47	$ 45

Summary of Significant Accoun48

Summary of Significant Accounting Policies Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Composite depreciation rate, low	1.09%
Composite depreciation rate, high	23.00%

Summary of Significant Accoun49

Summary of Significant Accounting Policies Equity investment and excess costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Sep. 01, 2016
Schedule of Equity Method Investments [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	16 years
Sale Equity Interest in SNG [Member]
Schedule of Equity Method Investments [Line Items]
Disposal Group, Equity Interest Sold			50.00%
Acquisition-related Costs [Member]
Schedule of Equity Method Investments [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	14 years
Property, Plant and Equipment, Other Types [Member] | Amortized [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method of Accounting and Excess Investment Cost	$ 732	$ 767
Goodwill [Member] | Unamortization [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method of Accounting and Excess Investment Cost	$ 956	$ 956

Summary of Significant Accoun50

Summary of Significant Accounting Policies Goodwill (Details)	12 Months Ended
	Dec. 31, 2017
May 31st [Member]
Goodwill [Line Items]
Number of Operating Segments	7

Summary of Significant Accoun51

Summary of Significant Accounting Policies Other Intangibles (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Intangible Assets, Gross (Excluding Goodwill)	$ 4,305	$ 4,305
Finite-Lived Intangible Assets, Accumulated Amortization	1,206	987
Intangible Assets, Net (Excluding Goodwill)	3,099	3,318
Amortization of Intangible Assets	220	$ 223	$ 221
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	214
Finite-Lived Intangible Assets, Amortization Expense, Year Two	212
Finite-Lived Intangible Assets, Amortization Expense, Year Three	209
Finite-Lived Intangible Assets, Amortization Expense, Year Four	209
Finite-Lived Intangible Assets, Amortization Expense, Year Five	$ 206
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	16 years

Summary of Significant Accoun52

Summary of Significant Accounting Policies Operations and Maintenance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ 342	$ 349	$ 366

Summary of Significant Accoun53

Summary of Significant Accounting Policies Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Regulatory Assets and Liabilities [Line Items]
Current regulatory assets	$ 60	$ 49
Non-current regulatory assets	288	330
Total regulatory assets(a)	348	379
Current regulatory liabilities	107	101
Non-current regulatory liabilities	236	108
Total regulatory liabilities(b)	343	$ 209
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	$ 124
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	17 years
Remaining Amounts of Regulatory Non-current Liabilities Subject to Crediting Period	$ 20
Remaining Recovery Period of Regulatory Liabilities Subject to Defined Crediting Period	28 years
Remaining Amounts of Regulatory Non-current Liabilities Not Subject to Defined Crediting Period	$ 216
Loss on Disposal of Assets [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	193
Income Tax Gross Up on AFUDC Equity [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	55
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	$ 100

Summary of Significant Accoun54

Summary of Significant Accounting Policies Earnings per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	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	$ 27	$ 552	$ 227
Basic Weighted Average Common Shares Outstanding	2,230	2,230	2,187
Basic Earnings Per Common Share	$ 0.01	$ 0.25	$ 0.10
Warrants	0	0	6
Diluted Weighted Average Common Shares Outstanding	2,230	2,230	2,193
Number of Warrants Expiring				293
Class of Warrant or Right, Exercise Price of Warrants or Rights					$ 40
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	10	8	7
Warrants to purchase our Class P shares(a)
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	291
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	8	8
Mandatory convertible preferred stock(b)
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	58	58	10
Less: Net Income Allocated to Restricted stock awards(a)
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ (5)	$ (4)	$ (13)
Unvested Restricted Stock Awards, Issued and Non Issued	11
Class P
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ 22	$ 548	$ 214

Acquisitions and Divestitures B

Acquisitions and Divestitures Business Combinations and Acquisitions of Investments (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Feb. 01, 2016	Dec. 31, 2015	Feb. 27, 2015	Feb. 13, 2015
Business Acquisition [Line Items]
Goodwill	$ 22,162	$ 22,152		$ 23,790
BP Terminal Assets [Member]
Business Acquisition [Line Items]
Purchase price			$ 349
Current assets			2
Property, plant, and equipment			396
Deferred charges & other			0
Goodwill			0
Debt			0
Other liabilities			$ (49)
Vopak Terminal Assets [Member]
Business Acquisition [Line Items]
Purchase price					$ 158
Current assets					2
Property, plant, and equipment					155
Deferred charges & other					0
Goodwill					6
Debt					0
Other liabilities					$ (5)
Hiland Partners, LP [Member]
Business Acquisition [Line Items]
Purchase price						$ 1,709
Current assets						79
Property, plant, and equipment						1,492
Deferred charges & other						1,498
Goodwill						310
Debt						(1,413)
Other liabilities						$ (257)

Acquisitions and Divestitures (

Acquisitions and Divestitures (1) BP Products North America Inc. (BP) Terminal Assets (Details) $ in Millions	Feb. 01, 2016USD ($)Terminals	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)Terminals	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Proceeds from noncontrolling interests | $		$ 12	$ 117	$ 11
BP Terminal Assets [Member]
Business Acquisition [Line Items]
Number of terminals	15
Payments to Acquire Businesses, Gross | $	$ 349
Number of terminals wholly owned	1
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	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			20
Terminals | New Joint Venture with BP [Member] | BP Terminal Assets [Member]
Business Acquisition [Line Items]
Number of terminals	10
Products Pipelines | New Joint Venture with BP [Member] | BP Terminal Assets [Member]
Business Acquisition [Line Items]
Number of terminals	5

Acquisitions and Divestitures57

Acquisitions and Divestitures (2) Vopak Terminal Assets (Details) - Vopak Terminal Assets [Member] $ in Millions	Feb. 27, 2015USD ($)aTerminalsbbl
Business Acquisition [Line Items]
Number of terminals	3
Number of Real Estate Properties	1
Payments to Acquire Businesses, Gross | $	$ 158
Galena Park, Texas [Member]
Business Acquisition [Line Items]
Area of Land | a	36
Storage Capacity | bbl	1,069,500
North Carolina [Member]
Business Acquisition [Line Items]
Number of terminals	2
North Wilmington, North Carolina [Member]
Business Acquisition [Line Items]
Number of terminals	1
South Wilmington, North Carolina [Member]
Business Acquisition [Line Items]
Number of terminals	1
Perth Amboy, New Jersey [Member]
Business Acquisition [Line Items]
Number of Real Estate Properties	1

Acquisitions and Divestitures58

Acquisitions and Divestitures (3) Hiland (Details) - USD ($) $ in Millions	Feb. 13, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Repayments of Debt Assumed		$ 11,064	$ 10,060	$ 15,116
Hiland Partners, LP [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 3,122
Repayments of Debt Assumed	$ 368
Finite-Lived Intangible Asset, Useful Life	16 years 5 months

Acquisitions and Divestitures A

Acquisitions and Divestitures Asset Purchase and Subsequent Sale of Noncontrolling Interest (Details) - USD ($) $ in Millions	Jul. 15, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 28, 2017
Property, Plant and Equipment [Line Items]
Proceeds from noncontrolling interests		$ 12	$ 117	$ 11
Elba Liquification Company LLC [Member]
Property, Plant and Equipment [Line Items]
Payments to Acquire Assets, Investing Activities	$ 185
Shell US Gas & Power LLC [Member] | Elba Liquification Company LLC [Member]
Property, Plant and Equipment [Line Items]
Equity Method Investment, Ownership Percentage	49.00%
Capacity Subscribed, Percent	100.00%
Sale of Equity Interest in Elba Liquification Company LLC [Member] [Member]
Property, Plant and Equipment [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners					49.00%
Controlling Interest, Ownership Percentage by Parent					51.00%
Other Long-Term Liabilities and Deferred Credits [Member] | Sale of Equity Interest in Elba Liquification Company LLC [Member] [Member]
Property, Plant and Equipment [Line Items]
Proceeds from noncontrolling interests		$ 386

Acquisitions and Divestitures I

Acquisitions and Divestitures Investment Acquisition (Details) - NGPL Holdings, LLC - USD ($) $ in Millions	Dec. 10, 2015	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%	50.00%
Payments to Acquire Assets, Investing Activities	$ 136
Equity Method Investment, Incremental Ownership Percentage Acquired	30.00%
KMI and Brookfield Infrastructure Partners L.P. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Incremental Ownership Percentage Acquired	53.00%
Brookfield Infrastructure Partners L.P.
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%	50.00%

Acquisitions and Divestitures S

Acquisitions and Divestitures Sale of Interest in Canadian Business (Details) CAD / shares in Units, CAD in Millions, $ in Millions	May 30, 2017USD ($)	May 30, 2017CADCAD / sharesshares	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from noncontrolling interests			$ 12	$ 117	$ 11
Noncontrolling Interest, Increase from Sale of Parent Equity Interest			1,049
Total current assets			2,715	3,229
Property, plant and equipment, net			40,155	38,705
Other non-current assets			1,582	1,522
Total Assets			79,055	80,305
Current portion of debt			2,828	2,696
Total other current liabilities			6,181	5,924
Long-term debt			35,015	37,354
Other long-term liabilities and deferred credits			2,735	2,225
Total Liabilities			$ 43,931	$ 45,503
Other funded debt percentage			60.00%
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 Partnership [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total current assets			$ 270
Property, plant and equipment, net			2,956
Other non-current assets			322
Total Assets			3,548
Current portion of debt			0
Total other current liabilities			236
Long-term debt			0
Other long-term liabilities and deferred credits			414
Total Liabilities			650
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] | 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]
Proceeds from noncontrolling interests			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
Shares Issued, Price Per Share | CAD / shares		CAD 17
Proceeds from Issuance Initial Public Offering	$ 1,299	CAD 1,750
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%

Acquisitions and Divestitures T

Acquisitions and Divestitures Terminals Asset Sale (Details) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Oct. 31, 2016USD ($)	Dec. 31, 2016USD ($)Terminals	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)	Jun. 30, 2017Terminals
Long Lived Assets Held-for-sale [Line Items]
Assets held for sale		$ 78	$ 78	$ 0
Terminal Asset Sale [Member]
Long Lived Assets Held-for-sale [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	$ 100
Gain (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]
Proceeds from Sale of Property, Plant, and Equipment		$ 37
Number of Terminals Sales Transaction Closed | Terminals		8
Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Terminal Asset Sale [Member]
Long Lived Assets Held-for-sale [Line Items]
Number of terminals | Terminals					11
Assets held for sale		$ 61	$ 61

Acquisitions and Divestitures63

Acquisitions and Divestitures Sale of Equity Interest in SNG (Details) - USD ($) $ in Millions	Sep. 01, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ 1,401	$ 0
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
Gain (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]
Disposal Group, Equity Interest Sold	50.00%
Equity Method Investment, Ownership Percentage	50.00%
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%

Impairments (Details)

Impairments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)Terminals	Dec. 31, 2015USD ($)	Sep. 01, 2016
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (gain) on Sale of Assets and Asset Impairment Charges	$ 172	$ 1,013	$ 2,125
Loss on impairment of goodwill	0	0	1,150
Loss (Gain) on impairments and divestitures of equity investments, net	150	610	30
MEP
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]
Loss (Gain) on impairments and divestitures of equity investments, net		250
Sale Equity Interest in SNG [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Disposal Group, Equity Interest Sold				50.00%
Regulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairment of long-lived assets			32
Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (gain) on Sale of Assets and Asset Impairment Charges	0	94	43
Loss on impairment of goodwill	0	0	1,150
Impairment of long-lived assets	30	106	79
Loss (Gain) on impairments and divestitures of equity investments, net	150	606	26
Natural Gas Pipelines | Investee [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (Gain) on impairments and divestitures of equity investments, net	10	7	0
Nonregulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairment of long-lived assets			47
CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (gain) on Sale of Assets and Asset Impairment Charges	0	(1)	0
Impairment of long-lived assets	(1)	20	606
CO2 | Investee [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (Gain) on impairments and divestitures of equity investments, net	(4)	9	26
CO2 | Oil and Gas Properties [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairment of long-lived assets			399
CO2 | Source and transportation projects [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairment of long-lived assets			207
Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (gain) on Sale of Assets and Asset Impairment Charges	(18)	80	3
Impairment of long-lived assets	3	19	188
Loss (Gain) on impairments and divestitures of equity investments, net	0	$ 16	4
Number of terminals | Terminals		20
Terminals | Coal
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairment of long-lived assets			175
Terminals | Deeprock Development [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (gain) on Sale of Assets and Asset Impairment Charges	$ 23
Disposal Group, Equity Interest Sold	40.00%
Products Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (gain) on Sale of Assets and Asset Impairment Charges	$ 0	$ 10	1
Impairment of long-lived assets	0	66	0
Loss (Gain) on impairments and divestitures of equity investments, net	0	(12)	0
Other
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (gain) on Sale of Assets and Asset Impairment Charges	2	(7)	(1)
Operating Segments
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss (gain) on Sale of Assets and Asset Impairment Charges	172	$ 1,013	2,125
Natural Gas Pipelines-Nonregulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairment of goodwill			$ 1,150
Cost of Sales [Member] | Colden storage [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Impairment of long-lived assets	$ 3

Income Taxes Income Tax Disclos

Income Taxes Income Tax Disclosures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Results of Operations, Income before Income Taxes [Abstract]
U.S.	$ 1,976	$ 1,466	$ 611
Foreign	185	172	161
Total Income Before Income Taxes	2,161	1,638	772
Current tax expense (benefit) [Abstract]
Federal	(137)	(148)	(125)
State	(16)	(28)	(7)
Foreign	18	6	4
Total	(135)	(170)	(128)
Deferred tax expense (benefit) [Abstract]
Federal	2,022	998	653
State	4	51	(4)
Deferred Foreign Income Tax Expense (Benefit)	47	38	43
Deferred Income Tax Expense (Benefit)	2,073	1,087	692
Effective Income Tax Rate Reconciliation [Abstract]
Federal income tax	$ 756	$ 573	$ 271
Federal income tax, percent	35.00%	35.00%	35.00%
State deferred tax rate change	$ 10	$ 11	$ (24)
State deferred tax rate change, percent	0.50%	0.70%	(3.10%)
Taxes on foreign earnings, net of federal benefit	$ 42	$ 28	$ 26
Taxes on foreign earnings, net of federal benefit, percent	1.90%	1.70%	3.50%
Net effects of noncontrolling interests	$ (14)	$ (4)	$ 15
Net effects of noncontrolling interests, percent	(0.70%)	(0.30%)	2.00%
State income tax, net of federal benefit	$ 38	$ 26	$ 12
State income tax, net of federal benefit, percent	1.80%	1.60%	1.50%
Dividend received deduction	$ (56)	$ (48)	$ (51)
Dividend received deduction, percent	(2.60%)	(2.90%)	(6.60%)
Adjustment to uncertain tax positions	$ (12)	$ (23)	$ (14)
Adjustment to uncertain tax positions, percent	(0.60%)	(1.40%)	(1.90%)
Valuation allowance on investment and tax credits	$ 13	$ 34	$ 0
Valuation allowance on investment and tax credits, percent	0.60%	2.10%	0.00%
Impact of the 2017 Tax Reform	$ 1,240	$ 0	$ 0
Impact of the 2017 Tax Reform, percent	57.40%	0.00%	0.00%
Nondeductible goodwill	$ 0	$ 301	$ 323
Nondeductible goodwill, percent	0.00%	18.50%	41.70%
General business credit	$ (95)	$ 0	$ 0
General business credit, percent	(4.40%)	(0.00%)	(0.00%)
Other	$ 16	$ 19	$ 6
Other, percent	0.80%	1.10%	0.80%
Total Income Before Income Taxes	$ 1,938	$ 917	$ 564
Total, percent	89.70%	56.10%	72.90%
Deferred Tax Assets [Abstract]
Employee benefits	$ 251	$ 401
Accrued expenses	73	118
Net operating loss, capital loss and tax credit carryforwards	1,113	1,307
Derivative instruments and interest rate and currency swaps	12	22
Debt fair value adjustments	37	74
Investments	968	2,804
Other	6	14
Valuation allowance	(171)	(184)
Total deferred tax assets	2,289	4,556
Deferred Tax Liabilities, Gross [Abstract]
Property, plant and equipment	225	177
Other	20	27
Total deferred tax liabilities	245	204
Net deferred tax assets	2,044	4,352
Canada
Income Tax Disclosures [Line Items]
Foreign Income Tax Expense (Benefit), Continuing Operations	58	38	$ 46
Mexico
Income Tax Disclosures [Line Items]
Foreign Income Tax Expense (Benefit), Continuing Operations	$ 7	$ 6	$ 1

Income Taxes Deferred Tax Asset

Income Taxes Deferred Tax Assets and Valuation Allowances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Valuation Allowance [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ (13)
Deferred Tax Assets, Operating Loss Carryforwards	935	$ 1,128
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	178	175
Deferred Tax Assets, Capital Loss Carryforwards		4
Proceeds from Income Tax Refunds	144
Capital Loss Carryforward [Member]
Valuation Allowance [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	(4)
Foreign Tax Authority [Member]
Valuation Allowance [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	(5)
Annual Rate Reductions [Member]
Valuation Allowance [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	(24)
Valuation Allowance, Operating Loss Carryforwards [Member]
Valuation Allowance [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	18
Valuation Allowance, Tax Credit Carryforward [Member]
Valuation Allowance [Line Items]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	2
Valuation Allowance of Deferred Tax Assets [Member]
Valuation Allowance [Line Items]
Valuation Allowances and Reserves, Balance	133	$ 123
Deferred Income Tax Charge [Member]
Valuation Allowance [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax Increase (Decrease)	(143)
Deferred Compensation, Share-based Payments [Member]
Valuation Allowance [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	$ 8

Income Taxes Deferred Tax Ass67

Income Taxes Deferred Tax Asset Expiration Periods (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Income Tax Examination [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	$ 178	$ 175
Expires from 2018 - 2037 [Member] | Domestic Tax Authority [Member]
Income Tax Examination [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	3,400
Expires from 2018 - 2037 [Member] | State and Local Jurisdiction [Member] | Domestic Tax Authority [Member]
Income Tax Examination [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	3,200
Expires from 2029 - 2036 [Member] | Foreign Tax Authority [Member]
Income Tax Examination [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Foreign	134
Does Not Expire [Member]
Income Tax Examination [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	8
Expires 2018 - 2027 [Member]
Income Tax Examination [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards	147
Majority expire from 2018 - 2023 [Member]
Income Tax Examination [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	$ 21

Income Taxes Unrecognized Tax B

Income Taxes Unrecognized Tax Benefits (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Required minimum likelihood for benefits to be recognized in the financial statements				50.00%
Balance at beginning of year	$ 122,000,000	$ 148,000,000	$ 189,000,000
Additions based on current year tax positions	3,000,000	3,000,000	4,000,000
Additions based on prior year tax positions	0	7,000,000	0
Reductions based on prior year tax positions	0	(1,000,000)	(6,000,000)
Reductions based on settlements with taxing authority	(22,000,000)	(26,000,000)	(25,000,000)
Reductions due to lapse in statute of limitations	(2,000,000)	(9,000,000)	(14,000,000)
Impact of the 2017 Tax Reform	(4,000,000)	0	0
Balance at end of year	97,000,000	122,000,000	148,000,000
Unrecognized Tax Benefits,Other Disclosure [Abstract]
Income Tax Examination, Penalties and Interest Expense	(9,000,000)	2,000,000	(4,000,000)
Income Tax Examination, Interest Accrued				$ 19,000,000	$ 28,000,000	$ 24,000,000
Income Tax Examination, Penalties Accrued				0	0	2,000,000
Unrecognized Tax Benefits	$ 122,000,000	$ 148,000,000	$ 189,000,000	97,000,000	$ 122,000,000	$ 148,000,000
Increase in Unrecognized Tax Benefits is Reasonably Possible				6,000,000
Unrecognized tax benefits balance reasonably possible next year				$ 91,000,000

Income Taxes 2017 Tax Reform (D

Income Taxes 2017 Tax Reform (Details) - USD ($) $ in Millions	Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Federal income tax		35.00%	35.00%	35.00%
New Federal Income Tax Rate	21.00%
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ 1,240	$ 0	$ 0
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 2017 Tax Reform [Member] | Investee [Member]
Income Tax Contingency [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		219
Impact of 2017 Tax Reform [Member] | after tax [Member] | Investee [Member]
Income Tax Contingency [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ 144

Property, Plant and Equipment C

Property, Plant and Equipment Classes and Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Accumulated depreciation, depletion and amortization	$ (14,175)	$ (12,306)
Public Utilities, Property, Plant and Equipment, Equipment	35,704	35,113
Land and land rights-of-way	1,456	1,431
Construction work in process	2,995	2,161
Property, plant and equipment, net	40,155	38,705
Public Utilities, Property, Plant and Equipment, Common	14,055	12,900
Depreciation, depletion and amortization	2,261	2,209	$ 2,309
Charged against PPE [Member]
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Depreciation, depletion and amortization	2,022	1,970	$ 2,059
Gas Transmission Equipment [Member]
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Pipelines (Natural gas, liquids, crude oil and CO2)	20,157	19,341
Gas, Transmission and Distribution Equipment [Member]
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Equipment (Natural gas, liquids, crude oil, CO2, and terminals)	24,152	23,298
Property, Plant and Equipment, Other Types [Member]
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Other(a)	$ 5,570	$ 4,780

Property, Plant and Equipment A

Property, Plant and Equipment Asset Retirement Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	$ 208	$ 193
Asset Retirement Obligation, Current	$ 4	$ 9

Investments Equity investments

Investments Equity investments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)	Dec. 10, 2015
Investment [Line Items]
Preferred stock, shares issued (in shares) | shares	1,600,000	1,600,000
Payments to Acquire Equity Method Investments	$ 684	$ 408	$ 96
Long-term Investments	$ 7,298	7,027
Citrus Corporation
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 1,698	1,709
SNG
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 1,495	1,505
Ruby Pipeline Holding Company LLC [Member]
Investment [Line Items]
Total equity investments	$ 774	798
NGPL Holdings, LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%			50.00%
Total equity investments	$ 687	475
Gulf LNG Holdings Group LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 461	485
Plantation Pipe Line Company
Investment [Line Items]
Equity Method Investment, Ownership Percentage	51.17%
Total equity investments	$ 331	333
EagleHawk Field Services
Investment [Line Items]
Equity Method Investment, Ownership Percentage	25.00%
Total equity investments	$ 314	329
Utopia Holding L.L.C.
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 276	55
Midcontinent Express Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 253	328
Red Cedar Gathering company
Investment [Line Items]
Equity Method Investment, Ownership Percentage	49.00%
Total equity investments	$ 187	191
Watco Companies LLC
Investment [Line Items]
Common Unit, Issued | shares	13,000
Profit participation rate	0.40%
Total equity investments	$ 182	180
Watco Companies LLC | Preferred stock
Investment [Line Items]
Preferred stock, shares issued (in shares) | shares	100,000
Quarterly preferred distribution rate	3.25%
Watco Companies LLC | Preferred Class B [Member]
Investment [Line Items]
Preferred stock, shares issued (in shares) | 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]
Total equity investments	$ 149	151
Fayetteville Express
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 112	101
Liberty Pipeline
Investment [Line Items]
Total equity investments	$ 71	75
Bear Creek Storage Company L.L.C.
Investment [Line Items]
Equity Method Investment, Ownership Percentage	75.00%
Total equity investments	$ 63	61
Sierrita Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	35.00%
Total equity investments	$ 55	57
Fort Union Pipeline
Investment [Line Items]
Equity Method Investment, Ownership Percentage	37.04%
Total equity investments	$ 12	25
All Other Legal Entities [Member]
Investment [Line Items]
Total equity investments	$ 178	$ 169
Cortez Pipeline Company
Investment [Line Items]
Equity Method Investment, Ownership Percentage	52.98%
Florida Gas Transmission Company, L.L.C. [Member]
Investment [Line Items]
Miles Of Pipeline	5,300
BHP Billiton Petroleum | EagleHawk Field Services
Investment [Line Items]
Equity Method Investment, Ownership Percentage	75.00%
ONEOK Partners L.P. [Member] | Fort Union Pipeline
Investment [Line Items]
Equity Method Investment, Ownership Percentage	37.04%
Powder River Midstream, LLC [Member] | Fort Union Pipeline
Investment [Line Items]
Equity Method Investment, Ownership Percentage	11.11%
Western Gas Resources Inc [Member] | Fort Union Pipeline
Investment [Line Items]
Equity Method Investment, Ownership Percentage	14.81%
MIT Pipeline Investment Americas, Inc. | Sierrita Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	30.00%
MGI Enterprises U.S. LLC | Sierrita Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	35.00%
Riverstone Investment Group LLC | Utopia Holding L.L.C.
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%
Pembina Pipeline Company [Member] | Ruby Pipeline Holding Company LLC [Member]
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Energy Transfers Partners L.P. | Citrus Corporation
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Energy Transfers Partners L.P. | Midcontinent Express Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Southern Natural Gas Company 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 Ute Indian Tribe [Member] | Red Cedar Gathering company
Investment [Line Items]
Equity Method Investment, Ownership Percentage	51.00%
Brookfield Infrastructure Partners L.P. | NGPL Holdings, LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%			50.00%
SNG | Bear Creek Storage Company L.L.C.
Investment [Line Items]
Equity Method Investment, Ownership Percentage	25.00%
Cortez Vickers Pipeline Company [Member] | Cortez Pipeline Company
Investment [Line Items]
Equity Method Investment, Ownership Percentage	13.77%
Mobil Cortez Pipeline Inc. [Member] | Cortez Pipeline Company
Investment [Line Items]
Equity Method Investment, Ownership Percentage	33.25%
TGP [Member] | Bear Creek Storage Company L.L.C.
Investment [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, 2017	Dec. 31, 2016	Dec. 31, 2015
Net Investment Income [Line Items]
Equity Method Investment, Other than Temporary Impairment	$ 150	$ 610	$ 30
Income (Loss) from Equity Method Investments	578	497	414
Income (loss) from Equity Method Investments, Net of Impairments	578	497	414
Amortization of excess costs	$ (61)	(59)	(51)
Citrus Corporation
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 108	102	96
SNG
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 77	58	0
Fayetteville Express
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 53	51	55
Gulf LNG Holdings Group LLC
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 47	48	49
Plantation Pipe Line Company
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	51.17%
Income (Loss) from Equity Method Investments	$ 46	37	29
Cortez Pipeline Company
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	52.98%
Equity Method Investment, Other than Temporary Impairment	$ 4	9	26
Income (Loss) from Equity Method Investments	44	24	(3)
Ruby Pipeline Holding Company LLC [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	$ 44	15	18
Midcontinent Express Pipeline LLC
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 38	40	45
EagleHawk Field Services
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	25.00%
Income (Loss) from Equity Method Investments	$ 24	10	24
Watco Companies LLC
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	$ 19	25	16
Red Cedar Gathering company
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	49.00%
Equity Method Investment, Other than Temporary Impairment	$ 10
Income (Loss) from Equity Method Investments	$ 14	24	26
Fort Union Pipeline
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	37.04%
Equity Method Investment, Other than Temporary Impairment		7
Income (Loss) from Equity Method Investments	$ 10	1	16
NGPL Holdco LLC [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	10	12	0
Liberty Pipeline
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	$ 9	11	9
Bear Creek Storage
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	75.00%
Income (Loss) from Equity Method Investments	$ 8	2	0
Sierrita Pipeline LLC
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	35.00%
Income (Loss) from Equity Method Investments	$ 7	7	9
Double Eagle Pipeline LLC
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	7	5	3
Parkway Pipeline LLC [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	0	14	5
All Other Legal Entities [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	$ 13	$ 11	$ 17

Investments Investments (Detail

Investments Investments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)
Schedule of Equity Method Investments [Line Items]
Loss on impairments and divestitures of equity investments, net (Note 4)	$ 150	$ 610	$ 30
Preferred stock, shares issued (in shares) | shares	1,600,000	1,600,000
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest	$ (684)	$ (408)	$ (96)
Florida Gas Transmission Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Miles Of Pipeline	5,300
Ruby
Schedule of Equity Method Investments [Line Items]
Loss on impairments and divestitures of equity investments, net (Note 4)		250
MEP
Schedule of Equity Method Investments [Line Items]
Loss on impairments and divestitures of equity investments, net (Note 4)		$ 350
Double Eagle Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Liberty Pipeline Group LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Energy Transfers Partners L.P. | Fayetteville Express
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Energy Transfers Partners L.P. | Liberty Pipeline Group LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Magellan Midstream Partners [Member] | Double Eagle Pipeline LLC
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 Summary of Signific

Investments Summary of Significant Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summarized Financial Information for Significant Equity Investments [Line Items]
Percent of investee information represented	100.00%
Revenues	$ 4,703	$ 4,084	$ 3,857
Costs and expenses	3,398	3,056	3,408
Net income	1,305	1,028	$ 449
Current assets	956	892
Non-current assets	22,344	22,170
Current liabilities	1,241	3,532
Non-current liabilities	10,605	9,187
Partners’/owners’ equity	$ 11,454	$ 10,343

Goodwill Goodwill - Rollforward

Goodwill Goodwill - Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 27, 2015
Goodwill [Line Items]
Goodwill, Impairment Loss	$ 0	$ 0	$ 1,150
Historical Goodwill			29,353
Accumulated impairment losses			(5,563)
Goodwill	22,162	22,152	23,790
Divestitures(a)	(3)	(1,644)
Currency translation	13	6
Natural Gas Pipelines Regulated
Goodwill [Line Items]
Historical Goodwill			17,527
Accumulated impairment losses			(1,643)
Goodwill	14,249	14,249	15,884
Divestitures(a)	0	(1,635)
Currency translation	0	0
Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Goodwill, Impairment Loss			1,150
Historical Goodwill			5,812
Accumulated impairment losses			(1,597)
Goodwill	4,215	4,215	4,215
Divestitures(a)	0	0
Currency translation	0	0
CO2
Goodwill [Line Items]
Historical Goodwill			1,528
Accumulated impairment losses			0
Goodwill	1,528	1,528	1,528
Divestitures(a)	0	0
Currency translation	0	0
Products Pipelines
Goodwill [Line Items]
Historical Goodwill			2,125
Accumulated impairment losses			(1,197)
Goodwill	928	928	928
Divestitures(a)	0	0
Currency translation	0	0
Products Pipelines Terminals
Goodwill [Line Items]
Historical Goodwill			221
Accumulated impairment losses			(70)
Goodwill	151	151	151
Divestitures(a)	0	0
Currency translation	0	0
Terminals
Goodwill [Line Items]
Historical Goodwill			1,584
Accumulated impairment losses			(679)
Goodwill	893	896	905
Divestitures(a)	(3)	(9)
Currency translation	0	0
Kinder Morgan Canada
Goodwill [Line Items]
Historical Goodwill			556
Accumulated impairment losses			(377)
Goodwill	198	185	$ 179
Divestitures(a)	0	0
Currency translation	$ 13	$ 6
Vopak Terminal Assets [Member]
Goodwill [Line Items]
Goodwill				$ 6

Goodwill Goodwill (Details)

Goodwill Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Sep. 01, 2016
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	$ 3	$ 1,644
Natural Gas Pipelines Regulated
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	0	1,635
Terminals
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	3	9
Products Pipelines Terminals
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	0	0
CO2
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	$ 0	0
Sale Equity Interest in SNG [Member]
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit		$ 1,635
Disposal Group, Equity Interest Sold			50.00%

Goodwill Allocation of Fair Val

Goodwill Allocation of Fair Value (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Fair Value [Line Items]
Loss on impairment of goodwill	$ 0	$ 0	$ 1,150
Natural Gas Pipelines
Schedule of Fair Value [Line Items]
Loss on impairment of goodwill	$ 0	$ 0	$ 1,150
Minimum [Member]
Schedule of Fair Value [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	3.00%
Maximum [Member]
Schedule of Fair Value [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	89.00%

Debt (Details)

Debt (Details) - USD ($) $ / shares in Units, $ in Millions	Dec. 01, 2017	Aug. 13, 2017	Aug. 10, 2017	Jun. 15, 2017	Apr. 15, 2017	Apr. 01, 2017	Feb. 01, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Preferred interest in general partner of KMP								$ 100	$ 100
Less: Current portion of debt(a)(f)(k)								2,828	2,696
Total Long-term debt - KMI and Subsidiaries(l)								35,015	37,354
Proceeds from Issuance of Debt								8,868	8,629	$ 14,316
Repayments of Debt								11,064	10,060	15,116
Gain (Loss) on Extinguishment of Debt								$ (4)	$ 45	$ 0
Preferred Stock, Liquidation Preference Per Share								$ 1,000	$ 1,000
Value of preferred securities value assigned to debt								$ 200
Value of preferred securities value assigned to equity								$ 21
Preferred stock, shares outstanding (in shares)								1,600,000	1,600,000
Preferred Stock, Dividend Rate, Percentage								9.75%	9.75%
Debt Instrument, Fair Value Disclosure								$ 927	$ 1,149
Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial Paper								$ 240
Kinder Morgan, Inc.
Debt Instrument [Line Items]
Redemption price of debt as a percentage of face amount								100.00%
Class of Warrant or Right, Number of Securities Called by Warrants or Rights								1.100
Kinder Morgan, Inc. | Senior unsecured revolving credit facility due 2019 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding								$ 125	0
Kinder Morgan, Inc. | Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial Paper								240	0
Kinder Morgan Canada | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding								$ 0	$ 0
Colorado Interstate Gas Company, L.L.C. [Member]
Debt Instrument [Line Items]
Construction Costs Funded								50.00%
Capital Trust I [Member]
Debt Instrument [Line Items]
Trust Convertible Preferred Securities Outstanding (in shares)								4,400,000
Kinder Morgan G.P., Inc. [Member]
Debt Instrument [Line Items]
Preferred stock, shares outstanding (in shares)								100,000	100,000
Preferred Stock, Dividend Rate, Percentage								3.8975%
Kinder Morgan, Inc and Subsidiaries [Member]
Debt Instrument [Line Items]
Total debt – KMI and Subsidiaries								$ 36,916	$ 38,901
Total Long-term debt - KMI and Subsidiaries(l)								$ 34,088	36,205
Capital Trust [Member]
Debt Instrument [Line Items]
Equity Method Investment, Ownership Percentage								100.00%
Senior unsecured term loan facility, variable, due 2019 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Senior Notes								$ 0	1,000
Repayments of Debt			$ 1,000
Senior Notes, floating rate, due January 15, 2023 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Senior Notes								250	0
Proceeds from Issuance of Debt			250
KMI Senior Notes,1.50% through 8.25%, due 2016 through 2098 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Senior Notes								$ 13,136	13,236
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Foreign Currency Exchange Rate, Translation								0.7971
KMP Senior notes, 2.65% through 9.00%, due 2016 through 2044 [Member] | Kinder Morgan Energy Partners, L.P. [Member]
Debt Instrument [Line Items]
Senior Notes								$ 18,885	19,485
KMP Senior notes, 7.00% through 8.375%, due 2016 through 2037 [Member] | TGP [Member]
Debt Instrument [Line Items]
Senior Notes								1,240	1,540
KMP 5.95% through 8.625%, due 2017 through 2032 [Member] [Member] | EPNG [Member]
Debt Instrument [Line Items]
Senior Notes								760	1,115
KMP Senior Notes 4.15% and 6.85%, due August 16, 2026 and June 15, 2037 [Member] | Colorado Interstate Gas Company, L.L.C. [Member]
Debt Instrument [Line Items]
Senior Notes								475	475
KMI 6.00% through 6.40% series, due 2018 through 2036 [Member] | Kinder Morgan Finance Company, LLC [Member]
Debt Instrument [Line Items]
Senior Notes								786	786
KMI Senior Note, 5.50%, due 2022 [Member] | Hiland Partners Holding LLC [Member]
Debt Instrument [Line Items]
Senior Notes								$ 0	225
Interest rate, stated percentage		5.50%						5.50%
Repayments of Debt		$ 225
Gain (Loss) on Extinguishment of Debt		3.8
KMI Promissory note 3.967%, due 2017 through 2035 [Member] | EPC Building LLC [Member]
Debt Instrument [Line Items]
Notes Payable								$ 421	433
Interest rate, stated percentage								3.967%
KMI EP Capital Trust I 4.75%, due 2028 [Member] | Capital Trust I [Member]
Debt Instrument [Line Items]
Senior Notes								$ 221	221
Interest rate, stated percentage								4.75%
Preferred Stock, Liquidation Preference Per Share								$ 50
Long-term Debt, Current Maturities								$ 111
KMI $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock [Member] | Kinder Morgan G.P., Inc. [Member]
Debt Instrument [Line Items]
Preferred interest in general partner of KMP								$ 100	100
Preferred stock, par value (in dollars per share)								$ 1,000
Other Miscellaneous Subsidiary Debt [Member] | KMI, KMP and EPB [Member]
Debt Instrument [Line Items]
Notes Payable								$ 277	$ 285
Senior Notes, 3.15%, due January 15, 2023 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Proceeds from Issuance of Debt			$ 1,000
Interest rate, stated percentage			3.15%
KMI Senior Notes, 7.0%, due June 15, 2017 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Interest rate, stated percentage				7.00%					7.00%
Repayments of Debt				$ 786
KMI Senior Notes, 2.0%, due December 1, 2017 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Interest rate, stated percentage	2.00%								2.00%
Repayments of Debt	$ 500
KMP Senior notes, 6.0%, due February 1, 2017 [Member] | Kinder Morgan Energy Partners, L.P. [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage							6.00%		6.00%
Repayments of Debt							$ 600
KMP Senior notes, 7.50%, due April 1, 2017 [Member] | TGP [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage						7.50%			7.50%
Repayments of Debt						$ 300
KMP Senior Notes, 5.95%, due April 15, 2017 [Member] | EPNG [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage					5.95%				5.95%
Repayments of Debt					$ 355
Totem [Member] | El Paso Pipeline Partners, L.P. [Member]
Debt Instrument [Line Items]
Capital Lease Obligations								69
High Plains [Member] | El Paso Pipeline Partners, L.P. [Member]
Debt Instrument [Line Items]
Capital Lease Obligations								$ 88
Totem and High Plains [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage								15.50%
Class P
Debt Instrument [Line Items]
Preferred Stock, Conversion, Shares								0.7197
Debt Instrument, Convertible, Conversion Price								$ 25.18
Euro Member Countries, Euro | Senior Notes [Member]
Debt Instrument [Line Items]
Foreign Currency Exchange Rate, Translation								1.2005	1.0517
Translation Adjustment Functional to Reporting Currency, Increase (Decrease), Gross of Tax								$ 186
Minimum [Member] | KMI Senior Notes,1.50% through 8.25%, due 2016 through 2098 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Interest rate, stated percentage								1.50%
Minimum [Member] | KMP Senior notes, 2.65% through 9.00%, due 2016 through 2044 [Member] | Kinder Morgan Energy Partners, L.P. [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage								2.65%
Minimum [Member] | KMP Senior notes, 7.00% through 8.375%, due 2016 through 2037 [Member] | TGP [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage								7.00%
Minimum [Member] | KMP 5.95% through 8.625%, due 2017 through 2032 [Member] [Member] | EPNG [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage								5.95%
Minimum [Member] | KMP Senior Notes 4.15% and 6.85%, due August 16, 2026 and June 15, 2037 [Member] | Colorado Interstate Gas Company, L.L.C. [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage								4.15%
Minimum [Member] | KMI 6.00% through 6.40% series, due 2018 through 2036 [Member] | Kinder Morgan Finance Company, LLC [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage								6.00%
Maximum [Member] | KMI Senior Notes,1.50% through 8.25%, due 2016 through 2098 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Interest rate, stated percentage								8.05%
Maximum [Member] | KMP Senior notes, 2.65% through 9.00%, due 2016 through 2044 [Member] | Kinder Morgan Energy Partners, L.P. [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage								9.00%
Maximum [Member] | KMP Senior notes, 7.00% through 8.375%, due 2016 through 2037 [Member] | TGP [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage								8.375%
Maximum [Member] | KMP 5.95% through 8.625%, due 2017 through 2032 [Member] [Member] | EPNG [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage								8.625%
Maximum [Member] | KMP Senior Notes 4.15% and 6.85%, due August 16, 2026 and June 15, 2037 [Member] | Colorado Interstate Gas Company, L.L.C. [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage								6.85%
Maximum [Member] | KMI 6.00% through 6.40% series, due 2018 through 2036 [Member] | Kinder Morgan Finance Company, LLC [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage								6.40%
Premium on Debt Repaid [Member] | KMI Senior Note, 5.50%, due 2022 [Member] | Hiland Partners Holding LLC [Member]
Debt Instrument [Line Items]
Gain (Loss) on Extinguishment of Debt		9.3
Purchase Accounting [Member] | KMI Senior Note, 5.50%, due 2022 [Member] | Hiland Partners Holding LLC [Member]
Debt Instrument [Line Items]
Gain (Loss) on Extinguishment of Debt		$ 5.5

Credit Facilities and Restricti

Credit Facilities and Restrictive Covenants (Details) CAD in Millions, $ in Millions	Jun. 16, 2017CAD	Jan. 26, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017CAD	Dec. 31, 2016USD ($)	Nov. 26, 2014USD ($)
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount			$ 107
Remaining borrowing capacity			4,528
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Prior Borrowing Capacity		$ 4,000
Line of Credit Facility, Current Borrowing Capacity		$ 5,000
Commercial Paper [Member]
Line of Credit Facility [Line Items]
Commercial Paper, Current Borrowing Capacity						$ 4,000
Debt Instrument, Term		270 days
Commercial Paper			$ 240
LIBOR Alternate Base Rate [Member] | Minimum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.125%
LIBOR Alternate Base Rate [Member] | Maximum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.00%
For the Period Ended on or prior to December 31, 2017 [Member] | Restrictive covenant [Member]
Line of Credit Facility [Line Items]
Consolidated Leverage Ratio			6.50
For the Period Ended After December 31, 2017 and on or prior to December 31, 2018 [Member] | Restrictive covenant [Member]
Line of Credit Facility [Line Items]
Consolidated Leverage Ratio			6.25
For the Period Ended After December 31,2018 [Member] | Restrictive covenant [Member]
Line of Credit Facility [Line Items]
Consolidated Leverage Ratio			6
London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.125%
London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			2.00%
Federal Funds Rate [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.50%
Eurodollar [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.00%
Kinder Morgan, Inc. | Commercial Paper [Member]
Line of Credit Facility [Line Items]
Commercial Paper			$ 240		$ 0
Kinder Morgan, Inc. | Senior unsecured revolving credit facility due 2019 [Member]
Line of Credit Facility [Line Items]
Long-Term Line of Credit, Amount Outstanding			125
Long-term Line of Credit			125		$ 0
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount			$ 42	CAD 53
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | Revolving Construction Facility [Member]
Line of Credit Facility [Line Items]
Long-term Line of Credit | CAD	CAD 4,000
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Increase in Rates and Fees by .25% upon Fourth Anniversary of the Credit Facility			0.25%
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | Revolving Contingent Credit Facility [Member]
Line of Credit Facility [Line Items]
Long-term Line of Credit | CAD	1,000
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | Revolving Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Long-Term Line of Credit, Amount Outstanding | CAD				0
Remaining borrowing capacity | CAD				CAD 447
Long-term Line of Credit | CAD	CAD 500
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.30%
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | Minimum [Member] | Revolving Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.50%
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.625%
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | Maximum [Member] | Revolving Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			2.50%
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Term	5 years
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | Credit Risk [Member] | Minimum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.50%
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | Credit Risk [Member] | Maximum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.50%
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.50%
Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate			2.50%
Revolving Credit Facility [Member] | Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC [Member]
Line of Credit Facility [Line Items]
Maximum ratio of consolidated total funded debt to consolidated capitalization	70.00%

Debt Current Portion of Debt

Debt Current Portion of Debt - USD ($) $ in Millions	Feb. 01, 2018	Jan. 15, 2018	Dec. 01, 2017	Jun. 15, 2017	Apr. 15, 2017	Apr. 01, 2017	Feb. 01, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Repayments of Debt								$ 11,064	$ 10,060	$ 15,116
KMI Senior Notes, 6.0%, due January 15, 2018 [Member] | Kinder Morgan Finance Company, LLC [Member]
Debt Instrument [Line Items]
Senior Notes, Current								$ 750
Debt Instrument, Interest Rate, Stated Percentage								6.00%
KMI Senior Notes, 7.0%, due February 1, 2018 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Senior Notes, Current								$ 82
Debt Instrument, Interest Rate, Stated Percentage								7.00%
KMP Senior notes, 5.95%, due February 15, 2018 [Member] | Kinder Morgan Energy Partners, L.P. [Member]
Debt Instrument [Line Items]
Senior Notes, Current								$ 975
Debt Instrument, Interest Rate, Stated Percentage								5.95%
KMI Senior Notes, 7.25%, due June 1, 2018 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Senior Notes, Current								$ 477
Debt Instrument, Interest Rate, Stated Percentage								7.25%
KMP Senior notes, 6.0%, due February 1, 2017 [Member] | Kinder Morgan Energy Partners, L.P. [Member]
Debt Instrument [Line Items]
Repayments of Debt							$ 600
Senior Notes, Current									$ 600
Debt Instrument, Interest Rate, Stated Percentage							6.00%		6.00%
KMP Senior notes, 7.50%, due April 1, 2017 [Member] | TGP [Member]
Debt Instrument [Line Items]
Repayments of Debt						$ 300
Senior Notes, Current									$ 300
Debt Instrument, Interest Rate, Stated Percentage						7.50%			7.50%
KMP Senior Notes, 5.95%, due April 15, 2017 [Member] | EPNG [Member]
Debt Instrument [Line Items]
Repayments of Debt					$ 355
Senior Notes, Current									$ 355
Debt Instrument, Interest Rate, Stated Percentage					5.95%				5.95%
KMI Senior Notes, 7.0%, due June 15, 2017 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Repayments of Debt				$ 786
Senior Notes, Current									$ 786
Debt Instrument, Interest Rate, Stated Percentage				7.00%					7.00%
KMI Senior Notes, 2.0%, due December 1, 2017 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Repayments of Debt			$ 500
Senior Notes, Current									$ 500
Debt Instrument, Interest Rate, Stated Percentage			2.00%						2.00%
Subsequent Event [Member] | KMI Senior Notes, 6.0%, due January 15, 2018 [Member] | Kinder Morgan Finance Company, LLC [Member]
Debt Instrument [Line Items]
Repayments of Debt		$ 750
Debt Instrument, Interest Rate, Stated Percentage		6.00%
Subsequent Event [Member] | KMI Senior Notes, 7.0%, due February 1, 2018 [Member] | Kinder Morgan, Inc.
Debt Instrument [Line Items]
Repayments of Debt	$ 82
Debt Instrument, Interest Rate, Stated Percentage	7.00%

Debt Maturties of Debt

Debt Maturties of Debt $ in Millions	Dec. 31, 2017USD ($)
Debt Disclosure [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 2,828
Long-term Debt, Maturities, Repayments of Principal in Year Two	2,820
Long-term Debt, Maturities, Repayments of Principal in Year Three	2,204
Long-term Debt, Maturities, Repayments of Principal in Year Four	2,422
Long-term Debt, Maturities, Repayments of Principal in Year Five	2,558
Long-term Debt, Maturities, Repayments of Principal after Year Five	24,084
Total debt outstanding	$ 36,916

Debt Debt Fair Value Adjustment

Debt Debt Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Amortization Period of Deferred Gain (Loss) on Discontinuation of Fair Value Hedge	16 years
Purchase accounting debt fair value adjustments	$ 719	$ 806
Carrying value adjustment to hedged debt	115	220
Unamortized portion of proceeds received from the early termination of interest rate swap agreements	297	342
Unamortized debt discounts, net	(74)	(80)
Unamortized debt issuance costs	(130)	(139)
Total debt fair value adjustments	$ 927	$ 1,149

Debt Interest Rates, Interest R

Debt Interest Rates, Interest Rate Swaps and Contingent Debt (Details)	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt, Weighted Average Interest Rate	5.02%	4.95%

Share-based Compensation and 85

Share-based Compensation and Employee Benefits Share-based Compensation (Details) - Restricted Stock [Member] - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016
Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Nonemployee Directors[Member] | Class P
Stock Compensation Plan for Non-Employee Directors [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized				250,000
Restricted Stock Incentive Plan Rollforward [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized				250,000
Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Nonemployee Directors[Member] | Class P | Six Month Vesting Period [Member]
Stock Compensation Plan for Non-Employee Directors [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	17,740	31,880	9,580
Stock Issued During Period, Value, Share-based Compensation, Net of Forfeitures	$ 400,000	$ 400,000	$ 401,000
Restricted Stock Incentive Plan Rollforward [Abstract]
Granted (shares)	17,740	31,880	9,580
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P
Stock Compensation Plan for Non-Employee Directors [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized				33,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	3,221,691	2,816,599	1,488,467
Restricted Stock Incentive Plan Rollforward [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized				33,000,000
Outstanding at beginning of period (shares)	9,038,137	7,645,105	7,373,294
Outstanding at beginning of period (value per share)	$ 32.72	$ 37.91	$ 37.63
Granted (shares)	3,221,691	2,816,599	1,488,467
Granted (value per share)	$ 19.52	$ 21.36	$ 38.20
Vested (shares)	(1,501,939)	(1,226,652)	(817,797)
Vested (value per share)	$ 36.67	$ 38.53	$ 35.66
Forfeited (shares)	(239,545)	(196,915)	(398,859)
Forfeited (value per share)	$ 28.34	$ 35.74	$ 38.51
Outstanding at end of period (shares)	10,518,344	9,038,137	7,645,105
Outstanding at end of period (value per share)	$ 28.21	$ 32.72	$ 37.91
Intrinsic value of restricted stock vested during the period	$ 30,000,000	$ 25,000,000	$ 31,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	9,038,137	7,645,105	7,373,294	10,518,344	9,038,137
Restricted Stock or Unit Expense	$ 65,000,000	$ 66,000,000	$ 52,000,000
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	9,000,000	9,000,000	15,000,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options				$ 112,000,000	$ 133,000,000
KML Equity Based Compensation Plans [Abstract]
Restricted Stock or Unit Expense	65,000,000	66,000,000	52,000,000
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	$ 9,000,000	$ 9,000,000	$ 15,000,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options				$ 112,000,000	$ 133,000,000
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P | Year 2018 [Member]
Restricted Stock Incentive Plan Rollforward [Abstract]
Outstanding at end of period (shares)	2,272,019
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	2,272,019			2,272,019
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P | Year 2019 [Member]
Restricted Stock Incentive Plan Rollforward [Abstract]
Outstanding at end of period (shares)	4,268,118
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	4,268,118			4,268,118
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P | Year 2020 [Member]
Restricted Stock Incentive Plan Rollforward [Abstract]
Outstanding at end of period (shares)	3,647,967
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	3,647,967			3,647,967
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P | Year 2021 [Member]
Restricted Stock Incentive Plan Rollforward [Abstract]
Outstanding at end of period (shares)	199,850
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	199,850			199,850
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P | Year 2022 [Member]
Restricted Stock Incentive Plan Rollforward [Abstract]
Outstanding at end of period (shares)	65,928
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	65,928			65,928
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P | Thereafter [Member]
Restricted Stock Incentive Plan Rollforward [Abstract]
Outstanding at end of period (shares)	64,462
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	64,462			64,462
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P | Minimum [Member]
Restricted Stock Incentive Plan Rollforward [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	1 year
Kinder Morgan Inc 2015 Amended and Restated Stock Incentive Plan [Member] | Class P | Maximum [Member]
Restricted Stock Incentive Plan Rollforward [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	10 years
KML Restricted Share Unit Plan for Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted Stock or Unit Expense	$ 1,000,000
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	1,000,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options				$ 8,000,000
KML Equity Based Compensation Plans [Abstract]
Restricted Stock or Unit Expense	1,000,000
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	$ 1,000,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options				$ 8,000,000

Share-based Compensation and 86

Share-based Compensation and Employee Benefits Pensions and Other Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Expected Amortization, Next Fiscal Year				$ 34
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year				(36)
Defined Benefit Plan, Expected Amortization of Prior Service Cost (Credit), Next Fiscal Year				$ (2)
Pension Plan [Member]
Pension Plans [Abstract]
defined benefit plan covered employee percentage				100.00%
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 39	$ 10	$ (35)
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, beginning of period	2,884	2,654
Defined Benefit Plan, Service Cost	40	36	33
Defined Benefit Plan, Interest Cost	88	89	99
Defined Benefit Plan, Actuarial (Gain) Loss	155	127
Defined Benefit Plan, Benefits Paid	(180)	(180)
Defined Benefit Plan, Contributions by Plan Participants	3	3
Defined Benefit Plan, Medicare Part D Subsidy Receipts	0	0
Defined Benefit Plan, Benefit Obligation, Foreign Currency Translation Gain (Loss)	13	4
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment	21	0
Defined Benefit Plan, Benefit Obligation, end of period	2,982	2,884	2,654
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	2,160	2,050
Defined Benefit Plan, Actual (Loss) Return on Plan Assets	292	157
Defined Benefit Plan, Plan Assets, Contributions by Employer	32	8
Defined Benefit Plan, Contributions by Plan Participants	3	3
Defined Benefit Plan, Medicare Part D Subsidy Receipts	0	0
Defined Benefit Plan, Benefits Paid	(180)	(180)
Defined Benefit Plan, Plan Assets, Foreign Currency Translation Gain (Loss)	10	3
Defined Benefit Plan, Plan Assets, Payment for Settlement	(21)	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	2,296	2,160	2,050
Defined Benefit Plan, Funded (Unfunded) Status of Plan				$ (686)	$ (724)
Components of Funded Status [Abstract]
Assets for Plan Benefits, Defined Benefit Plan				0	0
Liability, Defined Benefit Plan, Current				0	0
Liability, Defined Benefit Plan, Noncurrent				(686)	(724)
Defined Benefit Plan, Funded (Unfunded) Status of Plan				(686)	(724)
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax				(635)	(682)
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax				(4)	(5)
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax				(639)	(687)
Defined Benefit Plan, Accumulated Benefit Obligation				2,840	2,834
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	2,160	2,050	$ 2,050	2,296	2,160	$ 2,050
Investments Net Asset Value				1,281	$ 1,128
Changes in Pension and OPEB Assets [Abstract]
Defined Benefit Plan, Plan Assets, Level 3 Reconciliation, Actual Return (Loss)	$ 292	$ 157
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, 2018				244
Defined Benefit Plan, Expected Future Benefit Payments, 2019				241
Defined Benefit Plan, Expected Future Benefit Payments, 2020				242
Defined Benefit Plan, Expected Future Benefit Payments, 2021				232
Defined Benefit Plan, Expected Future Benefit Payments, 2022				230
Defined Benefit Plan, Expected Future Benefit Payments, 2023-2027				$ 1,029
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate				3.56%	3.83%	4.05%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase				3.53%	3.52%	3.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	7.07%	7.31%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.52%	3.51%	4.50%
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income [Abstract]
Defined Benefit Plan, Service Cost	$ 40	$ 36	$ 33
Defined Benefit Plan, Interest Cost	88	89	99
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(147)	(151)	(172)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	1	1	0
Defined Benefit Plan, Amortization of Net Actuarial Loss (Gain)	52	35	5
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	(5)	0	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	39	10	(35)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	17	116	267
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	0	0	0
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, before Tax	(64)	(34)	(5)
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax	(1)	0	0
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax	0	1	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax	(48)	83	262
Total Net benefit cost and other comprehensive income (loss) recognized	(9)	93	227
Pension Plan [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Investments Net Asset Value				$ 895	$ 829
Pension Plan [Member] | Private Investment Funds [Member]
Plan Assets [Abstract]
Investments Net Asset Value				337	290
Pension Plan [Member] | Limited Partnership [Member]
Plan Assets [Abstract]
Investments Net Asset Value				49	9
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	490
Defined Benefit Plan, Fair Value of Plan Assets, end of year	529	490
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	490	490		529	490
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	10
Defined Benefit Plan, Fair Value of Plan Assets, end of year	6	10
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	10	10		6	10
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Short-term Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual funds investment type [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	197
Defined Benefit Plan, Fair Value of Plan Assets, end of year	245	197
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	197	197		245	197
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	283
Defined Benefit Plan, Fair Value of Plan Assets, end of year	278	283
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	283	283		278	283
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Guaranteed Investment Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Derivatives [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Class P | Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	126
Defined Benefit Plan, Fair Value of Plan Assets, end of year	110	126
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	126	126		110	126
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	526
Defined Benefit Plan, Fair Value of Plan Assets, end of year	486	526
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	526	526		486	526
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	100
Defined Benefit Plan, Fair Value of Plan Assets, end of year	65	100
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	100	100		65	100
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual funds investment type [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	428
Defined Benefit Plan, Fair Value of Plan Assets, end of year	416	428
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	428	428		416	428
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Guaranteed Investment Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Derivatives [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	(2)
Defined Benefit Plan, Fair Value of Plan Assets, end of year	5	(2)
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	(2)	(2)		5	(2)
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	16
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	16
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16	16		0	16
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Short-term Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Mutual funds investment type [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Guaranteed Investment Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	16	15
Defined Benefit Plan, Actual (Loss) Return on Plan Assets	0	1
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	16	15
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16	15	$ 15	0	16	$ 15
Changes in Pension and OPEB Assets [Abstract]
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3	0	0
Defined Benefit Plan, Plan Assets, Level 3 Reconciliation, Actual Return (Loss)	0	1
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Purchases, Sales, and Settlements	(16)	0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Derivatives [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	$ 0	$ 0		$ 0	$ 0
Pension Plan [Member] | Benefit obligation [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.83%	4.05%	3.66%
Pension Plan [Member] | Discount rate for interest on benefit obligations [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.09%	3.24%	3.66%
Pension Plan [Member] | Discount rate for service cost [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.88%	4.15%	3.66%
Pension Plan [Member] | Discount rate for interest on service cost [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.24%	3.50%	3.66%
Pension Plan [Member] | Equity Securities [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				64.00%	61.00%
Pension Plan [Member] | Equity Securities [Member] | Private Investment Funds [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				48.00%	46.00%
Pension Plan [Member] | Fixed Income Securities [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				36.00%	39.00%
Pension Plan [Member] | Fixed Income Securities [Member] | Private Investment Funds [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				52.00%	54.00%
Pension Plan [Member] | Domestic Plan [Member]
Pension Plans [Abstract]
Defined Benefit Plan,Vesting Period	3 years
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Fiscal Year				$ 30
Pension Plan [Member] | Domestic Plan [Member] | Minimum [Member] | Cash [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				0.00%
Pension Plan [Member] | Domestic Plan [Member] | Minimum [Member] | Equity Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				34.00%
Pension Plan [Member] | Domestic Plan [Member] | Minimum [Member] | Fixed Income Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				37.00%
Pension Plan [Member] | Domestic Plan [Member] | Minimum [Member] | Alternative Investments [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				0.00%
Pension Plan [Member] | Domestic Plan [Member] | Maximum [Member] | Cash [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				5.00%
Pension Plan [Member] | Domestic Plan [Member] | Maximum [Member] | Equity Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				59.00%
Pension Plan [Member] | Domestic Plan [Member] | Maximum [Member] | Fixed Income Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				57.00%
Pension Plan [Member] | Domestic Plan [Member] | Maximum [Member] | Alternative Investments [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				2.00%
Pension Plan [Member] | Foreign Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Other Change	$ 0	$ 151
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Other	0	119
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Fiscal Year				$ 10
Pension Plan [Member] | Foreign Plan [Member] | Equity Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				55.00%
Pension Plan [Member] | Foreign Plan [Member] | Fixed Income Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				45.00%
Other Pension, Postretirement and Supplemental Plans [Member] | Foreign Plan [Member]
Pension Plans [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)			$ 12
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)			12
Other Postretirement Benefits Plan [Member]
Pension Plans [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	(14)	(5)	(4)
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, beginning of period	473	509
Defined Benefit Plan, Service Cost	1	1	0
Defined Benefit Plan, Interest Cost	13	16	21
Defined Benefit Plan, Actuarial (Gain) Loss	(16)	(42)
Defined Benefit Plan, Benefits Paid	(38)	(41)
Defined Benefit Plan, Contributions by Plan Participants	2	2
Defined Benefit Plan, Medicare Part D Subsidy Receipts	1	1
Defined Benefit Plan, Benefit Obligation, Foreign Currency Translation Gain (Loss)	1	1
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment	0	0
Defined Benefit Plan, Benefit Obligation, end of period	425	473	509
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	332	325
Defined Benefit Plan, Actual (Loss) Return on Plan Assets	29	29
Defined Benefit Plan, Plan Assets, Contributions by Employer	9	16
Defined Benefit Plan, Contributions by Plan Participants	2	2
Defined Benefit Plan, Medicare Part D Subsidy Receipts	1	1
Defined Benefit Plan, Benefits Paid	(38)	(41)
Defined Benefit Plan, Plan Assets, Foreign Currency Translation Gain (Loss)	0	0
Defined Benefit Plan, Plan Assets, Payment for Settlement	0	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	335	332	325
Defined Benefit Plan, Funded (Unfunded) Status of Plan				$ (90)	$ (141)
Components of Funded Status [Abstract]
Assets for Plan Benefits, Defined Benefit Plan				198	153
Liability, Defined Benefit Plan, Current				(15)	(16)
Liability, Defined Benefit Plan, Noncurrent				(273)	(278)
Defined Benefit Plan, Funded (Unfunded) Status of Plan				(90)	(141)
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), Gain (Loss), before Tax				88	69
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, Prior Service Cost (Credit), before Tax				17	18
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax				105	87
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Accumulated Benefit Obligation				373	415
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Fair Value of Plan Assets				84	121
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	332	325	$ 325	335	332	$ 325
Investments Net Asset Value				212	$ 201
Changes in Pension and OPEB Assets [Abstract]
Defined Benefit Plan, Plan Assets, Level 3 Reconciliation, Actual Return (Loss)	$ 29	$ 29
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, 2018				36
Defined Benefit Plan, Expected Future Benefit Payments, 2019				36
Defined Benefit Plan, Expected Future Benefit Payments, 2020				35
Defined Benefit Plan, Expected Future Benefit Payments, 2021				34
Defined Benefit Plan, Expected Future Benefit Payments, 2022				33
Defined Benefit Plan, Expected Future Benefit Payments, 2023-2027				$ 149
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate				3.48%	3.69%	3.91%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	6.84%	7.07%	7.08%
Unrelated Business Income Tax Rate	21.00%	21.00%	21.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year				7.71%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate				4.54%
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	$ 1	$ 1
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	22	27
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	(1)	(1)
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	(19)	(23)
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income [Abstract]
Defined Benefit Plan, Service Cost	1	1	$ 0
Defined Benefit Plan, Interest Cost	13	16	21
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(19)	(19)	(23)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(3)	(3)	(3)
Defined Benefit Plan, Amortization of Net Actuarial Loss (Gain)	(6)	0	1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	0	0	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	(14)	(5)	(4)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	(25)	(48)	(49)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	0	0	0
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, before Tax	6	0	(1)
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax	1	1	1
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax	0	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax	(18)	(47)	(49)
Total Net benefit cost and other comprehensive income (loss) recognized	(32)	(52)	(53)
Other Postretirement Benefits Plan [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Investments Net Asset Value				$ 68	$ 68
Other Postretirement Benefits Plan [Member] | Fixed Income Trusts [Member]
Plan Assets [Abstract]
Investments Net Asset Value				66	64
Other Postretirement Benefits Plan [Member] | Limited Partnership [Member]
Plan Assets [Abstract]
Investments Net Asset Value				78	69
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	69
Defined Benefit Plan, Fair Value of Plan Assets, end of year	67	69
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	69	69		67	69
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Short-term Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual funds investment type [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	1
Defined Benefit Plan, Fair Value of Plan Assets, end of year	1	1
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1	1		1	1
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	11
Defined Benefit Plan, Fair Value of Plan Assets, end of year	16	11
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	11	11		16	11
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Master Limited Partnerships [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	57
Defined Benefit Plan, Fair Value of Plan Assets, end of year	50	57
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	57	57		50	57
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Guaranteed Investment Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	15
Defined Benefit Plan, Fair Value of Plan Assets, end of year	7	15
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	15	15		7	15
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	15
Defined Benefit Plan, Fair Value of Plan Assets, end of year	7	15
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	15	15		7	15
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual funds investment type [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Master Limited Partnerships [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Guaranteed Investment Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	47
Defined Benefit Plan, Fair Value of Plan Assets, end of year	49	47
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	47	47		49	47
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Short-term Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Mutual funds investment type [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Master Limited Partnerships [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	0
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	0	0		0	0
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Guaranteed Investment Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	47	49
Defined Benefit Plan, Actual (Loss) Return on Plan Assets	5	(2)
Defined Benefit Plan, Fair Value of Plan Assets, end of year	49	47	49
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	47	49	$ 49	49	47	$ 49
Changes in Pension and OPEB Assets [Abstract]
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Assets Transferred into (out of) Level 3	0	0
Defined Benefit Plan, Plan Assets, Level 3 Reconciliation, Actual Return (Loss)	5	(2)
Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Purchases, Sales, and Settlements	(3)	$ 0
Other Postretirement Benefits Plan [Member] | Each of Next Five Years [Member]
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Medicare prescription drug, improvement and modernization act, annual subsidy	2
Other Postretirement Benefits Plan [Member] | Five Fiscal Years Thereafter [Member]
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Medicare prescription drug, improvement and modernization act, annual subsidy	$ 13
Other Postretirement Benefits Plan [Member] | Benefit obligation [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.69%	3.91%	3.56%
Other Postretirement Benefits Plan [Member] | Discount rate for interest on benefit obligations [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.05%	3.18%	3.56%
Other Postretirement Benefits Plan [Member] | Discount rate for service cost [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.15%	4.36%	3.56%
Other Postretirement Benefits Plan [Member] | Discount rate for interest on service cost [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.95%	4.17%	3.56%
Other Postretirement Benefits Plan [Member] | Other Affiliates [Member]
Pension Plans [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ (4)	$ (4)
Components of Funded Status [Abstract]
Assets for Plan Benefits, Defined Benefit Plan				$ 33	$ 29
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	(4)	(4)
Other Postretirement Benefits Plan [Member] | Equity Securities [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				71.00%	72.00%
Other Postretirement Benefits Plan [Member] | Fixed Income Securities [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				29.00%	28.00%
Other Postretirement Benefits Plan [Member] | Domestic Plan [Member]
Other Postretirement Benefit Plans [Abstract]
Purchase of Medical Coverage through Medicare Exchange Participant, Age				65
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Fiscal Year				$ 7
Other Postretirement Benefits Plan [Member] | Domestic Plan [Member] | Minimum [Member] | Cash [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				0.00%
Other Postretirement Benefits Plan [Member] | Domestic Plan [Member] | Minimum [Member] | Equity Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				15.00%
Other Postretirement Benefits Plan [Member] | Domestic Plan [Member] | Minimum [Member] | Master Limited Partnerships [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				13.00%
Other Postretirement Benefits Plan [Member] | Domestic Plan [Member] | Minimum [Member] | Fixed Income Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				15.00%
Other Postretirement Benefits Plan [Member] | Domestic Plan [Member] | Maximum [Member] | Cash [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				20.00%
Other Postretirement Benefits Plan [Member] | Domestic Plan [Member] | Maximum [Member] | Equity Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				55.00%
Other Postretirement Benefits Plan [Member] | Domestic Plan [Member] | Maximum [Member] | Master Limited Partnerships [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				39.00%
Other Postretirement Benefits Plan [Member] | Domestic Plan [Member] | Maximum [Member] | Fixed Income Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				47.00%
Other Postretirement Benefits Plan [Member] | Foreign Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Other Change	(12)	26
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Other	$ 0	0
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Fiscal Year				$ 1
Closed to New Participants [Member] | Pension Plan [Member] | Foreign Plan [Member] | Equity Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				10.00%
Closed to New Participants [Member] | Pension Plan [Member] | Foreign Plan [Member] | Fixed Income Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				90.00%
Savings plan - defined contribution plan [Member]
Savings Plan [Abstract]
Defined Contribution Plan, Cost			$ 46
Savings plan - defined contribution plan [Member]
Savings Plan [Abstract]
Defined Contribution Plan, Employer Matching Contribution, Percent	5.00%
Defined Contribution Plan, Cost	$ 47	47
Kinder Morgan, Inc. | Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Debt Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	1
Defined Benefit Plan, Fair Value of Plan Assets, end of year		1
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1	1			$ 1
Kinder Morgan, Inc. | Pension Plan [Member] | Domestic Plan [Member] | Minimum [Member] | Company Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				0.00%
Kinder Morgan, Inc. | Pension Plan [Member] | Domestic Plan [Member] | Maximum [Member] | Company Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage				10.00%
Kinder Morgan, Inc. | Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Class P | Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	2
Defined Benefit Plan, Fair Value of Plan Assets, end of year	2	2
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	2	2		$ 2	2
Within Fair Value Hierarchy [Member] | Pension Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	1,032
Defined Benefit Plan, Fair Value of Plan Assets, end of year	1,015	1,032
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,032	1,032		1,015	1,032
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	10
Defined Benefit Plan, Fair Value of Plan Assets, end of year	6	10
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	10	10		6	10
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Short-term Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	100
Defined Benefit Plan, Fair Value of Plan Assets, end of year	65	100
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	100	100		65	100
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Mutual funds investment type [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	197
Defined Benefit Plan, Fair Value of Plan Assets, end of year	245	197
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	197	197		245	197
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	283
Defined Benefit Plan, Fair Value of Plan Assets, end of year	278	283
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	283	283		278	283
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Fixed Income Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	428
Defined Benefit Plan, Fair Value of Plan Assets, end of year	416	428
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	428	428		416	428
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Guaranteed Investment Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	16
Defined Benefit Plan, Fair Value of Plan Assets, end of year	0	16
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16	16		0	16
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Derivatives [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	(2)
Defined Benefit Plan, Fair Value of Plan Assets, end of year	5	(2)
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	(2)	(2)		5	(2)
Within Fair Value Hierarchy [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	131
Defined Benefit Plan, Fair Value of Plan Assets, end of year	123	131
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	131	131		123	131
Within Fair Value Hierarchy [Member] | Other Postretirement Benefits Plan [Member] | Short-term Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	15
Defined Benefit Plan, Fair Value of Plan Assets, end of year	7	15
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	15	15		7	15
Within Fair Value Hierarchy [Member] | Other Postretirement Benefits Plan [Member] | Mutual funds investment type [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	1
Defined Benefit Plan, Fair Value of Plan Assets, end of year	1	1
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1	1		1	1
Within Fair Value Hierarchy [Member] | Other Postretirement Benefits Plan [Member] | Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	11
Defined Benefit Plan, Fair Value of Plan Assets, end of year	16	11
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	11	11		16	11
Within Fair Value Hierarchy [Member] | Other Postretirement Benefits Plan [Member] | Master Limited Partnerships [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	57
Defined Benefit Plan, Fair Value of Plan Assets, end of year	50	57
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	57	57		50	57
Within Fair Value Hierarchy [Member] | Other Postretirement Benefits Plan [Member] | Guaranteed Investment Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	47
Defined Benefit Plan, Fair Value of Plan Assets, end of year	49	47
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	$ 47	$ 47		$ 49	$ 47

Share-based Compensation and 87

Share-based Compensation and Employee Benefits Other Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Multiemployer Plan, Individually Insignificant Multiemployer Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 8	$ 8	$ 10

Common Equity (Details)

Common Equity (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 17, 2018	Feb. 08, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	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			$ 250
Issuances of common shares					$ 3,870
Dividends Per Common Share Declared for the Period			$ 0.500	$ 0.500	$ 1.605
Payments for Repurchase of Warrants					$ 12
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			0.50	0.50	$ 1.605
Per common share cash dividend paid in the period			$ 0.50	$ 0.50	$ 1.93
Subsequent Event [Member]
Class of Stock [Line Items]
Stock Repurchased During Period, Value		$ 250
Dividends Per Common Share Declared for the Period	$ 0.125
Equity distribution agreement [Member] | Class P
Class of Stock [Line Items]
Value of Stock Available for Sale Under Equity Distribution Agreement										$ 5,000
Stock Sold During the Period, Shares					102,614,508
Share issued (in shares)					102,614,508
Issuances of common shares					$ 3,900
Common stock
Class of Stock [Line Items]
Stock Repurchased During Period, Shares			14,000,000
Share issued (in shares)					103,000,000
Issuances of common shares					$ 1
Common stock | Subsequent Event [Member]
Class of Stock [Line Items]
Stock Repurchased During Period, Shares		13,000,000

Stockholders' Equity Mandatory

Stockholders' Equity Mandatory Convertible Preferred Stock (Details) $ / shares in Units, $ in Millions	Oct. 18, 2017$ / shares	Jul. 19, 2017$ / shares	Apr. 19, 2017$ / shares	Jan. 18, 2017$ / shares	Oct. 30, 2015USD ($)$ / sharesshares	Dec. 31, 2017$ / sharesshares	Dec. 31, 2016$ / shares
Class of Stock [Line Items]
Depositary Share Offering | shares					32,000,000
Amount of Interest Each Depositary Share has in a 9.75% Series A Mandatory Convertible Preferred Share					0.0005
Preferred Stock, Dividend Rate, Percentage						9.75%	9.75%
Preferred Stock, Liquidation Preference Per Share						$ 1,000	$ 1,000
Depositary Shares, Liquidation Preference Per Share					$ 50
Proceeds from Depositary Share Offering | $					$ 1,541
Number of days in Average Trading Period						20
Greater Than Applicable Market Value of Common Stock						$ 32.38
Less Than Applicable Market Value of Common Stock						$ 27.56
9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference
Class of Stock [Line Items]
Issuances of common shares | shares					1,600,000
Preferred Stock, Dividend Rate, Percentage					9.75%	9.75%
Preferred Stock, Liquidation Preference Per Share					$ 1,000
Dividends, Preferred Stock	$ 24.375	$ 24.375	$ 24.375	$ 24.375		$ 24.375
Depositary Stock, Dividends Per Share, Declared						$ 1.21875
Minimum [Member]
Class of Stock [Line Items]
Depositary Shares, Shares Issued Upon Conversion | shares						1.5440
Applicable Market Value of Common Stock						$ 27.56
Minimum [Member] | 9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference
Class of Stock [Line Items]
Convertible Preferred Stock, Shares Issued upon Conversion | shares						30.8800
Maximum [Member]
Class of Stock [Line Items]
Depositary Shares, Shares Issued Upon Conversion | shares						1.8142
Applicable Market Value of Common Stock						$ 32.38
Maximum [Member] | 9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference
Class of Stock [Line Items]
Convertible Preferred Stock, Shares Issued upon Conversion | shares						36.2840

Stockholders' Equity Noncontrol

Stockholders' Equity Noncontrolling Interests (Details) CAD / shares in Units, $ / shares in Units, CAD in Millions, $ in Millions	Jan. 17, 2018CAD / shares	Dec. 08, 2017USD ($)shares	Dec. 08, 2017CADCAD / sharesshares	Aug. 15, 2017USD ($)shares	Aug. 15, 2017CADCAD / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2017CADCAD / sharesshares	May 30, 2017shares	Dec. 31, 2016shares
Preferred Stock, Shares Issued | shares						1,600,000	1,600,000		1,600,000
Kinder Morgan Canada Limited [Member]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners								30.00%
Per restricted voting share declared for the period(b)							CAD 0.3821
Per restricted voting share paid in the period | (per share)						$ 0.1739	CAD 0.2196
Cash distributions paid in the period to the public						$ 13	CAD 16
Share distributions paid in the period to the public under KML’s DRIP | shares						418,989	418,989
Restricted Voting Shares in Public Offering [Member] | Kinder Morgan Canada Limited [Member]
Shares, Issued | shares								102,942,000
Restricted Voting Shares [Member] | Kinder Morgan Canada Limited [Member]
Total value of distributions paid in the period						$ 18	CAD 23
Cumulative Redeemable Minimum Rate Reset Preferred Shares, Series 1 [Member] | Kinder Morgan Canada Limited [Member]
Preferred Stock, Shares Issued | shares				12,000,000	12,000,000
Preferred Stock, Series 1 Offering Price, Per Share					CAD 25
Proceeds from Issuance of Preferred Stock and Preference Stock				$ 235	CAD 300
Net Proceeds from issuance of Preferred Stock						$ 230	CAD 293
Preferred Shares, Annualized Dividend Per Share							CAD 1.3125
Per Series 1 Preferred Share paid in the period | (per share)						$ 0.2624	CAD 0.3308
Cash distributions paid in the period to the public						$ 3	CAD 4
Cumulative Redeemable Minimum Rate Reset Preferred Shares, Series 3 [Member] | Kinder Morgan Canada Limited [Member]
Preferred Stock, Shares Issued | shares		10,000,000	10,000,000
Proceeds from Issuance of Preferred Stock and Preference Stock		$ 195	CAD 250
Preferred Stock, Series 3 Offering Price, Per Share			CAD 25
Net Proceeds from issuance of Preferred Stock						$ 189	CAD 243
Preferred Shares, Annualized Dividend Per Share							CAD 1.3000
Minimum [Member] | Kinder Morgan Canada Limited [Member]
Market Discount for the Dividend Paid on Restricted Voting Shares						0.00%	0.00%
Maximum [Member] | Kinder Morgan Canada Limited [Member]
Market Discount for the Dividend Paid on Restricted Voting Shares						5.00%	5.00%
Subsequent Event [Member] | Cumulative Redeemable Minimum Rate Reset Preferred Shares, Series 1 [Member] | Kinder Morgan Canada Limited [Member]
Preferred Stock, Dividends Per Share, Declared	CAD 0.328125
Subsequent Event [Member] | Cumulative Redeemable Minimum Rate Reset Preferred Shares, Series 3 [Member] | Kinder Morgan Canada Limited [Member]
Preferred Stock, Dividends Per Share, Declared	CAD 0.22082

Related Party Transactions Affi

Related Party Transactions Affiliated Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
RELATED PARTY ASSETS
Other current assets	$ 238	$ 337
Deferred charges and other assets	1,582	1,522
RELATED PARTY LIABILITIES [Abstract]
Other current liabilities	1,101	1,085
RELATED PARTY REVENUES [Abstract]
Services	7,901	8,146	$ 8,290
Product sales and other	2,751	2,458	3,274
Total Revenues	13,705	13,058	14,403
RELATED PARTY COST OF SALES [Abstract]
Costs of sales	4,345	3,429	4,059
Other operating expenses	12	386	2,066
Affiliated Entity [Member]
RELATED PARTY ASSETS
Accounts receivable, net	34	37
Other current assets	8	0
Deferred charges and other assets	23	10
Total Assets	65	47
RELATED PARTY LIABILITIES [Abstract]
Current portion of debt	6	6
Accounts payable	18	28
Other current liabilities	4	9
Long-term debt	155	161
Other long-term liabilities and deferred credits	35	29
Total Liabilities	218	233
RELATED PARTY REVENUES [Abstract]
Services	73	71	72
Product sales and other	89	71	71
Total Revenues	162	142	143
RELATED PARTY COST OF SALES [Abstract]
Costs of sales	20	38	60
Other operating expenses	$ 100	$ 75	$ 55

Related Party Transactions Note

Related Party Transactions Notes Receivable (Details)	Dec. 31, 2017
Midcontinent Express Pipeline LLC
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, 2017
MEP
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	50.00%

Commitments and Contingent Li94

Commitments and Contingent Liabilities Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 118
Operating Leases, Future Minimum Payments, Due in Two Years	106
Operating Leases, Future Minimum Payments, Due in Three Years	81
Operating Leases, Future Minimum Payments, Due in Four Years	62
Operating Leases, Future Minimum Payments, Due in Five Years	55
Operating Leases, Future Minimum Payments, Due Thereafter	300
Operating Leases, Future Minimum Payments Due	722
Operating Leases, Rent Expense	$ 140	$ 138	$ 143
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	41 years

Commitments and Contingent Li95

Commitments and Contingent Liabilities Contingent Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 1,070	$ 1,179
Cortez Pipeline Company
Guarantor Obligations [Line Items]
Equity Method Investment, Ownership Percentage	52.98%
Cortez Expansion Capital Corp [Member]
Guarantor Obligations [Line Items]
Percentage of Debt Guaranteed	100.00%
Revolving Credit Facility [Member] | Cortez Expansion Capital Corp [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 50
Notes Payable to Banks [Member] | Cortez Expansion Capital Corp [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	120
Partnership Interest [Member] | Revolving Credit Facility [Member] | Cortez Pipeline Company
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	50
Partnership Interest [Member] | Senior Notes [Member] | Cortez Pipeline Company
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 100
Debt Securities [Member] | Cortez Pipeline Company
Guarantor Obligations [Line Items]
Equity Method Investment, Ownership Percentage	50.00%

Energy Commodity Price Risk Man

Energy Commodity Price Risk Managment (Details) - Energy commodity derivative contracts(a)	Dec. 31, 2017MMBblsBcf
Designated as Hedging Instrument [Member] | Crude Oil Fixed Price [Member]
Derivative [Line Items]
Net Open Position Long/(Short) of Outstanding Commodity Forward Contracts to Hedge our Forecasted Energy Commodity Purchases and Sales	(21)
Designated as Hedging Instrument [Member] | Crude Oil Basis [Member]
Derivative [Line Items]
Net Open Position Long/(Short) of Outstanding Commodity Forward Contracts to Hedge our Forecasted Energy Commodity Purchases and Sales	(7.2)
Designated as Hedging Instrument [Member] | Natural Gas Fixed Price [Member]
Derivative [Line Items]
Net Open Position Long/(Short) of Outstanding Commodity Forward Contracts to Hedge our Forecasted Energy Commodity Purchases and Sales | Bcf	(46.4)
Designated as Hedging Instrument [Member] | Natural Gas Basis [Member]
Derivative [Line Items]
Net Open Position Long/(Short) of Outstanding Commodity Forward Contracts to Hedge our Forecasted Energy Commodity Purchases and Sales | Bcf	(21.7)
Not Designated as Hedging Instrument [Member] | Crude Oil Fixed Price [Member]
Derivative [Line Items]
Net Open Position Long/(Short) of Outstanding Commodity Forward Contracts to Hedge our Forecasted Energy Commodity Purchases and Sales	(1.9)
Not Designated as Hedging Instrument [Member] | Crude Oil Basis [Member]
Derivative [Line Items]
Net Open Position Long/(Short) of Outstanding Commodity Forward Contracts to Hedge our Forecasted Energy Commodity Purchases and Sales	(1.2)
Not Designated as Hedging Instrument [Member] | Natural Gas Fixed Price [Member]
Derivative [Line Items]
Net Open Position Long/(Short) of Outstanding Commodity Forward Contracts to Hedge our Forecasted Energy Commodity Purchases and Sales | Bcf	(9)
Not Designated as Hedging Instrument [Member] | Natural Gas Basis [Member]
Derivative [Line Items]
Net Open Position Long/(Short) of Outstanding Commodity Forward Contracts to Hedge our Forecasted Energy Commodity Purchases and Sales | Bcf	(23.1)
Not Designated as Hedging Instrument [Member] | NGL and other fixed price
Derivative [Line Items]
Net Open Position Long/(Short) of Outstanding Commodity Forward Contracts to Hedge our Forecasted Energy Commodity Purchases and Sales	(4.1)

Interest Rate Risk Managment (D

Interest Rate Risk Managment (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value Hedging [Member] | Interest rate swap agreements
Derivative [Line Items]
Derivative, Notional Amount	$ 9,575	$ 9,775

Risk Management Foreign Currenc

Risk Management Foreign Currency Risk Management (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Derivative [Line Items]
Cross-currency Swap Agreements	$ 1,358
KMI 1.50% Senior Notes Due 2022 [Member]
Derivative [Line Items]
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%
Currency Swap [Member] | KMI 2.25% Senior Notes Due 2027 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.67%

Risk Management Fair Value of D

Risk Management Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	$ 450	$ 471
Liability derivatives	(148)	(169)
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a)
Derivatives, Fair Value [Line Items]
Asset derivatives	79	171
Liability derivatives	(77)	(81)
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	65	101
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(53)	(57)
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	14	70
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(24)	(24)
Designated as Hedging Instrument [Member] | Interest rate swap agreements
Derivatives, Fair Value [Line Items]
Asset derivatives	205	300
Liability derivatives	(65)	(57)
Designated as Hedging Instrument [Member] | Interest rate swap agreements | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	41	94
Designated as Hedging Instrument [Member] | Interest rate swap agreements | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(3)	0
Designated as Hedging Instrument [Member] | Interest rate swap agreements | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	164	206
Designated as Hedging Instrument [Member] | Interest rate swap agreements | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(62)	(57)
Designated as Hedging Instrument [Member] | Currency Swap [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	166	0
Liability derivatives	(6)	(31)
Designated as Hedging Instrument [Member] | Currency Swap [Member] | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Designated as Hedging Instrument [Member] | Currency Swap [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(6)	(7)
Designated as Hedging Instrument [Member] | Currency Swap [Member] | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	166	0
Designated as Hedging Instrument [Member] | Currency Swap [Member] | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	0	(24)
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	458	474
Liability derivatives	(172)	(199)
Not Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	8	3
Not Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(22)	(29)
Not Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Not Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(2)	(1)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	8	3
Liability derivatives	$ (24)	$ (30)

Effect of Derivative Contracts

Effect of Derivative Contracts on the Income Statement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Interest rate swap agreements | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 0	$ 63	$ (15)
Energy commodity derivative contracts(a)
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	4	30	176
Derivative, Gain (Loss) on Derivative	57	73	31
Energy commodity derivative contracts(a) | Revenues—Natural gas sales
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	20	(10)	17
Energy commodity derivative contracts(a) | Revenues—Product sales and other
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(16)	(26)	176
Energy commodity derivative contracts(a) | Costs of sales
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	3	(2)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Loss to be reclassified within twelve months	1
Designated as Hedging Instrument [Member] | Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	145	(104)	164
Designated as Hedging Instrument [Member] | Operating Income (Loss) [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/(loss)reclassified fromAccumulated OCIinto income(effective portion)	171	116	272
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	11	(12)	2
Designated as Hedging Instrument [Member] | Interest rate swap agreements | Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	0	(2)	(4)
Designated as Hedging Instrument [Member] | Interest rate swap agreements | Interest Expense [Member] | Fair Value Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(103)	(180)	25
Designated as Hedging Instrument [Member] | Interest rate swap agreements | Interest Expense [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/(loss)reclassified fromAccumulated OCIinto income(effective portion)	(3)	(3)	(3)
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	0
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member] | Fair Value Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	105	160	(33)
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	24	(115)	201
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Revenues—Natural gas sales | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/(loss)reclassified fromAccumulated OCIinto income(effective portion)	12	15	54
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	0
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Revenues—Product sales and other | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/(loss)reclassified fromAccumulated OCIinto income(effective portion)	35	148	236
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	11	(12)	2
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Costs of sales | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/(loss)reclassified fromAccumulated OCIinto income(effective portion)	9	(17)	(15)
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	0
Designated as Hedging Instrument [Member] | Currency Swap [Member] | Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	121	13	(33)
Designated as Hedging Instrument [Member] | Other Credit Derivatives [Member] | Other Expense [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/(loss)reclassified fromAccumulated OCIinto income(effective portion)	118	(27)	0
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 0	$ 0	$ 0

Credit Risks (Details)

Credit Risks (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Credit Derivatives [Line Items]
Letters of Credit Outstanding, Amount	$ 107
Energy commodity derivative contracts(a)
Credit Derivatives [Line Items]
Letters of Credit Outstanding, Amount	0
Initial Margin Requirements	13
Variation Margin Requirements	12
Contract and Over the Counter [Member] | Energy commodity derivative contracts(a)
Credit Derivatives [Line Items]
Derivative, Collateral, Right to Reclaim Cash	1	$ 37
One notch credit downgrade [Member] | Energy commodity derivative contracts(a)
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	31
Two notch credit downgrade [Member] | Contract and Over the Counter [Member] | Energy commodity derivative contracts(a)
Credit Derivatives [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 0

Risk Management Risk Management

Risk Management Risk Management Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ (1)	$ 219	$ 327
Accumulated Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Net of Tax	(288)	(322)	(108)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(372)	(358)	(236)
Accumulated other comprehensive loss	(661)	(461)	(17)
Other Comprehensive Income Unrealized Gain Loss On Derivatives Arising During Period Net Of Tax Portion Attributable To Parent	145	(104)	164
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax, Before Reclassifications, Portion Attributable to Parent	55	34	(214)
Other Comprehensive (Income) Loss, Defined Benefit Plan, before Reclassification Adjustment, after Tax	40	(14)	(122)
OCI, before Reclassifications, Net of Tax, Attributable to Parent	240	(84)	(172)
Other Comprehensive Income Reclassification Adjustment On Derivatives Included In Net Income Net Of Tax Portion Attributable To Parent	(171)	(116)	(272)
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Reclassification Adjustment from AOCI, Realized upon Sale or Liquidation, Net of Tax	0	0	0
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretiremen Benefit Plans Net Of Tax Portion Attributable To Parent	0	0	0
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	(171)	(116)	(272)
Other Comprehensive Income Reclassification Adjustment On Derivatives Included In Net Income Net Of Tax Portion Attributable To Parent, Due to IPO	0
Other Comprehensive Income, Foreign Currency Translation Adjustment-IPO	44
Other Comprehensive Income(Loss), Defined Benefit Plan, Reclassification Adjustment from AOCI, due to IPO, net of tax	7
Other Comprehensive Income, KML IPO	51
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax, Portion Attributable to Parent	(26)	(220)	(108)
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax, Portion Attributable to Parent	99	34	(214)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax and Reclassification Adjustment, Attributable to Parent	47	(14)	(122)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(27)	(1)	219
Accumulated Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Net of Tax	(189)	(288)	(322)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(325)	(372)	(358)
Accumulated other comprehensive loss	(541)	(661)	(461)
Net current-period other comprehensive (loss) income	$ 120	$ (200)	$ (444)

Fair Value of Derivative Contra

Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Energy commodity derivative contracts(a)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 87	$ 174
Derivative Asset, Contracts Available for Netting	(42)	(43)
Derivative Liability, Fair Value, Gross Liability	(101)	(111)
Derivative Liability, Not Offset, Policy Election Deduction	42	43
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	0	(15)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Liability Net, Gain (Loss) Included in Earnings	0	(9)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Liability Net, Settlements	0	24
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	0	0
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	0	0
Interest rate swap agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	205	300
Derivative Asset, Contracts Available for Netting	(15)	(18)
Derivative Liability, Fair Value, Gross Liability	(65)	(57)
Derivative Liability, Not Offset, Policy Election Deduction	15	18
Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	166
Derivative Asset, Contracts Available for Netting	(6)
Derivative Liability, Fair Value, Gross Liability	(6)	(31)
Derivative Liability, Not Offset, Policy Election Deduction	6	0
Quoted prices in active markets for identical assets (Level 1) [Member] | Energy commodity derivative contracts(a)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	17	6
Derivative Liability, Fair Value, Gross Liability	(3)	(29)
Quoted prices in active markets for identical assets (Level 1) [Member] | Interest rate swap agreements
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
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 2 [Member] | Energy commodity derivative contracts(a)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	70	168
Derivative Liability, Fair Value, Gross Liability	(98)	(82)
Fair Value, Inputs, Level 2 [Member] | Interest rate swap agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	205	300
Derivative Liability, Fair Value, Gross Liability	(65)	(57)
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	166
Derivative Liability, Fair Value, Gross Liability	(6)	(31)
Significant unobservable inputs (Level 3) [Member] | Energy commodity derivative contracts(a)
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 swap agreements
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
Derivative Liability, Fair Value, Gross Liability	0	0
Energy commodity derivative contracts(a)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	33	131
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(59)	(31)
Interest rate swap agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	190	282
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(50)	(39)
Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	160
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	(31)
Contract and Over the Counter [Member] | Energy commodity derivative contracts(a)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Collateral, Obligation to Return Cash, Variation Margin	(12)	0
Derivative, Collateral, Right to Reclaim Cash, Variation Margins	0	37
Contract and Over the Counter [Member] | Interest rate swap agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Collateral, Obligation to Return Cash, Variation Margin	0	0
Derivative, Collateral, Right to Reclaim Cash, Variation Margins	0	0
Contract and Over the Counter [Member] | Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Collateral, Obligation to Return Cash, Variation Margin	0
Derivative, Collateral, Right to Reclaim Cash, Variation Margins	$ 0	$ 0

Fair Value of Debt (Details)

Fair Value of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 927	$ 1,149
Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	37,843	40,050
Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 40,050	$ 41,015

Reportable Segments Revenues (D

Reportable Segments Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
Revenues	$ 13,705	$ 13,058	$ 14,403
Single customer exceeding 10% of total [Member]
Revenues
Revenues	0	0	0
Operating Segments | CO2
Revenues
Revenues	1,196	1,221	1,699
Operating Segments | Kinder Morgan Canada
Revenues
Revenues	256	253	260
Operating Segments | External Customer [Member] | Natural Gas Pipelines
Revenues
Revenues	8,608	7,998	8,704
Operating Segments | External Customer [Member] | Terminals
Revenues
Revenues	1,965	1,921	1,878
Operating Segments | External Customer [Member] | Products Pipelines
Revenues
Revenues	1,645	1,631	1,828
Operating Segments | Intersegment revenues | Natural Gas Pipelines
Revenues
Revenues	10	7	21
Operating Segments | Intersegment revenues | Terminals
Revenues
Revenues	1	1	1
Operating Segments | Intersegment revenues | Products Pipelines
Revenues
Revenues	16	18	3
Corporate, Non-Segment and intersegment eliminations
Revenues
Revenues	$ 8	$ 8	$ 9
Revenues from External Customers [Member]
Revenues
Concentration Risk, Percentage	10.00%	10.00%	10.00%

Reportable Segments Operating e

Reportable Segments Operating expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating expenses(b)	$ 7,215	$ 6,222	$ 6,891
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Operating expenses(b)	5,457	4,393	4,738
Operating Segments | CO2
Segment Reporting Information [Line Items]
Operating expenses(b)	394	399	432
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Operating expenses(b)	788	768	836
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Operating expenses(b)	487	573	772
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Operating expenses(b)	95	87	87
Corporate, Non-Segment and intersegment eliminations
Segment Reporting Information [Line Items]
Operating expenses(b)	$ (6)	$ 2	$ 26

Reportable Segments Other expen

Reportable Segments Other expense (income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Other operating expenses	$ 12	$ 386	$ 2,066
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other operating expenses	26	199	1,269
Operating Segments | CO2
Segment Reporting Information [Line Items]
Other operating expenses	(1)	19	606
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Other operating expenses	(14)	99	190
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Other operating expenses	0	76	2
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Other operating expenses	0	0	(1)
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Other operating expenses	$ 1	$ (7)	$ 0

Reportable Segments Depreciatio

Reportable Segments Depreciation, depletion and amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
DD&A	$ 2,261	$ 2,209	$ 2,309
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
DD&A	1,011	1,041	1,046
Operating Segments | CO2
Segment Reporting Information [Line Items]
DD&A	493	446	556
Operating Segments | Terminals
Segment Reporting Information [Line Items]
DD&A	472	435	433
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
DD&A	216	221	206
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
DD&A	46	44	46
Corporate, Non-Segment
Segment Reporting Information [Line Items]
DD&A	$ 23	$ 22	$ 22

Reportable Segments Earnings (l

Reportable Segments Earnings (loss) from equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	$ 367	$ (172)	$ 333
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	253	(269)	285
Operating Segments | CO2
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	42	22	(5)
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	24	19	17
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	$ 48	$ 56	$ 36

Reportable Segments Other, net-

Reportable Segments Other, net-income(expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Other, net	$ 82	$ 44	$ 43
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other, net	49	19	24
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Other, net	8	4	8
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Other, net	(1)	2	4
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Other, net	25	15	8
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Other, net	$ 1	$ 4	$ (1)

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
DD&A	$ (2,261)	$ (2,209)	$ (2,309)
Amortization of excess cost of equity investments	(61)	(59)	(51)
General and administrative and corporate charges	(673)	(669)	(690)
Interest, net	(1,832)	(1,806)	(2,051)
Income tax expense	(1,938)	(917)	(564)
Net Income	223	721	208
Total segment EBDA
Segment Reporting Information [Line Items]
Segment EBDA(d)	6,975	6,364	5,891
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(d)	3,487	3,211	3,067
DD&A	(1,011)	(1,041)	(1,046)
Operating Segments | CO2
Segment Reporting Information [Line Items]
Segment EBDA(d)	847	827	658
DD&A	(493)	(446)	(556)
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Segment EBDA(d)	1,224	1,078	878
DD&A	(472)	(435)	(433)
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(d)	1,231	1,067	1,106
DD&A	(216)	(221)	(206)
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Segment EBDA(d)	186	181	182
DD&A	(46)	(44)	(46)
Corporate, Non-Segment
Segment Reporting Information [Line Items]
DD&A	(23)	(22)	(22)
General and administrative and corporate charges	$ (660)	$ (652)	$ (708)

Reportable Segments Capital exp

Reportable Segments Capital expenditures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Capital expenditures	$ 3,188	$ 2,882	$ 3,896
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	1,376	1,227	1,642
Operating Segments | CO2
Segment Reporting Information [Line Items]
Capital expenditures	436	276	725
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Capital expenditures	888	983	847
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	127	244	524
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Capital expenditures	338	124	142
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Capital expenditures	$ 23	$ 28	$ 16

Reportable Segments Investments

Reportable Segments Investments (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Investments	$ 7,298	$ 7,027
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments	6,218	6,185
Operating Segments | CO2
Segment Reporting Information [Line Items]
Investments	6	0
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Investments	263	252
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Investments	777	566
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Investments	34	20
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Investments	$ 0	$ 4

Reportable Segments Assets (Det

Reportable Segments Assets (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Assets at December 31	$ 79,055	$ 80,305
Assets held for sale	0	78
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Assets at December 31	3,382	6,108
Operating Segments | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets at December 31	51,173	50,428
Operating Segments | CO2
Segment Reporting Information [Line Items]
Assets at December 31	3,946	4,065
Operating Segments | Terminals
Segment Reporting Information [Line Items]
Assets at December 31	9,935	9,725
Operating Segments | Products Pipelines
Segment Reporting Information [Line Items]
Assets at December 31	8,539	8,329
Operating Segments | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Assets at December 31	$ 2,080	$ 1,572

Reportable Segments Geographica

Reportable Segments Geographical information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Total Revenues	$ 13,705	$ 13,058	$ 14,403
Long-term assets, excluding goodwill and other intangibles	51,079	51,606	53,939
U.S.
Segment Reporting Information [Line Items]
Total Revenues	13,073	12,459	13,797
Long-term assets, excluding goodwill and other intangibles	47,928	49,125	51,679
Canada
Segment Reporting Information [Line Items]
Total Revenues	503	483	479
Long-term assets, excluding goodwill and other intangibles	3,071	2,399	2,193
Mexico
Segment Reporting Information [Line Items]
Total Revenues	129	116	127
Long-term assets, excluding goodwill and other intangibles	$ 80	$ 82	$ 67

Reportable Segments Other (Deta

Reportable Segments Other (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues from External Customers [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	10.00%	10.00%	10.00%

Litigation, Environmental an117

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, 2017USD ($)
EPNG [Member] | Opinion 517 issued and implemented (rehearing pending); and Opinion 528 issued. [Member]
EPNG [Abstract]
Loss Contingency, Pending Claims, Number	2
Repreations, Refunds, and Rate Reductions [Member] | SFPP [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency Period of Time Litigation Concerns	2 years
Annual Rate Reductions [Member] | SFPP [Member] | Pending Litigation [Member]
SFPP [Abstract]
Loss Contingency, Damages Sought, Value	$ 40
Revenue Subject to Refund [Member] | SFPP [Member] | Pending Litigation [Member]
SFPP [Abstract]
Loss Contingency, Damages Sought, Value	$ 230

Litigation, Environmental an118

Litigation, Environmental and Other Contingencies Other Commercial Matters (Details) - USD ($) $ in Millions	May 24, 2016	Nov. 30, 2017	Apr. 30, 2017	Dec. 31, 2017
Gulf LNG Holdings Group, LLC
Loss Contingencies [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Brinckerhoff Merger [Member]
Loss Contingencies [Line Items]
Payments to Acquire Businesses, Gross			$ 9,200
Brinckerhoff Merger [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value			$ 700
Brinckerhoff Merger [Member] | Pending Litigation [Member] | Attorneys' fee [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value		$ 44
Price Reporting Litigation [Member] | Dismissed [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 500
Price Reporting Litigation [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 300

Litigation, Environmental an119

Litigation, Environmental and Other Contingencies Litigation General (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Loss Contingency, Information about Litigation Matters [Abstract]
Estimated Litigation Liability	$ 350	$ 407

Litigation, Environmental an120

Litigation, Environmental and Other Contingencies Environmental Matters (Details) $ in Millions

Jan. 06, 2017USD ($)

Oct. 05, 2016USD ($)

Jul. 28, 2016

Jun. 08, 2016USD ($)

Dec. 18, 2015USD ($)

Nov. 08, 2013

Aug. 06, 2013Defendants

Jul. 24, 2013

Dec. 31, 2000Terminals

Dec. 31, 2017USD ($)TerminalsPartiesDefendants

Dec. 31, 1969

Dec. 31, 2016USD ($)

Loss Contingencies [Line Items]

Accrual for Environmental Loss Contingencies

$ 279

$ 302

Recorded Third-Party Environmental Recoveries Receivable

$ 13

$ 13

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]

Number of Liquid Terminals | Terminals

2

4

Estimated Remedy Implementation Period

13 years

Number of Parties Involoved In Site Cleanup | Parties

90

Loss Contingency, Damages Sought, Value

$ 1,100

Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East [Member] | TGP and SNG [Member]

Loss Contingencies [Line Items]

Loss Contingency, Number of Defendants

100

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

Judicial District of Louisiana [Member] | Vermilion Parish Louisiana Coastal Zone [Member] | TGP [Member]

Loss Contingencies [Line Items]

Loss Contingency, Number of Defendants

52

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

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

Loss Contingencies [Line Items]

Number of Parties at a Joint Defense Group

70

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

Loss Contingencies [Line Items]

Loss Contingency, Damages Sought, Value

$ 80

Percent of legal expenses reimbursed by current property owner

50.00%

Minimum [Member] | 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]

Loss Contingency, Damages Sought, Value

$ 750

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

Loss Contingencies [Line Items]

Environmental Remediation Expense

$ 365

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

Loss Contingencies [Line Items]

Environmental Remediation Expense

3,200

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

Loss Contingencies [Line Items]

Environmental Remediation Expense

$ 1,700

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

Loss Contingencies [Line Items]

Environmental Remediation Expense

$ 165

Design [Member] | Lower Passaic River Study Area [Member] | Environmental Protection Agency [Member]

Loss Contingencies [Line Items]

Estimated Remedy Implementation Period

4 years

Clean Up Implementation [Member] | Lower Passaic River Study Area [Member] | Environmental Protection Agency [Member]

Loss Contingencies [Line Items]

Estimated Remedy Implementation Period

6 years

Recent Accounting Pronouceme121

Recent Accounting Pronoucements (Details) - USD ($) $ in Millions	Jan. 01, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	$ 100
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

Guarantee of Securities of S122

Guarantee of Securities of Subsidiaries Guarantee of Securities of Subsidiaries (Details) - USD ($) $ in Millions	Dec. 31, 2017	Sep. 01, 2016
Parent Issuer and Guarantor
Total debt - KMI and Subsidiaries	$ 13,750
Subsidiary Issuer and Guarantor - KMP
Total debt - KMI and Subsidiaries	18,885
Subsidiary Guarantors
Total debt - KMI and Subsidiaries	3,310
Capitalized Lease Debt Not Subject to Cross Guarantee Agreement	$ 162
Sale Equity Interest in SNG [Member]
Disposal Group, Equity Interest Sold		50.00%
Southern Natural Gas Company LLC | Sale Equity Interest in SNG [Member]
Disposal Group, Equity Interest Sold		50.00%

Guarantee of Securities of S123

Guarantee of Securities of Subsidiaries Income Statement and Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Guarantor Obligations [Line Items]
Total Revenues	$ 13,705	$ 13,058	$ 14,403
Costs of sales	4,345	3,429	4,059
Depreciation, depletion and amortization	2,261	2,209	2,309
Other operating expenses	(1)	(1)	(3)
Total Operating Costs, Expenses and Other	10,161	9,486	11,956
Operating Income	3,544	3,572	2,447
Earnings from equity investments	578	497	414
Interest, net	(1,832)	(1,806)	(2,051)
Amortization of excess cost of equity investments and other, net	82	44	43
Income Before Income Taxes	2,161	1,638	772
Income Tax Expense	(1,938)	(917)	(564)
Net Income	223	721	208
Net (Income) Loss Attributable to Noncontrolling Interests	(40)	(13)	45
Net Income Attributable to Kinder Morgan, Inc.	183	708	253
Preferred Stock Dividends	(156)	(156)	(26)
Net Income Available to Common Stockholders	27	552	227
Total other comprehensive loss	115	(200)	(444)
Comprehensive (loss) income	338	521	(236)
Comprehensive (income) loss attributable to noncontrolling interests	(86)	(13)	45
Comprehensive (loss) income attributable to controlling interests	252	508	(191)
Parent Issuer and Guarantor
Guarantor Obligations [Line Items]
Total Revenues	35	34	37
Costs of sales	0	0	0
Depreciation, depletion and amortization	16	18	22
Other operating expenses	76	725	71
Total Operating Costs, Expenses and Other	92	743	93
Operating Income	(57)	(709)	(56)
Earnings from consolidated subsidiaries	3,575	2,948	1,430
Earnings from equity investments	0	0	0
Interest, net	(701)	(696)	(686)
Amortization of excess cost of equity investments and other, net	0	0	0
Income Before Income Taxes	2,817	1,543	688
Income Tax Expense	(2,634)	(835)	(435)
Net Income	183	708	253
Net (Income) Loss Attributable to Noncontrolling Interests	0	0	0
Net Income Attributable to Kinder Morgan, Inc.	183	708	253
Preferred Stock Dividends	(156)	(156)	(26)
Net Income Available to Common Stockholders	27	552	227
Total other comprehensive loss	69	(200)	(444)
Comprehensive (loss) income	252	508	(191)
Comprehensive (income) loss attributable to noncontrolling interests	0	0	0
Comprehensive (loss) income attributable to controlling interests	252	508	(191)
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	(36)	38
Total Operating Costs, Expenses and Other	1	(36)	38
Operating Income	(1)	36	(38)
Earnings from consolidated subsidiaries	2,681	2,802	1,631
Earnings from equity investments	0	0	0
Interest, net	7	90	23
Amortization of excess cost of equity investments and other, net	0	0	1
Income Before Income Taxes	2,687	2,928	1,617
Income Tax Expense	(5)	(5)	(4)
Net Income	2,682	2,923	1,613
Net (Income) Loss Attributable to Noncontrolling Interests	0	0	0
Net Income Attributable to Kinder Morgan, Inc.	2,682	2,923	1,613
Preferred Stock Dividends	0	0	0
Net Income Available to Common Stockholders	2,682	2,923	1,613
Total other comprehensive loss	194	(341)	(460)
Comprehensive (loss) income	2,876	2,582	1,153
Comprehensive (income) loss attributable to noncontrolling interests	0	0	0
Comprehensive (loss) income attributable to controlling interests	2,876	2,582	1,153
Subsidiary Guarantors
Guarantor Obligations [Line Items]
Total Revenues	12,202	11,572	12,840
Costs of sales	4,124	3,176	3,691
Depreciation, depletion and amortization	1,933	1,872	1,929
Other operating expenses	2,999	2,459	4,770
Total Operating Costs, Expenses and Other	9,056	7,507	10,390
Operating Income	3,146	4,065	2,450
Earnings from consolidated subsidiaries	419	245	118
Earnings from equity investments	428	(113)	384
Interest, net	(1,104)	(1,149)	(1,345)
Amortization of excess cost of equity investments and other, net	(2)	(20)	(17)
Income Before Income Taxes	2,887	3,028	1,590
Income Tax Expense	237	(33)	(6)
Net Income	3,124	2,995	1,584
Net (Income) Loss Attributable to Noncontrolling Interests	0	0	0
Net Income Attributable to Kinder Morgan, Inc.	3,124	2,995	1,584
Preferred Stock Dividends	0	0	0
Net Income Available to Common Stockholders	3,124	2,995	1,584
Total other comprehensive loss	217	(352)	(325)
Comprehensive (loss) income	3,341	2,643	1,259
Comprehensive (income) loss attributable to noncontrolling interests	0	0	0
Comprehensive (loss) income attributable to controlling interests	3,341	2,643	1,259
Subsidiary Non-Guarantors
Guarantor Obligations [Line Items]
Total Revenues	1,614	1,511	1,575
Costs of sales	322	266	367
Depreciation, depletion and amortization	312	319	358
Other operating expenses	524	746	759
Total Operating Costs, Expenses and Other	1,158	1,331	1,484
Operating Income	456	180	91
Earnings from consolidated subsidiaries	59	58	(30)
Earnings from equity investments	0	0	0
Interest, net	(34)	(51)	(43)
Amortization of excess cost of equity investments and other, net	23	5	8
Income Before Income Taxes	504	192	26
Income Tax Expense	464	(44)	(119)
Net Income	968	148	(93)
Net (Income) Loss Attributable to Noncontrolling Interests	0	0	0
Net Income Attributable to Kinder Morgan, Inc.	968	148	(93)
Preferred Stock Dividends	0	0	0
Net Income Available to Common Stockholders	968	148	(93)
Total other comprehensive loss	160	55	(326)
Comprehensive (loss) income	1,128	203	(419)
Comprehensive (income) loss attributable to noncontrolling interests	0	0	0
Comprehensive (loss) income attributable to controlling interests	1,128	203	(419)
Consolidated KMI
Guarantor Obligations [Line Items]
Total Revenues	13,705	13,058	14,403
Costs of sales	4,345	3,429	4,059
Depreciation, depletion and amortization	2,261	2,209	2,309
Other operating expenses	3,555	3,848	5,588
Total Operating Costs, Expenses and Other	10,161	9,486	11,956
Operating Income	3,544	3,572	2,447
Earnings from consolidated subsidiaries	0	0	0
Earnings from equity investments	428	(113)	384
Interest, net	(1,832)	(1,806)	(2,051)
Amortization of excess cost of equity investments and other, net	21	(15)	(8)
Income Before Income Taxes	2,161	1,638	772
Income Tax Expense	(1,938)	(917)	(564)
Net Income	223	721	208
Net (Income) Loss Attributable to Noncontrolling Interests	(40)	(13)	45
Net Income Attributable to Kinder Morgan, Inc.	183	708	253
Preferred Stock Dividends	(156)	(156)	(26)
Net Income Available to Common Stockholders	27	552	227
Total other comprehensive loss	115	(200)	(444)
Comprehensive (loss) income	338	521	(236)
Comprehensive (income) loss attributable to noncontrolling interests	(86)	(13)	45
Comprehensive (loss) income attributable to controlling interests	252	508	(191)
Consolidating Adjustments
Guarantor Obligations [Line Items]
Total Revenues	(146)	(59)	(49)
Costs of sales	(101)	(13)	1
Depreciation, depletion and amortization	0	0	0
Other operating expenses	(45)	(46)	(50)
Total Operating Costs, Expenses and Other	(146)	(59)	(49)
Operating Income	0	0	0
Earnings from consolidated subsidiaries	(6,734)	(6,053)	(3,149)
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	(6,734)	(6,053)	(3,149)
Income Tax Expense	0	0	0
Net Income	(6,734)	(6,053)	(3,149)
Net (Income) Loss Attributable to Noncontrolling Interests	(40)	(13)	45
Net Income Attributable to Kinder Morgan, Inc.	(6,774)	(6,066)	(3,104)
Preferred Stock Dividends	0	0	0
Net Income Available to Common Stockholders	(6,774)	(6,066)	(3,104)
Total other comprehensive loss	(525)	638	1,111
Comprehensive (loss) income	(7,259)	(5,415)	(2,038)
Comprehensive (income) loss attributable to noncontrolling interests	(86)	(13)	45
Comprehensive (loss) income attributable to controlling interests	$ (7,345)	$ (5,428)	$ (1,993)

Guarantee of Securities of S124

Guarantee of Securities of Subsidiaries Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
ASSETS
Cash and cash equivalents	$ 264	$ 684	$ 229	$ 315
All other current assets	238	337
Property, plant and equipment, net	40,155	38,705
Investments	7,298	7,027
Goodwill	22,162	22,152	23,790
Deferred income taxes	2,044	4,352
Other non-current assets	1,582	1,522
Total Assets	79,055	80,305
LIABILITIES AND STOCKHOLDERS’ EQUITY
Long-term debt	35,015	37,354
Total Liabilities	43,931	45,503
Total KMI equity	33,636	34,431
Noncontrolling interests	1,488	371
Total Stockholders’ Equity	35,124	34,802	35,403	34,426
Total Liabilities and Stockholders’ Equity	79,055	80,305
Parent Issuer and Guarantor
ASSETS
Cash and cash equivalents	3	471	123	4
Other current assets - affiliates	6,214	5,739
All other current assets	243	269
Property, plant and equipment, net	236	242
Investments	665	665
Investments in subsidiaries	37,983	26,907
Goodwill	13,789	13,789
Notes receivable from affiliates	1,033	516
Deferred income taxes	3,635	6,647
Other non-current assets	254	72
Total Assets	64,055	55,317
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	924	1,286
Other current liabilities - affiliates	13,225	3,551
All other current liabilities	468	432
Long-term debt	13,104	13,308
Notes payable to affiliates	2,009	1,533
Deferred income taxes	0	0
Other long-term liabilities and deferred credits	689	776
Total Liabilities	30,419	20,886
Total KMI equity	33,636	34,431
Noncontrolling interests	0	0
Total Stockholders’ Equity	33,636	34,431
Total Liabilities and Stockholders’ Equity	64,055	55,317
Subsidiary Issuer and Guarantor - KMP
ASSETS
Cash and cash equivalents	0	0	0	15
Other current assets - affiliates	5,201	1,999
All other current assets	59	139
Property, plant and equipment, net	0	0
Investments	0	2
Investments in subsidiaries	36,728	28,894
Goodwill	22	22
Notes receivable from affiliates	20,363	21,608
Deferred income taxes	0	0
Other non-current assets	164	206
Total Assets	62,537	52,870
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	975	600
Other current liabilities - affiliates	14,188	13,299
All other current liabilities	347	362
Long-term debt	18,206	19,277
Notes payable to affiliates	448	448
Deferred income taxes	0	0
Other long-term liabilities and deferred credits	117	111
Total Liabilities	34,281	34,097
Total KMI equity	28,256	18,773
Noncontrolling interests	0	0
Total Stockholders’ Equity	28,256	18,773
Total Liabilities and Stockholders’ Equity	62,537	52,870
Subsidiary Guarantors
ASSETS
Cash and cash equivalents	0	9	12	17
Other current assets - affiliates	22,402	13,207
All other current assets	1,938	1,935
Property, plant and equipment, net	31,093	30,795
Investments	6,498	6,236
Investments in subsidiaries	5,417	4,307
Goodwill	5,166	5,167
Notes receivable from affiliates	1,233	1,132
Deferred income taxes	0	0
Other non-current assets	4,080	4,455
Total Assets	77,827	67,243
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	805	687
Other current liabilities - affiliates	6,512	4,197
All other current liabilities	2,055	2,016
Long-term debt	3,052	4,095
Notes payable to affiliates	20,593	20,520
Deferred income taxes	449	681
Other long-term liabilities and deferred credits	1,462	821
Total Liabilities	34,928	33,017
Total KMI equity	42,899	34,226
Noncontrolling interests	0	0
Total Stockholders’ Equity	42,899	34,226
Total Liabilities and Stockholders’ Equity	77,827	67,243
Subsidiary Non-Guarantors
ASSETS
Cash and cash equivalents	262	205	142	279
Other current assets - affiliates	858	655
All other current assets	235	205
Property, plant and equipment, net	8,826	7,668
Investments	135	124
Investments in subsidiaries	4,232	4,015
Goodwill	3,185	3,174
Notes receivable from affiliates	776	412
Deferred income taxes	0	0
Other non-current assets	183	107
Total Assets	18,692	16,565
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	124	123
Other current liabilities - affiliates	750	553
All other current liabilities	508	422
Long-term debt	653	674
Notes payable to affiliates	355	1,167
Deferred income taxes	1,142	1,614
Other long-term liabilities and deferred credits	467	517
Total Liabilities	3,999	5,070
Total KMI equity	14,693	11,495
Noncontrolling interests	0	0
Total Stockholders’ Equity	14,693	11,495
Total Liabilities and Stockholders’ Equity	18,692	16,565
Consolidated KMI
ASSETS
Cash and cash equivalents	264	684	229	315
Other current assets - affiliates	0	0
All other current assets	2,451	2,545
Property, plant and equipment, net	40,155	38,705
Investments	7,298	7,027
Investments in subsidiaries	0	0
Goodwill	22,162	22,152
Notes receivable from affiliates	0	0
Deferred income taxes	2,044	4,352
Other non-current assets	4,681	4,840
Total Assets	79,055	80,305
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	2,828	2,696
Other current liabilities - affiliates	0	0
All other current liabilities	3,353	3,228
Long-term debt	35,015	37,354
Notes payable to affiliates	0	0
Deferred income taxes	0	0
Other long-term liabilities and deferred credits	2,735	2,225
Total Liabilities	43,931	45,503
Total KMI equity	33,636	34,431
Noncontrolling interests	1,488	371
Total Stockholders’ Equity	35,124	34,802
Total Liabilities and Stockholders’ Equity	79,055	80,305
Consolidating Adjustments
ASSETS
Cash and cash equivalents	(1)	(1)	$ (48)	$ 0
Other current assets - affiliates	(34,675)	(21,600)
All other current assets	(24)	(3)
Property, plant and equipment, net	0	0
Investments	0	0
Investments in subsidiaries	(84,360)	(64,123)
Goodwill	0	0
Notes receivable from affiliates	(23,405)	(23,668)
Deferred income taxes	(1,591)	(2,295)
Other non-current assets	0	0
Total Assets	(144,056)	(111,690)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	0	0
Other current liabilities - affiliates	(34,675)	(21,600)
All other current liabilities	(25)	(4)
Long-term debt	0	0
Notes payable to affiliates	(23,405)	(23,668)
Deferred income taxes	(1,591)	(2,295)
Other long-term liabilities and deferred credits	0	0
Total Liabilities	(59,696)	(47,567)
Total KMI equity	(85,848)	(64,494)
Noncontrolling interests	1,488	371
Total Stockholders’ Equity	(84,360)	(64,123)
Total Liabilities and Stockholders’ Equity	$ (144,056)	$ (111,690)

Guarantee of Securities of S125

Guarantee of Securities of Subsidiaries Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	$ 4,601	$ 4,795	$ 5,313
Acquisitions of assets and investments, net of cash acquired	(4)	(333)	(2,079)
Capital expenditures	(3,188)	(2,882)	(3,896)
Proceeds from sale of equity interests in subsidiaries, net	0	1,401	0
Sales of property, plant and equipment, investments and other net assets, net of removal costs	118	330	39
Contributions to investments	(684)	(408)	(96)
Distributions from equity investments in excess of cumulative earnings	374	231	228
Funding (to) from affiliates	0
Other, net	22	(44)	98
Net Cash Used in Investing Activities	(3,362)	(1,705)	(5,706)
Issuances of debt	8,868	8,629	14,316
Payments of debt	(11,064)	(10,060)	(15,116)
Debt issue costs	(70)	(19)	(24)
Issuances of common shares	0	0	3,870
Issuance of mandatory convertible preferred stock (Note 11)	0	0	1,541
Cash dividends - common shares	(1,120)	(1,118)	(4,224)
Cash dividends - preferred shares	(156)	(154)	0
Repurchases of shares	(250)	0	(12)
Proceeds from Partnership Contribution	485	0	0
Contributions from noncontrolling interests - net proceeds from KML IPO	1,245	0	0
Proceeds from noncontrolling interests KML preferred stock	420	0	0
Contributions from noncontrolling interests - other	12	117	11
Distributions to noncontrolling interests	(42)	(24)	(34)
Other, net	(9)	(8)	(11)
Net Cash (Used in) Provided by Financing Activities	(1,681)	(2,637)	317
Effect of exchange rate changes on cash and cash equivalents	22	2	(10)
Net (decrease) increase in Cash and Cash Equivalents	(420)	455	(86)
Cash and Cash Equivalents, at Carrying Value	264	684	229	$ 315
Parent Issuer and Guarantor
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	(3,184)	(3,981)	(4,208)
Acquisitions of assets and investments, net of cash acquired	0	(2)	(1,843)
Capital expenditures	(23)	(27)	(10)
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	16	6	0
Contributions to investments	(237)	(343)	(21)
Distributions from equity investments in excess of cumulative earnings	2,297	2,417	2,653
Funding (to) from affiliates	(4,419)	(2,820)	(3,204)
Investment in KMP			(159)
Other, net	(23)	0	0
Net Cash Used in Investing Activities	(2,389)	(769)	(2,584)
Issuances of debt	8,609	8,255	14,316
Payments of debt	(9,288)	(7,322)	(14,048)
Debt issue costs	(12)	(16)	(24)
Issuances of common shares			3,870
Issuance of mandatory convertible preferred stock (Note 11)			1,541
Cash dividends - common shares	(1,120)	(1,118)	(4,224)
Cash dividends - preferred shares	(156)	(154)
Repurchases of shares	(250)		(12)
Funding from affiliates	7,327	5,461	5,502
Proceeds from Partnership Contribution	0
Contributions from parents	0	0	0
Contributions from noncontrolling interests - net proceeds from KML IPO	4
Proceeds from noncontrolling interests KML preferred stock	0
Contributions from noncontrolling interests - other	0	0	0
Distributions to parents	0	0	0
Distributions to noncontrolling interests	0	0	0
Other, net	(9)	(8)	(10)
Net Cash (Used in) Provided by Financing Activities	5,105	5,098	6,911
Effect of exchange rate changes on cash and cash equivalents	0	0	0
Net (decrease) increase in Cash and Cash Equivalents	(468)	348	119
Cash and Cash Equivalents, at Carrying Value	3	471	123	4
Subsidiary Issuer and Guarantor - KMP
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	3,911	4,980	6,824
Acquisitions of assets and investments, net of cash acquired	0	0	0
Capital expenditures	0	0	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	298	0
Funding (to) from affiliates	779	(535)	(8,388)
Investment in KMP			0
Other, net	36	(73)	24
Net Cash Used in Investing Activities	815	(310)	(8,364)
Issuances of debt	0	0	0
Payments of debt	(600)	(500)	(675)
Debt issue costs	0	0	0
Issuances of common shares			0
Issuance of mandatory convertible preferred stock (Note 11)			0
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0	0
Repurchases of shares	0		0
Funding from affiliates	776	1,116	6,989
Proceeds from Partnership Contribution	0
Contributions from parents	0	0	156
Contributions from noncontrolling interests - net proceeds from KML IPO	0
Proceeds from noncontrolling interests KML preferred stock	0
Contributions from noncontrolling interests - other	0	0	0
Distributions to parents	(4,902)	(5,286)	(4,944)
Distributions to noncontrolling interests	0	0	0
Other, net	0	0	(1)
Net Cash (Used in) Provided by Financing Activities	(4,726)	(4,670)	1,525
Effect of exchange rate changes on cash and cash equivalents	0	0	0
Net (decrease) increase in Cash and Cash Equivalents	0	0	(15)
Cash and Cash Equivalents, at Carrying Value	0	0	0	15
Subsidiary Guarantors
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	11,523	11,641	11,039
Acquisitions of assets and investments, net of cash acquired	(4)	(331)	(236)
Capital expenditures	(2,390)	(2,258)	(3,555)
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	94	326	39
Contributions to investments	(435)	(54)	(70)
Distributions from equity investments in excess of cumulative earnings	326	190	143
Funding (to) from affiliates	(7,040)	(5,062)	(7,980)
Investment in KMP			0
Other, net	4	39	16
Net Cash Used in Investing Activities	(9,445)	(5,749)	(11,643)
Issuances of debt	0	374	0
Payments of debt	(897)	(2,227)	(383)
Debt issue costs	0	(2)	0
Issuances of common shares			0
Issuance of mandatory convertible preferred stock (Note 11)			0
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0	0
Repurchases of shares	0		0
Funding from affiliates	3,797	1,959	7,112
Proceeds from Partnership Contribution	485
Contributions from parents	0	117	3
Contributions from noncontrolling interests - net proceeds from KML IPO	0
Proceeds from noncontrolling interests KML preferred stock	0
Contributions from noncontrolling interests - other	0	0	0
Distributions to parents	(5,472)	(6,116)	(6,133)
Distributions to noncontrolling interests	0	0	0
Other, net	0	0	0
Net Cash (Used in) Provided by Financing Activities	(2,087)	(5,895)	599
Effect of exchange rate changes on cash and cash equivalents	0	0	0
Net (decrease) increase in Cash and Cash Equivalents	(9)	(3)	(5)
Cash and Cash Equivalents, at Carrying Value	0	9	12	17
Subsidiary Non-Guarantors
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	1,121	885	347
Acquisitions of assets and investments, net of cash acquired	0	0	0
Capital expenditures	(775)	(597)	(331)
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	8	(2)	0
Contributions to investments	(12)	(11)	(10)
Distributions from equity investments in excess of cumulative earnings	0	0	0
Funding (to) from affiliates	(1,028)	(727)	(779)
Investment in KMP			0
Other, net	5	(10)	58
Net Cash Used in Investing Activities	(1,802)	(1,347)	(1,062)
Issuances of debt	259	0	0
Payments of debt	(279)	(11)	(10)
Debt issue costs	(58)	(1)	0
Issuances of common shares			0
Issuance of mandatory convertible preferred stock (Note 11)			0
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0	0
Repurchases of shares	0		0
Funding from affiliates	(192)	608	748
Proceeds from Partnership Contribution	0
Contributions from parents	1,673	0	16
Contributions from noncontrolling interests - net proceeds from KML IPO	0
Proceeds from noncontrolling interests KML preferred stock	0
Contributions from noncontrolling interests - other	0	0	0
Distributions to parents	(687)	(73)	(166)
Distributions to noncontrolling interests	0	0	0
Other, net	0	0	0
Net Cash (Used in) Provided by Financing Activities	716	523	588
Effect of exchange rate changes on cash and cash equivalents	22	2	(10)
Net (decrease) increase in Cash and Cash Equivalents	57	63	(137)
Cash and Cash Equivalents, at Carrying Value	262	205	142	279
Consolidated KMI
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	4,601	4,795	5,313
Acquisitions of assets and investments, net of cash acquired	(4)	(333)	(2,079)
Capital expenditures	(3,188)	(2,882)	(3,896)
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	118	330	39
Contributions to investments	(684)	(408)	(96)
Distributions from equity investments in excess of cumulative earnings	374	231	228
Funding (to) from affiliates		0	0
Investment in KMP			0
Other, net	22	(44)	98
Net Cash Used in Investing Activities	(3,362)	(1,705)	(5,706)
Issuances of debt	8,868	8,629	14,316
Payments of debt	(11,064)	(10,060)	(15,116)
Debt issue costs	(70)	(19)	(24)
Issuances of common shares			3,870
Issuance of mandatory convertible preferred stock (Note 11)			1,541
Cash dividends - common shares	(1,120)	(1,118)	(4,224)
Cash dividends - preferred shares	(156)	(154)
Repurchases of shares	(250)		(12)
Funding from affiliates	0	0	0
Proceeds from Partnership Contribution	485
Contributions from parents	0	0	0
Contributions from noncontrolling interests - net proceeds from KML IPO	1,245
Proceeds from noncontrolling interests KML preferred stock	420
Contributions from noncontrolling interests - other	12	117	11
Distributions to parents	0	0	0
Distributions to noncontrolling interests	(42)	(24)	(34)
Other, net	(9)	(8)	(11)
Net Cash (Used in) Provided by Financing Activities	(1,681)	(2,637)	317
Effect of exchange rate changes on cash and cash equivalents	22	2	(10)
Net (decrease) increase in Cash and Cash Equivalents	(420)	455	(86)
Cash and Cash Equivalents, at Carrying Value	264	684	229	315
Consolidating Adjustments
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	(8,770)	(8,730)	(8,689)
Acquisitions of assets and investments, net of cash acquired	0	0	0
Capital expenditures	0	0	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	5
Distributions from equity investments in excess of cumulative earnings	(2,249)	(2,674)	(2,568)
Funding (to) from affiliates	11,708	9,144	20,351
Investment in KMP			159
Other, net	0	0	0
Net Cash Used in Investing Activities	9,459	6,470	17,947
Issuances of debt	0	0	0
Payments of debt	0	0	0
Debt issue costs	0	0	0
Issuances of common shares			0
Issuance of mandatory convertible preferred stock (Note 11)			0
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0	0
Repurchases of shares	0		0
Funding from affiliates	(11,708)	(9,144)	(20,351)
Proceeds from Partnership Contribution	0
Contributions from parents	(1,673)	(117)	(175)
Contributions from noncontrolling interests - net proceeds from KML IPO	1,241
Proceeds from noncontrolling interests KML preferred stock	420
Contributions from noncontrolling interests - other	12	117	11
Distributions to parents	11,061	11,475	11,243
Distributions to noncontrolling interests	(42)	(24)	(34)
Other, net	0	0	0
Net Cash (Used in) Provided by Financing Activities	(689)	2,307	(9,306)
Effect of exchange rate changes on cash and cash equivalents	0	0	0
Net (decrease) increase in Cash and Cash Equivalents	0	47	(48)
Cash and Cash Equivalents, at Carrying Value	$ (1)	$ (1)	$ (48)	$ 0