Kinder Morgan (KMI) 10-K 10 Feb 17 2016 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 09, 2017	Jun. 30, 2016
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			$ 36,035,868,866
Entity Common Stock, Shares Outstanding		2,232,438,943
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues
Natural gas sales	$ 2,454,000,000	$ 2,839,000,000	$ 4,115,000,000
Services	8,146,000,000	8,290,000,000	7,650,000,000
Product sales and other	2,458,000,000	3,274,000,000	4,461,000,000
Total Revenues	13,058,000,000	14,403,000,000	16,226,000,000
Operating Costs, Expenses and Other
Costs of sales	3,498,000,000	4,115,000,000	6,278,000,000
Operations and maintenance	2,303,000,000	2,337,000,000	2,157,000,000
Depreciation, depletion and amortization	2,209,000,000	2,309,000,000	2,040,000,000
General and administrative	669,000,000	690,000,000	610,000,000
Taxes, other than income taxes	421,000,000	439,000,000	418,000,000
Loss on impairment of goodwill	0	1,150,000,000	0
Loss on impairments and divestitures, net	387,000,000	919,000,000	274,000,000
Other (income) expense, net	(1,000,000)	(3,000,000)	1,000,000
Total Operating Costs, Expenses and Other	9,486,000,000	11,956,000,000	11,778,000,000
Operating Income	3,572,000,000	2,447,000,000	4,448,000,000
Other Income (Expense)
Earnings from equity investments	497,000,000	414,000,000	406,000,000
Loss on impairments and divestitures of equity investments, net	(610,000,000)	(30,000,000)	0
Amortization of excess cost of equity investments	(59,000,000)	(51,000,000)	(45,000,000)
Interest, net	(1,806,000,000)	(2,051,000,000)	(1,798,000,000)
Other, net	44,000,000	43,000,000	80,000,000
Total Other Expense	(1,934,000,000)	(1,675,000,000)	(1,357,000,000)
Income Before Income Taxes	1,638,000,000	772,000,000	3,091,000,000
Income Tax Expense	(917,000,000)	(564,000,000)	(648,000,000)
Net Income	721,000,000	208,000,000	2,443,000,000
Net (Income) Loss Attributable to Noncontrolling Interests	(13,000,000)	45,000,000	(1,417,000,000)
Net Income Attributable to Kinder Morgan, Inc.	708,000,000	253,000,000	1,026,000,000
Preferred Stock Dividends	(156,000,000)	(26,000,000)	0
Net Income Available to Common Stockholders	$ 552,000,000	$ 227,000,000	$ 1,026,000,000
Class P Shares
Basic Earnings Per Common Share	$ 0.25	$ 0.10	$ 0.89
Basic Weighted Average Common Shares Outstanding	2,230	2,187	1,137
Diluted Earnings Per Common Share	$ 0.25	$ 0.10	$ 0.89
Diluted Weighted Average Common Shares Outstanding	2,230	2,193	1,137
Dividends Per Common Share Declared for the Period	$ 0.50	$ 1.605	$ 1.74

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Total
Net income	$ 721	$ 208	$ 2,443
Other comprehensive income (loss), net of tax
Change in fair value of hedge derivatives (net of tax benefit (expense) of $60, $(94) and $(163), respectively)	(104)	164	409
Reclassification of change in fair value of derivatives to net income (net of tax benefit of $67, $156 and $13, respectively)	(116)	(272)	(25)
Foreign currency translation adjustments (net of tax (expense) benefit of $(20), $123 and $48, respectively)	34	(214)	(138)
Benefit plan adjustments (net of tax benefit of $19, $69 and $126, respectively)	(14)	(122)	(226)
Total other comprehensive (loss) income	(200)	(444)	20
Comprehensive income (loss)	521	(236)	2,463
Comprehensive (income) loss attributable to noncontrolling interests	(13)	45	(1,486)
Comprehensive income (loss) attributable to KMI	$ 508	$ (191)	$ 977

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME, TAX (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Total, Tax
Change in fair value of derivatives utilized for hedging purposes	$ 60	$ (94)	$ (163)
Reclassification of change in fair value of derivatives to net income	67	156	13
Foreign currency translation adjustments	(20)	123	48
Benefit plan adjustments	$ 19	$ 69	$ 126

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 684	$ 229
Restricted deposits	103	60
Accounts receivable, net	1,370	1,315
Fair value of derivative contracts	198	507
Inventories	357	407
Income tax receivable	180	40
Other current assets	337	266
Total current assets	3,229	2,824
Property, plant and equipment, net	38,705	40,547
Investments	7,027	6,040
Goodwill	22,152	23,790
Other intangibles, net	3,318	3,551
Deferred income taxes	4,352	5,323
Deferred charges and other assets	1,522	2,029
Total Assets	80,305	84,104
Current liabilities
Current portion of debt	2,696	821
Accounts payable	1,257	1,192
Accrued interest	625	695
Accrued contingencies	261	298
Other current liabilities	1,085	1,059
Total current liabilities	5,924	4,065
Long-term debt
Outstanding	36,105	40,632
Preferred interest in general partner of KMP	100	100
Debt fair value adjustments	1,149	1,674
Total long-term debt	37,354	42,406
Other long-term liabilities and deferred credits	2,225	2,230
Total long-term liabilities and deferred credits	39,579	44,636
Total Liabilities	45,503	48,701
Commitments and contingencies (Notes 9, 13 and 17)
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,230,102,384 and 2,229,223,864 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	41,739	41,661
Retained deficit	(6,669)	(6,103)
Accumulated other comprehensive loss	(661)	(461)
Total Kinder Morgan, Inc.’s stockholders’ equity	34,431	35,119
Noncontrolling interests	371	284
Total Stockholders’ Equity	34,802	35,403
Total Liabilities and Stockholders’ Equity	$ 80,305	$ 84,104

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Stockholders’ Equity
Common stock, shares outstanding (in shares)	2,230,000,000	2,229,000,000
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)	2,230,102,384	2,229,223,864
Common stock, shares outstanding (in shares)	2,230,102,384	2,229,223,864

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flows From Operating Activities
Net income	$ 721	$ 208	$ 2,443
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	2,209	2,309	2,040
Deferred income taxes	1,087	692	615
Amortization of excess cost of equity investments	59	51	45
Gain on early extinguishment of debt	(45)	0	0
Loss on impairment of goodwill (Note 4)	0	1,150	0
Loss on impairments and divestitures, net (Note 4)	387	919	274
Loss on impairments and divestitures of equity investments, net (Note 4)	610	30	0
Earnings from equity investments	(497)	(414)	(406)
Distributions of equity investment earnings	431	391	381
Pension contributions and noncash pension benefit credits	0	(85)	(88)
Changes in components of working capital, net of the effects of acquisitions
Accounts receivable	(107)	382	(84)
Income tax receivable	(148)	195	(195)
Inventories	49	34	(30)
Other current assets	(81)	113	(17)
Accounts payable	144	(156)	(1)
Accrued interest, net of interest rate swaps	(18)	37	61
Accrued contingencies and other current liabilities	71	(129)	108
Rate reparations, refunds and other litigation reserve adjustments	(32)	18	(280)
Other, net	(53)	(442)	(399)
Net Cash Provided by Operating Activities	4,787	5,303	4,467
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired	(333)	(2,079)	(1,388)
Capital expenditures	(2,882)	(3,896)	(3,617)
Proceeds from sale of equity interests in subsidiaries, net	1,401	0	0
Sales of property, plant and equipment, investments, and other net assets, net of removal costs	330	39	5
Contributions to investments	(408)	(96)	(389)
Distributions from equity investments in excess of cumulative earnings	231	228	182
Other, net	(44)	98	(3)
Net Cash Used in Investing Activities	(1,705)	(5,706)	(5,210)
Cash Flows From Financing Activities
Issuances of debt	8,629	14,316	24,573
Payments of debt	(10,060)	(15,116)	(17,801)
Debt issue costs	(19)	(24)	(89)
Issuances of common shares (Note 11)	0	3,870	0
Issuance of mandatory convertible preferred stock (Note 11)	0	1,541	0
Cash dividends - common shares (Note 11)	(1,118)	(4,224)	(1,760)
Cash dividends - preferred shares (Note 11)	(154)	0	0
Repurchases of shares and warrants	0	(12)	(192)
Cash consideration of Merger Transactions (Note 1)	0	0	(3,937)
Merger Transactions costs	0	(2)	(74)
Contributions from noncontrolling interests	117	11	1,767
Distributions to noncontrolling interests	(24)	(34)	(2,013)
Other, net	0	1	(3)
Net Cash (Used in) Provided by Financing Activities	(2,629)	327	471
Effect of Exchange Rate Changes on Cash and Cash Equivalents	2	(10)	(11)
Net increase (decrease) in Cash and Cash Equivalents	455	(86)	(283)
Cash and Cash Equivalents, beginning of period	229	315	598
Cash and Cash Equivalents, end of period	684	229	315
Noncash Investing and Financing Activities
Assets acquired by the assumption or incurrence of liabilities	43	1,681	106
Net assets contributed to equity investments	37	46	0
Net assets and liabilities or noncontrolling interests acquired by the issuance of shares and warrants (Notes 1)	0	0	16,023
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	2,050	1,985	1,718
Cash paid (refunded) during the period for income taxes, net	$ 4	$ (331)	$ 227

CONSOLIDATED STATEMENT OF STOCK

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Class P	Preferred stock	Common stock	Preferred stock	Additional paid-in capital	Additional paid-in capitalPreferred stock	Retained deficit	Accumulated other comprehensive loss	Stockholders’ equity attributable to KMI	Stockholders’ equity attributable to KMIPreferred stock	Non-controlling interests	KMP, EPB and KMR [Member]	KMP, EPB and KMR [Member]Additional paid-in capital	KMP, EPB and KMR [Member]Stockholders’ equity attributable to KMI	KMP, EPB and KMR [Member]Non-controlling interests
Common stock, shares outstanding (in shares)	1,031,000,000
Preferred stock, shares outstanding (in shares)	0
Total at Dec. 31, 2013	$ 28,285			$ 10	$ 0	$ 14,479		$ (1,372)	$ (24)	$ 13,093		$ 15,192
Impact of Merger Transactions	1,097,000,000
Impact of Merger Transactions	$ 5,955			11		21,880				21,891		(15,936)
Merger Transactions costs	$ (75)					(75)				(75)
Repurchase of shares and warrants	(3,000,000)
Repurchase of shares and warrants	$ (192)					(192)				(192)
Adjustments to Additional Paid in Capital, Share-based Compensation, Restricted Stock Unit or Restricted Stock Award, Requisite Service Period Recognition	52					52				52
Impact from equity transactions of KMP, EPB and KMR													$ (19)	$ 36	$ 36	$ (55)
Net income	2,443							1,026		1,026		1,417
Distributions	(2,013)									0		(2,013)
Contributions	1,767									0		1,767
Common stock dividends	(1,760)							(1,760)		(1,760)
Other	(6)					(2)				(2)		(4)
Other comprehensive (loss) income	20								(49)	(49)		69
Impact of Merger Transactions on Accumulated other comprehensive loss	(31)								56	56		(87)
Total at Dec. 31, 2014	$ 34,426			21	0	36,178		(2,106)	(17)	34,076		350
Common stock, shares outstanding (in shares)	2,125,000,000
Preferred stock, shares outstanding (in shares)	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Restricted Stock Unit or Restricted Stock Award, Requisite Service Period Recognition	$ 57					57				57
Net income	208							253		253		(45)
Distributions	(34)									0		(34)
Contributions	11									0		11
Common stock dividends	(4,224)							(4,224)		(4,224)
Other	5					3				3		2
Other comprehensive (loss) income	$ (444)								(444)	(444)
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
Preferred stock dividends	(26)							(26)		(26)
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	2,229,223,864
Preferred stock, shares outstanding (in shares)	1,600,000
Adjustments to Additional Paid in Capital, Share-based Compensation, Restricted Stock Unit or Restricted Stock Award, Requisite Service Period Recognition	$ 66					66				66
Net income	721							708		708		13
Distributions	(24)									0		(24)
Contributions	117									0		117
Common stock dividends	(1,118)							(1,118)		(1,118)
Other	(7)					12				12		(19)
Other comprehensive (loss) income	(200)								(200)	(200)
Preferred stock dividends	(156)							(156)		(156)
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	2,230,102,384
Preferred stock, shares outstanding (in shares)	1,600,000

General (Notes)

General (Notes)	12 Months Ended
	Dec. 31, 2016
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 such products as steel, coal and petroleum coke. We are also a leading producer of CO 2 , which we and others utilize for enhanced oil recovery projects primarily in the Permian basin. On November 26, 2014, we completed our acquisition, pursuant to three separate merger agreements, of all of the outstanding common units of KMP and EPB and all of the outstanding shares of KMR that we did not already own. The transactions are referred to collectively as the “Merger Transactions.” As we controlled each of KMP, KMR and EPB and continued to control each of them after the Merger Transactions, the changes in our ownership interest in each of KMP, KMR and EPB were accounted for as an equity transaction and no gain or loss was recognized in our consolidated statements of income related to the Merger Transactions. After closing the Merger Transactions, KMR was merged with and into KMI. On January 1, 2015, EPB and its subsidiary, EPPOC, merged with and into KMP. References to EPB refer to EPB for periods prior to its merger into KMP. Prior to the Merger Transactions, we owned an approximate 10% limited partner interest (including our interest in KMR) and the 2% general partner interest including incentive distribution rights in KMP, and an approximate 39% limited partner interest and the 2% general partner interest and incentive distribution rights in EPB. Effective with the Merger Transactions, the incentive distribution rights held by the general partner of KMP were eliminated. The equity interests in KMP, EPB and KMR (which are all consolidated in our financial statements) owned by the public prior to the Merger Transactions are reflected within “Noncontrolling interests” in our accompanying consolidated statements of stockholders’ equity. The earnings recorded by KMP, EPB and KMR that are attributed to their units and shares, respectively, held by the public prior to the Merger Transactions are reported as “Net (income) loss attributable to noncontrolling interests” in our accompanying consolidated statement of income for the year ended December 31, 2014. 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, 2016
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 $103 million and $60 million as of December 31, 2016 and 2015 , respectively. Accounts Receivable, net The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of December 31, 2016 and 2015 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 $39 million and $91 million as of December 31, 2016 and 2015 , respectively. The decrease was primarily associated with certain coal customers’ receivables that were written off in 2016 and had been reserved in prior periods. 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, 2016 and 2015 , our gas imbalance receivables—including both trade and related party receivables—totaled $108 million and $21 million , respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2016 and 2015 , our gas imbalance payables—including both trade and related party payables—totaled $45 million and $17 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, for certain depreciable assets, we employ the composite depreciation method, applying 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. The units-of-production depreciation rate is determined by field and for our oil and gas producing fields that have no proved reserves, the units-of-production depreciation rate is based on each field’s probable reserves and NYMEX forward curve prices. 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 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. Prior to us conducting the 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 $767 million and $808 million as of December 31, 2016 and 2015 , 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, 2016, 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 and $138 million , as of December 31, 2016 and 2015 , respectively. 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. The increase in the equity method goodwill balance from December 31, 2015 is due to the sale of a 50% interest in our SNG natural gas pipeline system, see Note 3. 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 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 December 31, 2016 and 2015 , the gross carrying amounts of these intangible assets was $4,305 million and $4,335 million , respectively and the accumulated amortization was $986 million and $784 million , respectively, resulting in net carrying amounts of $3,318 million and $3,551 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, 2016 , 2015 and 2014 , the amortization expense on our intangibles totaled $223 million , $221 million and $143 million , respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2017 – 2021) is approximately $215 million , $213 million , $211 million , $209 million , and $208 million , respectively. As of December 31, 2016 , the weighted average amortization period for our intangible assets was approximately seventeen years . Other intangibles are evaluated for recoverability consistent with the discussion above on long-lived asset impairments. 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 carbon dioxide producing activities included within operations and maintenance totaled $349 million , $366 million and $403 million for the years ended December 31, 2016, 2015 and 2014, 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” 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 effective. 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 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 income/(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, 2016 and 2015 (in millions): December 31, 2016 2015 Current regulatory ass

Acquisitions (Notes)

Acquisitions (Notes)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	Acquisitions and Divestitures Business Combinations During 2016 , 2015 and 2014 , we completed the following significant acquisitions. Allocation of Purchase Price As of December 31, 2016, the evaluation of the assigned fair values for the BP terminals acquisition was ongoing and subject to adjustment. As of December 31, 2016, our preliminary allocation of the purchase price for the BP terminals acquisition and the purchase allocation for other significant acquisitions completed during 2016 , 2015 and 2014 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 ) (4) 11/14 Pennsylvania and Florida Jones Act Tankers 270 — 270 8 25 — (33 ) (5) 1/14 American Petroleum Tankers and State Class Tankers 961 6 951 6 64 — (66 ) 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 . (4) Pennsylvania and Florida Jones Act Tankers On November 5, 2014, we acquired two Jones Act tankers from Crowley Maritime Corporation (Crowley) for approximately $270 million . The MT Pennsylvania and the MT Florida engage in the marine transportation of crude oil, condensate and refined products in the U.S. domestic trade, commonly referred to as the Jones Act trade, and are currently operating pursuant to multi-year charters with a major integrated oil company. The vessels each have approximately 330 MBbl of cargo capacity and are included in our Terminals business segment. (5) American Petroleum Tankers and State Class Tankers Effective January 17, 2014, we acquired APT and State Class Tankers (SCT) for aggregate consideration of $961 million in cash (the APT acquisition). APT is engaged in Jones Act trade and its primary assets consist of a fleet of five medium range Jones Act qualified product tankers, each with 330 MBbl of cargo capacity, and each operating pursuant to long-term time charters with high quality counterparties, including major integrated oil companies, major refiners and the U.S. Military Sealift Command. As of the closing date, the vessels’ time charters had an average remaining term of approximately four years , with renewal options to extend the terms by an average of two years . SCT commissioned the construction of four medium range Jones Act qualified product tankers, by General Dynamics’ NASSCO shipyard, each with 330 MBbl of cargo capacity and were delivered in 2015 and 2016. The time charters for each vessel upon completion had an initial term of five years , with renewal options to extend the term by up to three years . The APT acquisition complements and extends our existing crude oil and refined products transportation and storage business. We include the acquired assets as part of our Terminals business segment. Asset Purchase 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 . The purchase gives us full ownership and control of ELC. Therefore, we prospectively changed our method of accounting for ELC from the equity method to full consolidation. Shell remains subscribed to 100% of the liquefaction capacity. 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 for additional information regarding our equity interests in NGPL Holdings LLC. Sale of Equity Interest and Terminal Assets 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 (see Note 9). 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. Terminals Asset Sale In October 2016, we entered into a definitive agreement to sell 20 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 seven of the locations closed in the fourth quarter of 2016, for which we received $37 million of the total consideration, with the balance of this transaction expected to close by April 2017 as certain conditions are 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 December 31, 2016 consolidated statement of income for the year ended December 31, 2016, and we have classified $61 million as held for sale for the remaining thirteen locations which is included within “Other current assets” on our accompanying consolidated balance sheet at December 31, 2016.

Impairments (Notes)

Impairments (Notes)	12 Months Ended
	Dec. 31, 2016
Impairments [Abstract]
Impairment of Goodwill, Long-lived assets and equity investments [Text Block]	Impairments and Losses on Divestitures During the years ended December 31, 2016, 2015, and 2014, we recorded impairments of certain equity investments, long-lived assets, and intangible assets, and net losses on divestitures totaling $1,013 million , $2,125 million , and $274 million , respectively. These adjustments were precipitated by a period of sustained deterioration in commodity prices which impacted the values of certain of our assets because of lower customer demand and, in the case of our CO 2 segment, reduced economics on our oil and gas properties. This lower commodity price environment led us to cancel certain projects that were in progress and divest of certain assets. For two of our equity investments in the Natural Gas Pipelines business segment, we determined that the negative outlook for long-term transportation contracts for those entities resulted in an other than temporary impairment of those investments in 2016 leading to a fair value write-down. 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 for further information. These impairments require management to estimate fair value of these assets. The impairments resulting from decisions to classify assets as held-for-sale are based on the value expected to be realized in the transaction which is generally known at the time. 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 certain 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 not be 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, 2016 2015 2014 Natural Gas Pipelines Impairment of goodwill $ — $ 1,150 $ — Impairments of long-lived assets(a) 106 79 — Losses on divestitures of long-lived assets(b) 94 43 5 Impairment of equity investments(c) 606 26 — Impairment at equity investee(d) 7 — — CO 2 Impairments of long-lived assets(e) 20 606 243 Gains on divestitures of long-lived assets (1 ) — — Impairment at equity investee(d) 9 26 — Terminals Impairments of long-lived assets(f) 19 188 — Losses on divestitures of long-lived assets(g) 80 3 29 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 (3 ) Gain on divestiture of equity investment (12 ) — — Other gains on divestitures of long-lived assets (7 ) (1 ) — Pre-tax losses on impairments and divestitures, net $ 1,013 $ 2,125 $ 274 _______ (a) 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) 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) 2016 and 2015 amounts are losses on impairments recorded by equity investees and included in “Earnings from equity investments” in 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. 2014 amount is primarily related to oil and gas properties. (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) 2016 amount primarily relates to an agreement to sell 20 bulk terminals that handle mostly coal and steel products, predominately located along the inland river system. The sale of seven locations closed in the fourth quarter of 2016. (h) 2016 amount represents project write-offs associated with the canceled Palmetto project.

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of “Income Before Income Taxes” are as follows (in millions): Year Ended December 31, 2016 2015 2014 U.S. $ 1,466 $ 611 $ 2,941 Foreign 172 161 150 Total Income Before Income Taxes $ 1,638 $ 772 $ 3,091 Components of the income tax provision applicable for federal, foreign and state taxes are as follows (in millions): Year Ended December 31, 2016 2015 2014 Current tax expense (benefit) Federal $ (148 ) $ (125 ) $ (16 ) State (28 ) (7 ) 36 Foreign 6 4 13 Total (170 ) (128 ) 33 Deferred tax expense (benefit) Federal 998 653 572 State 51 (4 ) 14 Foreign 38 43 29 Total 1,087 692 615 Total tax provision $ 917 $ 564 $ 648 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, 2016 2015 2014 Federal income tax $ 573 35.0 % $ 271 35.0 % $ 1,082 35.0 % Increase (decrease) as a result of: State deferred tax rate change 11 0.7 % (24 ) (3.1 )% — — % Taxes on foreign earnings 28 1.7 % 26 3.5 % 40 1.3 % Net effects of consolidating KMP and EPB and other noncontrolling interests (4 ) (0.3 )% 15 2.0 % (433 ) (14.0 )% State income tax, net of federal benefit 26 1.6 % 12 1.5 % 37 1.2 % Dividend received deduction (48 ) (2.9 )% (51 ) (6.6 )% (50 ) (1.6 )% Adjustments to uncertain tax positions (23 ) (1.4 )% (14 ) (1.9 )% (5 ) (0.2 )% Valuation allowance on investment and tax credits 34 2.1 % — — % 61 2.0 % Disposition of certain international holdings — — % — — % (112 ) (3.6 )% Nondeductible goodwill 301 18.5 % 323 41.7 % — — % Other 19 1.1 % 6 0.8 % 28 0.9 % Total $ 917 56.1 % $ 564 72.9 % $ 648 21.0 % Deferred tax assets and liabilities result from the following (in millions): December 31, 2016 2015 Deferred tax assets Employee benefits $ 401 $ 394 Accrued expenses 118 129 Net operating loss, capital loss and tax credit carryforwards 1,307 1,344 Derivative instruments and interest rate and currency swaps 22 45 Debt fair value adjustment 74 110 Investments 2,804 3,607 Other 14 3 Valuation allowances (184 ) (152 ) Total deferred tax assets 4,556 5,480 Deferred tax liabilities Property, plant and equipment 177 143 Other 27 14 Total deferred tax liabilities 204 157 Net deferred tax assets $ 4,352 $ 5,323 Deferred Tax Assets and Valuation Allowances: The step-up in tax basis from the Merger Transactions 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 recorded a full valuation allowance of $61 million against the deferred tax asset at December 31, 2014 related to our investment in NGPL as we concluded it was no longer realizable. We increased our valuation allowances in 2016 by $32 million , primarily due to $18 million for our foreign tax credits, $10 million for foreign net operating losses, and $4 million for capital losses for which we do not expect to realize a future tax benefit. We have 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 $123 million of valuation allowances related to these deferred tax assets at December 31, 2016. As of December 31, 2015, we had deferred tax assets of $1,005 million related to net operating loss carryovers, $339 million related to alternative minimum and foreign tax credits, and valuation allowances related to these deferred tax assets of $91 million . We expect to generate taxable income beginning in 2020 and utilize all federal net operating loss carryforwards and alternative minimum tax carryforwards by the end of 2025. Our alternative minimum tax credit carryforwards decreased by $151 million in 2016 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. In addition we have unrecorded deferred tax assets of $9 million as of December 31, 2016 related to net operating loss carryovers as a result of the delayed recognition of a windfall tax benefit related to share-based compensation. Upon the adoption of ASU 2016-09, the $9 million unrecorded deferred tax assets will be recorded through a cumulative-effect adjustment to retained earnings. Expiration Periods for Deferred Tax Assets: As of December 31, 2016, we have U.S. federal net operating loss carryforwards of $2.7 billion , which will expire from 2018 - 2036; state losses of $3.0 billion which will expire from 2017 - 2036; and foreign losses of $183 million , of which approximately $137 million carries over indefinitely and $46 million expires from 2029 - 2036. We also have $153 million of federal alternative minimum tax credits which do not expire; and approximately $21 million of foreign tax credits, which will expire from 2017 - 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, 2016 2015 2014 Balance at beginning of period $ 148 $ 189 $ 209 Additions based on current year tax positions 3 4 12 Additions based on prior year tax positions 7 — — Reductions based on prior year tax positions (1 ) (6 ) (3 ) Reductions based on settlements with taxing authority (26 ) (25 ) (24 ) Reductions due to lapse in statute of limitations (9 ) (14 ) (5 ) Balance at end of period $ 122 $ 148 $ 189 We recognize interest and/or penalties related to income tax matters in income tax expense. We recognized tax expense of $2 million and a benefit of $4 million and $1 million at December 31, 2016, 2015, and 2014, respectively. As of December 31, 2016 , 2015, and 2014, we had $28 million , $24 million and $28 million , respectively, of accrued interest. We had no accrued penalties as of December 31, 2016 and $2 million in accrued penalties as of both December 31, 2015 and 2014. All of the $122 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 increase by approximately $2 million during the next year to approximately $124 million , primarily due to additions for state filing positions taken in prior years. We are subject to taxation, and have tax years open to examination for the periods 2011-2015 in the U.S., 2002-2015 in various states and 2007-2015 in various foreign jurisdictions.

Property, Plant and Equipment (

Property, Plant and Equipment (Notes)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure [Text Block]	Property, Plant and Equipment, net Classes and Depreciation As of December 31, 2016 and 2015 , our property, plant and equipment, net consisted of the following (in millions): December 31, 2016 2015 Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 19,341 $ 19,855 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 23,298 22,979 Other(a) 4,780 4,719 Accumulated depreciation, depletion and amortization (12,306 ) (10,851 ) 35,113 36,702 Land and land rights-of-way 1,431 1,450 Construction work in process 2,161 2,395 Property, plant and equipment, net $ 38,705 $ 40,547 _______ (a) Includes buildings, computer and communication equipment, vessels, linefill and other. As of December 31, 2016 and 2015 , property, plant and equipment, net included $12,900 million and $16,089 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 $1,970 million , $2,059 million , and $1,862 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Asset Retirement Obligations As of December 31, 2016 and 2015 , we recognized asset retirement obligations in the aggregate amount of $193 million and $215 million , respectively, of which $9 million were classified as current for each respective period. 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, 2016
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, 2016 and 2015 , our investments consisted of the following (in millions): December 31, 2016 2015 Citrus Corporation $ 1,709 $ 1,719 SNG 1,505 — Ruby 798 1,093 Gulf LNG Holdings Group, LLC 485 516 NGPL Holdings LLC 475 153 Plantation Pipe Line Company 333 327 EagleHawk 329 348 MEP 328 713 Red Cedar Gathering Company 191 185 Watco Companies, LLC 180 201 Double Eagle Pipeline LLC 151 158 FEP 101 116 Liberty Pipeline Group LLC 75 79 Bear Creek Storage 61 — Sierrita Gas Pipeline LLC 57 60 Utopia Holding LLC 55 — Fort Union Gas Gathering L.L.C. 25 50 Parkway Pipeline LLC — 131 All others 169 183 Total equity investments 7,027 6,032 Bond investments — 8 Total investments $ 7,027 $ 6,040 As shown in the table above, our significant equity investments, as of December 31, 2016 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—Effective September 1, 2016, 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. Veresen Inc. owns the remaining interest in Ruby in the form of a convertible preferred interest. If Veresen converted its preferred interest into common interest, we and Veresen would each own a 50% common interest in Ruby; • 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 GE Financial Services and The Blackstone Group L.P.; • 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; • 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; • MEP—We operate MEP and own a 50% interest in MEP, the sole owner of the Midcontinent Express 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 3.4% common ownership that is accounted for under the equity method of accounting; • 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 50% interest in Bear Creek through TGP, one of our wholly owned subsidiaries. SNG 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% ; • Utopia Holding L.L.C. — We operate Utopia Holding L.L.C. and own a 50% interest in Utopia Holding L.L.C. after the sale of 50% of our interest to Riverstone Investment Group LLC on June 28, 2016; • 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; • Parkway Pipeline LLC —Prior to the sale of our interest in Parkway, we operated and owned a 50% interest in Parkway Pipeline LLC, the sole owner of the Parkway Pipeline refined petroleum products pipeline system. Valero Energy Corp. owns the remaining 50% interest; • Cortez Pipeline Company—We operate the Cortez carbon dioxide pipeline system, and as of December 31, 2016, we owned a 50% interest in, the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system. Our earnings (losses) from equity investments were as follows (in millions): Year Ended December 31, 2016 2015 2014 Citrus Corporation $ 102 $ 96 $ 97 SNG 58 — — FEP 51 55 55 Gulf LNG Holdings Group, LLC 48 49 48 MEP 40 45 45 Plantation Pipe Line Company 37 29 29 Watco Companies, LLC 25 16 13 Red Cedar Gathering Company 24 26 33 Cortez Pipeline Company(a) 24 (3 ) 25 Ruby 15 18 15 Parkway Pipeline LLC 14 5 8 NGPL Holdings LLC 12 — — Liberty Pipeline Group LLC 11 9 6 EagleHawk 10 24 (7 ) Sierrita Gas Pipeline LLC 7 9 3 Double Eagle Pipeline LLC 5 3 (1 ) Bear Creek Storage 2 — — Fort Union Gas Gathering L.L.C.(b) 1 16 16 All others 11 17 21 Total earnings from equity investments $ 497 $ 414 $ 406 Amortization of excess costs (59 ) (51 ) (45 ) _______ (a) 2016 and 2015 amounts include $9 million and $26 million , respectively, representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company. (b) 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 2016 2015 2014 Revenues $ 4,084 $ 3,857 $ 3,829 Costs and expenses 3,056 3,408 3,063 Net income $ 1,028 $ 449 $ 766 December 31, Balance Sheet 2016 2015 Current assets $ 892 $ 811 Non-current assets 22,170 19,745 Current liabilities 3,532 1,009 Non-current liabilities 9,187 11,227 Partners’/owners’ equity 10,343 8,320

Goodwill Goodwill (Notes)

Goodwill Goodwill (Notes)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 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 $ 5,719 $ 1,528 $ 1,908 $ 221 $ 1,573 $ 591 $ 29,067 Accumulated impairment losses (1,643 ) (447 ) — (1,197 ) (70 ) (679 ) (377 ) (4,413 ) December 31, 2014 15,884 5,272 1,528 711 151 894 214 24,654 Acquisitions(a) — 93 — 217 — 11 — 321 Currency translation — — — — — — (35 ) (35 ) Impairment — (1,150 ) — — — — — (1,150 ) December 31, 2015 15,884 4,215 1,528 928 151 905 179 23,790 Currency translation — — — — — — 6 6 Divestitures(b) (1,635 ) — — — — (9 ) — (1,644 ) December 31, 2016 $ 14,249 $ 4,215 $ 1,528 $ 928 $ 151 $ 896 $ 185 $ 22,152 _______ (a) 2015 includes $93 million and $217 million , respectively, related to the February 2015 acquisition of Hiland by Natural Gas Pipelines Non-Regulated and Products Pipelines, and $7 million related to the February 2015 acquisition of Vopak terminal assets by Terminals, all of which are discussed in Note 3. (b) 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. Refer to Note 2 “Summary of Significant Accounting Policies— Goodwill ” for a description of our accounting for goodwill and Note 4 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 multiplies 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. As of May 31, 2016, with the exception of our Natural Gas Pipelines Non-Regulated reporting unit, each of our reporting units indicated a fair value in excess of their respective carrying values. The amount of excess fair value over the carrying value ranged from approximately 9% for our Natural Gas Pipelines Regulated reporting unit to 80% for our Products Pipelines Terminals as of May 31, 2016. The results of our Step 2 analysis for our Natural Gas Pipelines Non-Regulated reporting unit 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 . For our Natural Gas Pipelines Non-Regulated and our CO 2 reporting units, our May 31, 2016 annual test and our December 31, 2015 interim test included a discounted cash flow analysis (income approach) to evaluate the fair value of these reporting units to provide additional indication of fair value based on the present value of cash flows these reporting units are expected to generate in the future. We weighted the market and income approaches for these reporting units to arrive at an estimated fair value of these respective reporting units giving more weighting on the income approach and less on the market approach as we believed the values indicated using the income approach are more representative of the value that could be received from a market participant. 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 as discussed in Note 4. 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, 2016
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, 2016 2015 KMI Unsecured term loan facility, variable rate, due January 26, 2019(a) $ 1,000 $ — Senior notes 1.50% through 8.25%, due 2016 through 2098(b)(c) 13,236 13,346 Credit facility expiring November 26, 2019 — — Commercial paper borrowings — — KMP Senior notes, 2.65% through 9.00%, due 2016 through 2044(c) 19,485 19,985 TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(a)(c) 1,540 1,790 EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(c) 1,115 1,115 Copano senior notes, 7.125%, due April 1, 2021(c)(d) — 332 CIG senior notes, 4.15% through 6.85%, due 2026 through 2037(c)(e) 475 100 SNG notes, 4.40% through 8.00%, due 2017 through 2032(c)(f) — 1,211 Other Subsidiary Borrowings (as obligor) Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(a)(c) 786 1,636 Hiland Partners Holdings LLC, senior notes, 5.50% and 7.25%, due 2020 and 2022(c)(g) 225 974 EPC Building, LLC, promissory note, 3.967%, due 2016 through 2035 433 443 Trust I preferred securities, 4.75%, due March 31, 2028(h) 221 221 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(i) 100 100 Other miscellaneous debt(j) 285 300 Total debt – KMI and Subsidiaries 38,901 41,553 Less: Current portion of debt(a)(f)(k) 2,696 821 Total long-term debt – KMI and Subsidiaries(l) $ 36,205 $ 40,732 _______ (a) On January 26, 2016, we entered into a $1 billion three -year unsecured term loan facility with a variable interest rate, which is determined in the same manner as interest on our revolving credit facility borrowings. In January 2016, we repaid $850 million of maturing 5.70% senior notes, and in February 2016, we repaid $250 million of maturing 8.00% senior notes primarily using proceeds from the three-year term loan. Since we refinanced a portion of the maturing debt with proceeds from long-term debt, we classified $1 billion of the maturing debt within “Long-term debt” on our consolidated balance sheet as of December 31, 2015. (b) Amounts include senior notes that are denominated in Euros and have been converted and are respectively reported above at the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro and the December 31, 2015 exchange rate of 1.0862 U.S. dollars per Euro. For the year ended December 31, 2016 , our debt decreased by $43 million as a result of the change in the exchange rate of U.S dollars per Euro. The decrease 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 ”). (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) On September 30, 2016, we repaid the $332 million principal amount of 7.125% senior notes due 2021, plus accrued interest. We recognized a $28.3 million gain from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2016 consisting of an $11.8 million premium on the debt repaid and a $40.1 million gain from the write-off of unamortized purchase accounting associated with the extinguished debt. Copano continues to be a subsidiary guarantor under a cross guarantee agreement (see Note 19). (e) On August 16, 2016, CIG completed a private offering of $375 million in principal amount of 4.15% senior notes due August 15, 2026. The net proceeds of $372 million received from the offering were used to reduce debt incurred as the result of the repayment of CIG’s senior notes that matured in 2015 and for general corporate purposes. (f) Due to the September 1, 2016 sale of a 50% interest in SNG, we no longer consolidate SNG’s accounts in our consolidated financial statements. As of the transaction date, SNG had $1,211 million of debt outstanding (including a current portion of $500 million ). (g) On October 1, 2016, a portion of the proceeds from the sale of a 50% interest in SNG was used to repay the $749 million principal amount of Hiland’s 7.25% senior notes due 2020, plus accrued interest. We recognized a $17.3 million gain from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2016 consisting of a $27.1 million premium on the debt repaid and a $44.4 million gain from the write-off of unamortized purchase accounting associated with the extinguished debt. (h) Capital Trust I (Trust I), is a 100% -owned business trust that as of December 31, 2016 , 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. 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, 2016 , the outstanding balance of $221 million (of which $111 million was classified as current) was bifurcated between debt ( $199 million ) and equity ( $22 million ). During the years ended December 31, 2016 and 2015 , 200 and 1,176,015 , respectively, of Trust I Preferred Securities had been converted into (i) 143 and 846,369 shares of our Class P common stock; (ii) approximately $5,000 and $30 million in cash; and (iii) 220 and 1,293,615 in warrants, respectively. (i) As of December 31, 2016 and 2015, 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. (j) 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, 2016 , the principal amounts of the Totem and High Plains financing obligations were $71 million and $92 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. (k) Amounts include outstanding credit facility and commercial paper borrowings and other debt maturing within 12 months. See “—Maturities of Debt” below. (l) Excludes our “Debt fair value adjustments” which, as of December 31, 2016 and 2015 , increased our combined debt balances by $1,149 million and $1,674 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. Credit Facilities and Restrictive Covenants 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. As of December 31, 2016 , we were in compliance with all required financial covenants. Our credit facility included the following restrictive covenants as of December 31, 2016 : • 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, 2016 , we had no borrowings outstanding under our five -year $5.0 billion revolving credit facility, no borrowings outstanding under our $4.0 billion commercial paper program and $160 million in letters of credit. Our availability under our revolving credit facility as of December 31, 2016 was $4,840 million . Current Portion of Debt The primary components of our current portion of debt include the following significant series of long-term notes: As of December 31, 2016 $600 million 6.00% notes due February 2017 $300 million 7.50% notes due April 2017 $355 million 5.95% notes due April 2017 $786 million 7.00% notes due June 2017 $500 million 2.00% notes due December 2017 As of December 31, 2015 $500 million 3.50% notes due March 2016 Long-term Debt Issuances, Repayments and Other Significant Changes in Debt Following are significant long-term debt issuances, repayments and other significant changes made during 2016 and 2015 : 2016 2015 Issuances $1.0 billion unsecured term loan facility due 2019 $800 million 5.05% notes due 2046 $375 million 4.15% notes due 2026 $815 million 1.50% notes due 2022(a) $543 million 2.25% notes due 2027(a) Repayments $850 million 5.70% notes due 2016 $300 million 5.625% notes due 2015 $500 million 3.50% notes due 2016 $250 million 5.15% notes due 2015 $250 million 8.00% notes due 2016 $340 million 6.80% notes due 2015 $67 million 8.25% notes due 2016 $375 million 4.10% notes due 2015 $332 million 7.125% notes due 2021 $749 million 7.25% notes due 2020 Other significant changes $1,211 million reduction due to the deconsolidation of SNG, including a current portion of $500 million (see Note 3) $1,413 million assumption of senior notes and other borrowings due to the Hiland acquisition of which $368 million was immediately paid down after closing (see Note 3)(b) _______ (a) Senior notes are denominated in Euros and are presented above in U.S. dollars at the exchange rate on the issuance date of 1.0862 U.S. dollars per Euro. We entered into cross-currency swap agreements associated with these senior notes (see Note 14—“Risk Management—Foreign Currency Risk Management”). (b) As of the February 13, 2015 Hiland acquisition date, we assumed (i) $975 million in principal amount of senior notes (which were valued at $1,043 million as of the acquisition date) and (ii) $368 million of other borrowings that were immediately repaid after closing, primarily consisting of borrowings outstanding under a revolving credit facility. The senior notes are subject to our cross guarantee agreement discussed in Note 19. Maturities of Debt The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2016 , are summarized as follows (in millions): Year Total 2017 $ 2,696 2018 2,328 2019 3,820 2020 2,204 2021 2,422 Thereafter 25,431 Total $ 38,901 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, 2016 , 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 2016 2015 Purchase accounting debt fair value adjustments $ 806 $ 1,135 Carrying value adjustment to hedged debt 220 380 Unamortized portion of proceeds received from the early termination of interest rate swap agreements 342 397 Unamortized debt discount/premiums (80 ) (86 ) Unamortized debt issuance costs (139 ) (152 ) Total debt fair value adjustments $ 1,149 $ 1,674 Interest Rates, Interest Rate Swaps and Contingent Debt The weighted average interest rate on all of our borrowings was 4.95% during 2016 and 4.92% during 2015 . Information on our interest rate swaps is contained in Note 14. For information about our contingent debt agreements, see Note 13 “Commitments and Contingent Liabilities— Contingent Debt ”).

Share-based Compensation and Em

Share-based Compensation and Employee Benefits Share-based Compensation and Employee Benefits (Notes)	12 Months Ended
	Dec. 31, 2016
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 2016 , 2015 and 2014 , we made restricted Class P common stock grants to our non-employee directors of 31,880 , 9,580 and 6,210 , respectively. These grants were valued at time of issuance at $400,000 , $401,000 and $220,000 , 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 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, 2016 December 31, 2015 December 31, 2014 Shares Weighted Average Shares Weighted Average Shares Weighted Average Grant Date Fair Value Outstanding at beginning of period 7,645,105 $ 37.91 7,373,294 $ 37.63 6,382,885 $ 37.38 Granted 2,816,599 21.36 1,488,467 38.20 1,694,668 36.01 Vested (1,226,652 ) 38.53 (817,797 ) 35.66 (460,032 ) 28.84 Forfeited (196,915 ) 35.74 (398,859 ) 38.51 (244,227 ) 36.39 Outstanding at end of period 9,038,137 $ 32.72 7,645,105 $ 37.91 7,373,294 $ 37.63 The intrinsic value of restricted stock awards vested during the years ended December 31, 2016, 2015 and 2014 was $25 million , $31 million and $17 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 2017 1,476,832 2018 2,352,443 2019 4,358,728 2020 539,790 2021 199,850 Thereafter 110,494 Total Outstanding 9,038,137 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 2016 , 2015 and 2014 , we recorded $66 million , $52 million and $51 million , respectively, in expense related to restricted stock awards and capitalized approximately $9 million , $15 million and $6 million , respectively. At December 31, 2016 and 2015 , unrecognized restricted stock awards compensation costs, less estimated forfeitures, was approximately $133 million and $154 million , respectively. 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 plan participants’ contributions and Company contributions are based on collective bargaining agreements. The total expense for our savings plan was approximately $48 million , $46 million , and $42 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Pension Plans Our U.S. pension plan is a defined benefit plan that covers substantially all of our U.S. employees and provides benefits under a cash balance formula. A participant in the cash balance plan accrues benefits through contribution credits based on a combination of age and years of service, times 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 continue to accrue benefits through career pay or final pay formulas. Two of our subsidiaries, Kinder Morgan Canada Inc. and Trans Mountain Pipeline Inc. (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. The associated net periodic benefit costs for these combined Canadian plans of $12 million and $10 million for the years ended December 31, 2015 and 2014, respectively, were reported separately in prior years. 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. 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. Effective January 1, 2014, the U.S. plans were amended to provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange. 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, 2016 and 2015 (in millions): Pension Benefits OPEB 2016 2015 2016 2015 Change in benefit obligation: Benefit obligation at beginning of period $ 2,654 $ 2,804 $ 509 $ 624 Service cost 36 33 1 — Interest cost 89 99 16 21 Actuarial loss (gain) 127 (109 ) (42 ) (101 ) Benefits paid (180 ) (173 ) (41 ) (39 ) Participant contributions 3 — 2 2 Medicare Part D subsidy receipts — — 1 2 Exchange rate changes 4 — 1 — Other(a) 151 — 26 — Benefit obligation at end of period 2,884 2,654 473 509 Change in plan assets: Fair value of plan assets at beginning of period 2,050 2,377 325 389 Actual return (loss) on plan assets 157 (204 ) 29 (45 ) Employer contributions 8 50 16 16 Participant contributions 3 — 2 2 Medicare Part D subsidy receipts — — 1 2 Benefits paid (180 ) (173 ) (41 ) (39 ) Exchange rate changes 3 — — — Other(a) 119 — — — Fair value of plan assets at end of period 2,160 2,050 332 325 Funded status - net liability at December 31, $ (724 ) $ (604 ) $ (141 ) $ (184 ) _______ (a) 2016 amounts represent December 31, 2015 balances associated with our Canadian pension and OPEB plans and Plantation Pipeline OPEB plan for prospective inclusion in these disclosures, which associated net periodic benefit costs were reported separately in prior years. Components of Funded Status . The following table details the amounts recognized in our balance sheet at December 31, 2016 and 2015 related to our pension and OPEB plans (in millions): Pension Benefits OPEB 2016 2015 2016 2015 Non-current benefit asset(a) $ — $ — $ 153 $ 139 Current benefit liability — — (16 ) (16 ) Non-current benefit liability(a) (724 ) (604 ) (278 ) (307 ) Funded status - net liability at December 31, $ (724 ) $ (604 ) $ (141 ) $ (184 ) _______ (a) 2016 OPEB amount includes $29 million of non-current benefit assets and $12 million of non-current benefit liabilities related to plans we sponsor which are associated with employee services provided to unconsolidated joint ventures, and for which we have recorded an offsetting related party deferred charge/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, 2016 and 2015 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 2016 2015 2016 2015 Unrecognized net actuarial (loss) gain $ (682 ) $ (558 ) $ 69 $ 23 Unrecognized prior service (cost) credit (5 ) (4 ) 18 19 Accumulated other comprehensive (loss) income $ (687 ) $ (562 ) $ 87 $ 42 We anticipate that approximately $44 million of pre-tax accumulated other comprehensive loss will be recognized as part of our net periodic benefit cost in 2017 , including approximately $45 million of unrecognized net actuarial loss and approximately $1 million of unrecognized prior service credit. Our accumulated benefit obligation for our pension plans was $2,834 million and $2,615 million at December 31, 2016 and 2015 , respectively. Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $415 million and $444 million at December 31, 2016 and 2015 , respectively. The fair value of these plans’ assets was approximately $121 million at both December 31, 2016 and 2015 . 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, 2016 , 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). As of December 31, 2016 , 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% master limited partnerships. As of December 31, 2016 , the allowable range for asset allocations in effect for our Canadian pension plans were 0% to 55% equity and 45% to 100% fixed income. 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 master limited partnerships. 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. These amounts 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, 2016 and 2015 (in millions): Pension Assets 2016 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Cash $ 10 $ — $ — $ 10 $ 15 $ — $ — $ 15 Short-term investment funds — 100 — 100 — 110 — 110 Mutual funds(a) 197 — — 197 70 — — 70 Equities(b) 283 — — 283 271 — — 271 Fixed income securities — 428 — 428 — 449 — 449 Immediate participation guarantee contract — — 16 16 — — 15 15 Derivatives — (2 ) — (2 ) — (14 ) — (14 ) Subtotal $ 490 $ 526 $ 16 1,032 $ 356 $ 545 $ 15 916 Measured at NAV(c) Common/collective trusts(d) 829 775 Private investment funds(e) 290 347 Private limited partnerships(f) 9 12 Subtotal 1,128 1,134 Total plan assets fair value $ 2,160 $ 2,050 _______ (a) For 2016 and 2015 , this category includes mutual funds which are invested in equity. (b) Plan assets include $126 million and $91 million of KMI Class P common stock for 2016 and 2015 , respectively. (c) Plan assets for which fair value was measured using NAV as a practical expedient. (d) Common/collective trust funds were invested in approximately 39% fixed income and 61% equity in 2016 and 45% fixed income and 55% equity in 2015 . (e) Private investment funds were invested in approximately 54% fixed income and 46% equity in 2016 and 46% fixed income and 54% equity in 2015 . (f) Private limited partnerships were invested in real estate, venture and buyout funds for 2016 and 2015 . OPEB Assets 2016 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Short-term investment funds $ — $ 15 $ — $ 15 $ — $ 16 $ — $ 16 Equities 11 — — 11 8 — — 8 Master limited partnerships 57 — — 57 51 — — 51 Guaranteed insurance contracts — — 47 47 — — 49 49 Mutual funds 1 — — 1 1 — — 1 Subtotal $ 69 $ 15 $ 47 131 $ 60 $ 16 $ 49 125 Measured at NAV(a) Common/collective trusts(b) 68 71 Fixed income trusts 64 58 Limited partnerships(c) 69 71 Subtotal 201 200 Total plan assets fair value $ 332 $ 325 _______ (a) Plan assets for which fair value was measured using NAV as a practical expedient. (b) Common/collective trust funds which are invested in approximately 72% equity and 28% fixed income securities for 2016 and 67% equity and 33% fixed income securities for 2015. (c) For 2016 and 2015 , 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, 2016 and 2015 (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 2016 Insurance contracts $ 15 $ — $ 1 $ — $ 16 2015 Insurance contracts $ 15 $ — $ — $ — $ 15 OPEB Assets Balance at Beginning of Period Transfers In (Out) Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period 2016 Insurance contracts $ 49 $ — $ (2 ) $ — $ 47 2015 Insurance contracts $ 51 $ — $ (1 ) $ (1 ) $ 49 Changes in the underlying value of Level 3 assets due to the effect of changes of fair value were immaterial for the years ended December 31, 2016 and 2015 . Expected Payment of Future Benefits and Employer Contributions . As of December 31, 2016 , we expect to make the following benefit payments under our plans (in millions): Fiscal year Pension Benefits OPEB(a) 2017 $ 235 $ 39 2018 237 38 2019 232 39 2020 231 37 2021 220 37 2022 - 2026 1,016 168 _______ (a) Includes a reduction of approximately $3 million in each of the years 2017 - 2021 and approximately $16 million in aggregate for 2022 - 2026 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. In 2017 , we expect to contribute approximately $22 million to our U.S. pension plan and $7 million , net of anticipated subsidies, to our U.S. OPEB plans. In 2017, we expect to contribute approximately $8 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 2016 , 2015 and 2014 : Pension Benefits OPEB 2016 2015 2014 2016 2015 2014 Assumptions related to benefit obligations: Discount rate 3.83 % 4.05 % 3.66 % 3.69 % 3.91 % 3.56 % Rate of compensation increase 3.52 % 3.50 % 4.50 % n/a n/a n/a Assumptions related to benefit costs: Discount rate for benefit obligations 4.05 % 3.66 % 4.45 % 3.91 % 3.56 % 4.34 % Discount rate for interest on benefit obligations 3.24 % 3.66 % 4.45 % 3.18 % 3.56 % 4.34 % Discount rate for service cost 4.15 % 3.66 % 4.45 % 4.36 % 3.56 % 4.34 % Discount rate for interest on service cost 3.50 % 3.66 % 4.45 % 4.17 % 3.56 % 4.34 % Expected return on plan assets(a) 7.31 % 7.50 % 7.50 % 7.07 % 7.08 % 7.43 % Rate of compensation increase 3.51 % 4.50 % 3.50 % 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 2016 , 2015 and 2014 . For years 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 9.30% , 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, 2016 and 2015 (in millions): 2016 2015 One-percentage point increase: Aggregate of service cost and interest cost $ 1 $ 2 Accumulated postretirement benefit obligation 27 31 One-percentage point decrease: Aggregate of service cost and interest cost $ (1 ) $ (1 ) Accumulated postretirement benefit obligation (23 ) (27 ) 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 2016 2015 2014 2016 2015 2014 Components of net benefit cost: Service cost $ 36 $ 33 $ 21 $ 1 $ — $ — Interest cost 89 99 112 16 21 25 Expected return on assets (151 ) (172 ) (171 ) (19 ) (23 ) (24 ) Amortization of prior service cost (credit) 1 — — (3 ) (3 ) (2 ) Amortization of net actuarial loss (gain) 35 5 — — 1 (1 ) Net benefit (credit) cost(a) 10 (35 ) (38 ) (5 ) (4 ) (2 ) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 116 267 285 (48 ) (49 ) 10 Prior service cost (credit) arising during period — — — — — — Amortization or settlement recognition of net actuarial loss (34 ) (5 ) — — (1 ) — Amortization of prior service credit — — — 1 1 1 Exchange rate changes 1 — — — — — Total recognized in total other comprehensive (income) loss 83 262 285 (47 ) (49 ) 11 Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ 93 $ 227 $ 247 $ (52 ) $ (53 ) $ 9 _______ (a) 2016 OPEB amount includes $4 million of net benefit credits related to plans that we sponsor that are associated with employee services provided to unconsolidated joint ventures. We charge or refund these costs or credits associated with these plans 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 , $10 million and $13 million for the years ended December 31, 2016 , 2015 and 2014 , 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, 2016
Stockholders' Equity Note [Abstract]
Shareholders' Equity	Stockholders’ Equity Common Equity As of December 31, 2016, our common equity consisted of our Class P common stock. During the years 2014 through 2015, as authorized by our board of directors under various repurchase programs, we repurchased shares and warrants. As of December 31, 2016, we had $90 million of availability to repurchase warrants. During the years ended December 31, 2015 and 2014 , we paid a total of $12 million and $98 million , respectively, for the repurchase of warrants. During the year ended December 31, 2014 , we repurchased $94 million of our Class P shares. 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 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 . Common 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, 2016 2015 2014 Per common share cash dividend declared for the period $ 0.50 $ 1.605 $ 1.74 Per common share cash dividend paid in the period 0.50 1.93 1.70 On January 18, 2017, our board of directors declared a cash dividend of $0.125 per common share for the quarterly period ended December 31, 2016, which is payable on February 15, 2017 to shareholders of record as of February 1, 2017. Warrants Each of our warrants entitles 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, at any time until May 25, 2017. The table below sets forth the changes in our outstanding warrants: Warrants 2016 2015 2014 Beginning balance 293,263,797 298,135,976 347,933,107 Warrants issued with conversions of EP Trust I Preferred securities(a) — 1,293,615 4,315 Warrants exercised — (71,268 ) (18,040 ) Warrants repurchased and canceled — (6,094,526 ) (49,783,406 ) Ending balance 293,263,797 293,263,797 298,135,976 _______ (a) See Note 9. 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 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. On October 19, 2016 , our board of directors declared a cash dividend of $24.375000 per share of our mandatory convertible preferred stock (equivalent of $1.218750 per depositary share) for the period from and including October 26, 2016 through and including January 25, 2017, which was paid on January 26, 2017 to mandatory convertible preferred shareholders of record as of January 11, 2017. Noncontrolling Interests Contributions Prior to the completion of the Merger Transactions on November 26, 2014, contributions from our noncontrolling interests consisted primarily of equity issuances to the public of common units or shares by KMP, EPB and KMR. Each of these subsidiaries had an equity distribution agreement in place which allowed the subsidiary to sell its equity interests from time to time through a designated sales agent. The equity distribution agreement provided the subsidiary with the right, but not the obligation to offer and sell its equity units or shares, at prices to be determined by market conditions. For the period from January 1, 2014 to November 26, 2014, KMP, EPB and KMR made equity issuances of 30 million units or shares, resulting in net proceeds of $1,695 million . These equity issuances had the associated effects of increasing our (i) noncontrolling interests by $1,640 million ; (ii) accumulated deferred income taxes by $19 million ; and (iii) additional paid-in capital by $36 million . Distributions The following table provides information about distributions from our noncontrolling interests (in millions except per unit and i-unit distribution amounts): Year Ended December 31, 2014 KMP(a) Per unit cash distribution declared for the period $ 4.17 Per unit cash distribution paid in the period $ 5.53 Cash distributions paid in the period to the public $ 1,654 EPB(a) Per unit cash distribution declared for the period $ 1.95 Per unit cash distribution paid in the period $ 2.60 Cash distributions paid in the period to the public $ 347 KMR(a)(b) Share distributions paid in the period to the public 7,794,183 _______ (a) As a result of the Merger Transactions, no distribution was declared starting with the fourth quarter of 2014. (b) KMR’s distributions were paid in the form of additional shares or fractions thereof calculated by dividing the KMP cash distribution per common unit by the average of the market closing prices of a KMR share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Represents share distributions made in the period to noncontrolling interests and excludes 1,127,712 of shares distributed in 2014 on KMR shares we directly and indirectly owned.

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Affiliate Balances The following tables summarize our affiliate balance sheet balances and income statement activity (in millions): December 31, 2016 2015 Balance sheet location Accounts receivable, net $ 37 $ 25 Other current assets — 36 Deferred charges and other assets 10 — $ 47 $ 61 Current portion of debt $ 6 $ 6 Accounts payable 28 22 Other current liabilities 9 10 Long-term debt 161 167 Other long-term liabilities and deferred credits 29 — $ 233 $ 205 Year Ended December 31, 2016 2015 2014 Income statement location Revenues Services $ 71 $ 72 $ 29 Product sales and other 71 71 86 $ 142 $ 143 $ 115 Operating Costs, Expenses and Other Costs of sales $ 38 $ 60 $ 74 Other operating expenses 75 55 57 Notes Receivable Plantation In March 2016, we received the final principal payment of $35 million for our proportionate share of a note receivable due from Plantation. We own a 51.17% equity interest in Plantation and the $35 million note receivable balance for our proportionate share of the note was included within “Other current assets” on our accompanying consolidated balance sheet as of December 31, 2015 . Subsequent Event MEP Loan Agreement On February 3, 2017 we renewed our $40 million loan agreement for an additional one -year term with MEP, our 50% -owned equity investee. The loan agreement allows us, at our sole option, to make loans from time to time to MEP to fund its working capital needs and for other LLC purposes. Borrowings under the loan agreement bear interest at a rate of one month LIBOR plus 1.50% , and all borrowings can be prepaid before maturity without penalty or premium. As of both December 31, 2016 and 2015 there was no amount outstanding pursuant to this loan agreement.

Commitments and Contingent Liab

Commitments and Contingent Liabilities (Notes)	12 Months Ended
	Dec. 31, 2016
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, 2016 (in millions): Year Commitment 2017 $ 106 2018 94 2019 86 2020 75 2021 61 Thereafter 342 Total minimum payments $ 764 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 $138 million , $143 million and $114 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. The amount of capital leases included within “Property, plant and equipment, net” in our accompanying consolidated balance sheets as of December 31, 2016 and 2015 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, 2016 and 2015, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $1,179 million and $1,202 million , respectively. Both December 31, 2016 and 2015 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 the debt obligations of our 50% -owned investee, Cortez Pipeline Company. We are severally liable for 50% (our percentage ownership share) of the Cortez Pipeline Company debt which includes a $50 million credit facility and $100 million in bonds. In addition, we are liable for 100% of the debt issued by one of Cortez Pipeline Company’s subsidiaries in the event of their non-performance which has a $100 million credit facility and $120 million private placement note to fund an expansion project. 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. Commitment for Jones Act Trade Fleet Expansion Under an August 2015 definitive construction agreement with Philly Tankers LLC, we are expected to have four more Jones Act tankers delivered by the end of 2017. Our obligation for payments due under the terms of this agreement total $383 million in 2017, of which, approximately $195 million relates to work not yet performed as of December 31, 2016.

Risk Management (Notes)

Risk Management (Notes)	12 Months Ended
	Dec. 31, 2016
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 certain of these risks. In addition, prior to May 2016, we had power forward and swap contracts related to legacy operations of acquired businesses. Energy Commodity Price Risk Management As of December 31, 2016 , 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 (19.7 ) MMBbl Crude oil basis (1.3 ) MMBbl Natural gas fixed price (38.4 ) Bcf Natural gas basis (19.3 ) Bcf Derivatives not designated as hedging contracts Crude oil fixed price (1.7 ) MMBbl Crude oil basis (0.1 ) MMBbl Natural gas fixed price (5.2 ) Bcf Natural gas basis (1.4 ) Bcf NGL and other fixed price (5.0 ) MMBbl As of December 31, 2016 , 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 2020. Interest Rate Risk Management As of December 31, 2016 , we had a combined notional principal amount of $9,775 million of fixed-to-variable interest rate swap agreements, all of which were designated as fair value hedges. As of December 31, 2015 , we had a combined notional principal amount of $11,000 million of fixed-to-variable interest rate swap agreements, of which $9,700 million 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, 2016 , 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 In connection with the issuance of our Euro denominated senior notes in March 2015 (see Note 9), we entered into $1,358 million of cross-currency swap agreements to manage the related foreign currency risk 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 on our accompanying consolidated balance sheets (in millions): Fair Value of Derivative Contracts Asset derivatives Liability derivatives December 31, December 31, 2016 2015 2016 2015 Location Fair value Fair value Derivatives designated as hedging contracts Natural gas and crude derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 101 $ 359 $ (57 ) $ (13 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 70 244 (24 ) — Subtotal 171 603 (81 ) (13 ) Interest rate swap agreements Fair value of derivative contracts/(Other current liabilities) 94 111 — — Deferred charges and other assets/(Other long-term liabilities and deferred credits) 206 273 (57 ) (9 ) Subtotal 300 384 (57 ) (9 ) Cross-currency swap agreements Fair value of derivative contracts/(Other current liabilities) — — (7 ) (6 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (24 ) (46 ) Subtotal — — (31 ) (52 ) Total 471 987 (169 ) (74 ) Derivatives not designated as hedging contracts Natural gas, crude, NGL and other derivative contracts Fair value of derivative contracts/(Other current liabilities) 3 35 (29 ) (1 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (1 ) — Subtotal 3 35 (30 ) (1 ) Interest rate swap agreements Fair value of derivative contracts/(Other current liabilities) — 1 — (11 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — — (5 ) Subtotal — 1 — (16 ) Power derivative contracts Fair value of derivative contracts/(Other current liabilities) — 1 — (17 ) Subtotal — 1 — (17 ) Total 3 37 (30 ) (34 ) Total derivatives $ 474 $ 1,024 $ (199 ) $ (108 ) 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, 2016 2015 2014 Interest rate swap agreements Interest, net $ (180 ) $ 25 $ 207 Hedged fixed rate debt Interest, net $ 160 $ (33 ) $ (204 ) 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, 2016 2015 2014 2016 2015 2014 2016 2015 2014 Energy commodity derivative contracts $ (115 ) $ 201 $ 424 Revenues—Natural gas sales $ 15 $ 54 $ (1 ) Revenues—Natural gas sales $ — $ — $ — Revenues—Product sales and other 148 236 26 Revenues—Product sales and other (12 ) 2 11 Costs of sales (17 ) (15 ) 4 Costs of sales — — — Interest rate swap agreements(c) (2 ) (4 ) (15 ) Interest, net (3 ) (3 ) (4 ) Interest, net — — — Cross-currency swap 13 (33 ) — Other, net (27 ) — — Other, net — — — Total $ (104 ) $ 164 $ 409 Total $ 116 $ 272 $ 25 Total $ (12 ) $ 2 $ 11 _______ (a) We expect to reclassify an approximate $8 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of December 31, 2016 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, 2016 2015 2014 Energy commodity derivative contracts Revenues—Natural gas sales $ (10 ) $ 17 $ (7 ) Revenues—Product sales and other (26 ) 176 20 Costs of sales 3 (2 ) — Other (income) expense, net — — (2 ) Interest rate swap agreements Interest, net 63 (15 ) — Total(a) $ 30 $ 176 $ 11 ________ (a) For the years ended December 31, 2016 and 2015, includes an approximate gain of $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, 2016 and 2015 , we had $0 million and $2 million , respectively, of outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2016 , we had cash margins of $37 million posted by us with our counterparties as collateral and no amounts posted by our counterparties as collateral. As of December 31, 2015 , we had no cash margins posted by us as collateral and cash margins of $37 million posted by our counterparties as collateral. 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, 2016 , 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 $10 million of additional collateral and no additional collateral beyond this $10 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, 2013 $ (3 ) $ 2 $ (23 ) $ (24 ) Other comprehensive gain (loss) before reclassifications 254 (68 ) (212 ) (26 ) Gains reclassified from accumulated other comprehensive loss (22 ) — (1 ) (23 ) Impact of Merger Transactions (See Note 1) 98 (42 ) — 56 Net current-period other comprehensive income (loss) 330 (110 ) (213 ) 7 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 )

Fair Value (Notes)

Fair Value (Notes)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value	Fair Value of Financial Instruments 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, 2016 Energy commodity derivative contracts(a) $ 6 $ 168 $ — $ 174 $ (43 ) $ — $ 131 Interest rate swap agreements $ — $ 300 $ — $ 300 $ (18 ) $ — $ 282 As of December 31, 2015 Energy commodity derivative contracts(a) $ 48 $ 589 $ 2 $ 639 $ (12 ) $ (37 ) $ 590 Interest rate swap agreements $ — $ 385 $ — $ 385 $ (8 ) $ — $ 377 Balance sheet liability fair value measurements by level Level 1 Level 2 Level 3 Gross amount Contracts available for netting Collateral posted(c) Net amount 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 ) As of December 31, 2015 Energy commodity derivative contracts(a) $ (4 ) $ (10 ) $ (17 ) $ (31 ) $ 12 $ — $ (19 ) Interest rate swap agreements $ — $ (25 ) $ — $ (25 ) $ 8 $ — $ (17 ) Cross-currency swap agreements $ — $ (52 ) $ — $ (52 ) $ — $ — $ (52 ) _______ (a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and options and NGL swaps. Level 3 consists primarily of power derivative contracts. (b) Cash margin deposits held by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities” on our accompanying consolidated balance sheets. (c) Cash margin deposits posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Restricted Deposits” on our accompanying consolidated balance sheets. 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, 2016 2015 Derivatives-net asset (liability) Beginning of period $ (15 ) $ (61 ) Total gains or (losses) included in earnings (9 ) (13 ) Settlements 24 59 End of period $ — $ (15 ) 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 $ — $ — As of December 31, 2015 , our Level 3 derivative assets and liabilities 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 does not expect materially different valuation results were we to use different input amounts within reasonable ranges. Fair Value of Debt The carrying value and estimated fair value of our outstanding debt balances is disclosed below (in millions): December 31, 2016 December 31, 2015 Carrying value Estimated fair value Carrying value Estimated fair value Total debt $ 40,050 $ 41,015 $ 43,227 $ 37,481 We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2016 and 2015 .

Reportable Segments (Notes)

Reportable Segments (Notes)	12 Months Ended
	Dec. 31, 2016
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—(i) the ownership and/or operation of 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 coal, petroleum coke, fertilizer, steel and ores 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, 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. Segment results for the years ended December 31, 2015 and 2014 have been retrospectively adjusted to reflect the elimination of the Other segment as a reportable segment. The activities that previously comprised the Other segment are now presented within the Corporate non-segment activities in reconciling to the consolidated totals in the respective segment reporting tables. The Other segment had historically been comprised primarily of legacy operations of acquired businesses not associated with our ongoing operations. These business activities have since been sold or have otherwise ceased. In addition, the Other segment included certain company owned real estate assets which are primarily leased to our operating subsidiaries as well as third party tenants. This activity is now reflected within Corporate activity. In addition, the portions of interest income and income tax expense previously allocated to our business segments is now included in “Interest expense, net” and “Income tax expense” for all periods presented in the following tables. 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 2016, 2015 and 2014, 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, 2016 2015 2014 Revenues Natural Gas Pipelines Revenues from external customers $ 7,998 $ 8,704 $ 10,153 Intersegment revenues 7 21 15 CO 2 1,221 1,699 1,960 Terminals Revenues from external customers 1,921 1,878 1,717 Intersegment revenues 1 1 1 Products Pipelines Revenues from external customers 1,631 1,828 2,068 Intersegment revenues 18 3 — Kinder Morgan Canada 253 260 291 Corporate and intersegment eliminations(a) 8 9 21 Total consolidated revenues $ 13,058 $ 14,403 $ 16,226 Year Ended December 31, 2016 2015 2014 Operating expenses(b) Natural Gas Pipelines $ 4,393 $ 4,738 $ 6,241 CO 2 399 432 494 Terminals 768 836 746 Products Pipelines 573 772 1,258 Kinder Morgan Canada 87 87 106 Corporate and intersegment eliminations 2 26 8 Total consolidated operating expenses $ 6,222 $ 6,891 $ 8,853 Year Ended December 31, 2016 2015 2014 Other expense (income)(c) Natural Gas Pipelines $ 199 $ 1,269 $ 5 CO 2 19 606 243 Terminals 99 190 29 Products Pipelines 76 2 (3 ) Kinder Morgan Canada — (1 ) — Corporate (7 ) — 1 Total consolidated other expense (income) $ 386 $ 2,066 $ 275 Year Ended December 31, 2016 2015 2014 DD&A Natural Gas Pipelines $ 1,041 $ 1,046 $ 897 CO 2 446 556 570 Terminals 435 433 337 Products Pipelines 221 206 166 Kinder Morgan Canada 44 46 51 Corporate 22 22 19 Total consolidated DD&A $ 2,209 $ 2,309 $ 2,040 Year Ended December 31, 2016 2015 2014 Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments Natural Gas Pipelines $ (269 ) $ 285 $ 279 CO 2 22 (5 ) 26 Terminals 19 17 18 Products Pipelines 56 36 37 Corporate — — 1 Total consolidated equity earnings $ (172 ) $ 333 $ 361 Year Ended December 31, 2016 2015 2014 Other, net-income (expense) Natural Gas Pipelines $ 19 $ 24 $ 24 Terminals 4 8 12 Products Pipelines 2 4 (1 ) Kinder Morgan Canada 15 8 15 Corporate 4 (1 ) 30 Total consolidated other, net-income (expense) $ 44 $ 43 $ 80 Year Ended December 31, 2016 2015 2014 Segment EBDA(d) Natural Gas Pipelines $ 3,211 $ 3,067 $ 4,264 CO 2 827 658 1,248 Terminals 1,078 878 973 Products Pipelines 1,067 1,106 856 Kinder Morgan Canada 181 182 200 Total segment EBDA 6,364 5,891 7,541 DD&A (2,209 ) (2,309 ) (2,040 ) Amortization of excess cost of equity investments (59 ) (51 ) (45 ) General and administrative expenses (669 ) (690 ) (610 ) Interest expense, net (1,806 ) (2,051 ) (1,798 ) Corporate(a) 17 (18 ) 43 Income tax expense (917 ) (564 ) (648 ) Total consolidated net income $ 721 $ 208 $ 2,443 Year Ended December 31, 2016 2015 2014 Capital expenditures Natural Gas Pipelines $ 1,227 $ 1,642 $ 935 CO 2 276 725 792 Terminals 983 847 1,049 Products Pipelines 244 524 680 Kinder Morgan Canada 124 142 156 Corporate 28 16 5 Total consolidated capital expenditures $ 2,882 $ 3,896 $ 3,617 2016 2015 Investments at December 31 Natural Gas Pipelines $ 6,185 $ 5,080 Terminals 252 306 Products Pipelines 566 641 Kinder Morgan Canada 20 10 Corporate 4 3 Total consolidated investments $ 7,027 $ 6,040 2016 2015 Assets at December 31 Natural Gas Pipelines $ 50,428 $ 53,704 CO 2 4,065 4,706 Terminals 9,725 9,083 Products Pipelines 8,329 8,464 Kinder Morgan Canada 1,572 1,434 Corporate assets(e) 6,108 6,694 Assets held for sale 78 19 Total consolidated assets $ 80,305 $ 84,104 _______ (a) Includes a management fee for services we perform as operator of an equity investee. (b) Includes natural gas purchases and other 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) expense, net. (d) Includes revenues, earnings from equity investments, other, net, less operating expenses, and other (income) expense, 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 operations) 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 segments (in millions): Year Ended December 31, 2016 2015 2014 Revenues from external customers U.S. $ 12,459 $ 13,797 $ 15,605 Canada 483 479 437 Mexico 116 127 184 Total consolidated revenues from external customers $ 13,058 $ 14,403 $ 16,226 December 31, 2016 2015 2014 Long-term assets, excluding goodwill and other intangibles U.S. $ 49,125 $ 51,679 $ 49,992 Canada 2,399 2,193 2,268 Mexico 82 67 81 Total consolidated long-lived assets $ 51,606 $ 53,939 $ 52,341

Litigation, Environmental and O

Litigation, Environmental and Other Contingencies (Notes)	12 Months Ended
	Dec. 31, 2016
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. Federal Energy Regulatory Commission 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 late 2015 with the FERC (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. 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 $190 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 has sought federal appellate review of Opinion 517-A and oral argument is scheduled for February 15, 2017. 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, NGPL and WIC were notified by the FERC of rate proceedings against them pursuant to section 5 of the Natural Gas Act (the “Orders”). Each respective proceeding will set the matter for hearing and determine whether NGPL’s and WIC’s current rates remain just and reasonable. A proceeding under section 5 of the Natural Gas Act is prospective in nature such that a change in rates charged to customers, if any, would likely only occur after the FERC has issued a final order. Unless a settlement is reached sooner, an initial Administrative Law Judge decision is anticipated in late February, 2018, with a final FERC decision anticipated by the third quarter, 2018. We do not believe that the ultimate resolution of these proceedings will have a material adverse impact on our results of operations or cash flows from operations. Other Commercial Matters Union Pacific Railroad Company Easements & Related Litigation SFPP and Union Pacific Railroad Company (UPRR) are engaged in a proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten -year period beginning January 1, 2004 ( Union Pacific Railroad Company v. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004). In September 2011, the trial judge determined that the annual rent payable as of January 1, 2004 was $14 million , subject to annual consumer price index increases. SFPP appealed the judgment. By notice dated October 25, 2013, UPRR demanded the payment of $22.3 million in rent for the first year of the next ten -year period beginning January 1, 2014, which SFPP rejected. On November 5, 2014, the Court of Appeals issued an opinion which reversed the judgment, including the award of prejudgment interest, and remanded the matter to the trial court for a determination of UPRR’s property interest in its right-of-way, including whether UPRR has sufficient interest to grant SFPP’s easements. UPRR filed a petition for review to the California Supreme Court which was denied. The trial court has not set a date for the retrial. After the above-referenced decision by the California Court of Appeals which held that UPRR does not own the subsurface rights to grant certain easements and may not be able to collect rent from those easements, a purported class action lawsuit was filed in 2015 in the U.S. District Court for the Southern District of California by private landowners in California 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 and are pending 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” for declaratory judgment, trespass, ejectment, quiet title, unjust enrichment, accounting, and alleged unlawful business acts and practices arising from defendants’ alleged improper use or occupation of subsurface real property. SFPP views these cases as primarily a dispute between UPRR and the plaintiffs. UPRR purported to grant SFPP a network of subsurface pipeline easements along UPRR’s railroad right-of-way. SFPP relied on the validity of those easements and paid rent to UPRR for the value of those easements. We believe we have recorded a right-of-way liability sufficient to cover our potential obligation, if any, for back rent. SFPP and UPRR have engaged in multiple disputes over the circumstances under which SFPP must pay for relocations of its pipeline within the UPRR right-of-way and the safety standards that govern relocations. In 2006, following a bench trial regarding the circumstances under which SFPP must pay for relocations, the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR. The decision was affirmed on appeal. In addition, UPRR contends that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way Association (AREMA) standards in determining when relocations are necessary and in completing relocations. Each party has sought declaratory relief with respect to its positions regarding the application of these standards with respect to relocations. In 2011, a jury verdict was reached that SFPP was obligated to comply with AREMA standards in connection with a railroad project in Beaumont Hills, California. In 2014, the trial court entered judgment against SFPP, consistent with the jury’s verdict. On June 29, 2015, the parties entered into a confidential settlement of all of the claims relating to the project in Beaumont Hills and the case was dismissed. Since SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations, it is difficult to quantify the effects of the outcome of these cases on SFPP. Even if SFPP is successful in advancing its positions, significant relocations for which SFPP must nonetheless bear the cost (i.e., for railroad purposes, with the standards in the federal Pipeline Safety Act applying) could have an adverse effect on our financial position, results of operations, cash flows, and our dividends to our shareholders. These effects could be even greater in the event SFPP is unsuccessful in one or more of these lawsuits. 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. We expect the arbitration panel will issue its decision within approximately six months. 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 intend to contest it vigorously. Plains Gas Solutions, LLC v. Tennessee Gas Pipeline Company, L.L.C. et al. On October 16, 2013, Plains Gas Solutions, LLC (Plains) filed a petition in the 151 st Judicial District Court for Harris County, Texas (Case No. 62528) against TGP, Kinetica Partners, LLC and two other Kinetica entities. The suit arose from the sale by TGP of the Cameron System in Louisiana to Kinetica Partners, LLC on September 1, 2013. Plains alleged that defendants breached a straddle agreement requiring that gas on the Cameron System be committed to Plains’ Grand Chenier gas-processing facility, that requisite daily volume reports were not provided, that TGP improperly assigned its obligations under the straddle agreement to Kinetica, and that defendants interfered with Plains’ contracts with producers. The petition alleged damages of at least $100 million . Under the Amended and Restated Purchase and Sale Agreement with Kinetica, Kinetica is obligated to defend and indemnify TGP in connection with the gas commitment and reporting claims. After agreeing initially to defend and indemnify TGP against such claims, Kinetica withdrew its defense, disputed its indemnity obligation, and settled with Plains. On January 20, 2017, Plains and TGP agreed to release and dismiss their claims and causes of action in the lawsuit with prejudice. Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al. In December 2011 ( Brinckerhoff I ), March 2012, ( Brinckerhoff II ), May 2013 ( Brinckerhoff III ) and June 2014 ( Brinckerhoff IV), derivative lawsuits were filed in Delaware Chancery Court against El Paso Corporation, El Paso Pipeline GP Company, L.L.C., the general partner of EPB, and the directors of the general partner at the time of the relevant transactions. EPB was named in these lawsuits as a “Nominal Defendant.” The lawsuits arise from the March 2010, November 2010, May 2012 and June 2011 drop-down transactions involving EPB’s purchase of SLNG, Elba Express, CPG and interests in SNG and CIG. The lawsuits allege various conflicts of interest and that the consideration paid by EPB was excessive. Brinckerhoff I and II were consolidated into one proceeding. Motions to dismiss were filed in Brinckerhoff III and Brinckerhoff IV, and such motions remain pending. On June 12, 2014, defendants’ motion for summary judgment was granted in Brinckerhoff I, dismissing the case in its entirety. Defendants’ motion for summary judgment in Brinckerhoff II was granted in part, dismissing certain claims and allowing the matter to go to trial in late 2014 on the remaining claims. On April 20, 2015, the Court issued a post-trial memorandum opinion (Memorandum Opinion) in Brinckerhoff II entering judgment in favor of all of the defendants other than the general partner of EPB, but finding the general partner liable for breach of contract in connection with EPB’s purchase of 49% interests in Elba and SLNG and a 15% interest in SNG in a $1.13 billion drop-down transaction that closed on November 19, 2010 (Fall Dropdown), prior to our acquisition of El Paso Corporation in 2012. In its Memorandum Opinion, the Court determined that EPB suffered damages of $171 million from the Fall Dropdown, which the Court determined to be the amount that EPB overpaid for Elba. We believe the claim is derivative in nature and was extinguished by our acquisition on November 26, 2014, pursuant to a merger agreement, of all of the outstanding common units of EPB that we did not already own. On December 2, 2015, the Court denied our motion to dismiss the remaining claims in Brinckerhoff II based upon our acquisition of all of the outstanding common units of EPB, and held that damages should be calculated by considering the unaffiliated unitholders’ ownership percentage as of the effective date of the merger. Based on this ruling, the Court entered judgment on February 4, 2016 in the amount of $100.2 million plus interest at the legal rate for the period from November 15, 2010 until the date of payment, if any payment is ultimately required. We filed an appeal to the Delaware Supreme Court and Brinckerhoff filed a cross-appeal challenging the dismissal of Brinckerhoff I. On December 20, 2016, the Delaware Supreme Court issued an opinion reversing the trial court’s December 2, 2015 decision, finding that the claims were derivative in nature and that Brinckerhoff lost standing to continue both the appeal and cross-appeal when the merger closed. Because its holding terminates the litigation, the Supreme Court did not reach the other issues raised by the parties. On January 5, 2017, the Supreme Court issued a mandate to the trial court reversing the February 4, 2016 judgment in its entirety. On January 30, 2017, the trial court dismissed the case. We continue to believe the transactions at issue were appropriate and in the best interests of EPB. We believe the remaining lawsuits (Brinckerhoff III and IV) should be dismissed on the same grounds, among others, as Brinckerhoff I and II and we intend to continue to defend such 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 Nevada federal court, were dismissed, but the dismissal was reversed by the 9 th Circuit Court of Appeals. The U.S. Supreme Court affirmed the 9 th Circuit Court of Appeals in a decision dated April 21, 2015, and the cases were then remanded to the Nevada federal court for further consideration and trial, if necessary, of numerous remaining issues. On May 24, 2016, the 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 9 th Circuit Court of Appeals. Tentative settlements have been reached in class actions originally filed in Kansas and Missouri, which settlements are subject to court approval. In the remaining case, a Wisconsin class action, approximately $300 million in damages have been alleged against all defendants. 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. Kinder Morgan, Inc. Corporate Reorganization Litigation Certain unitholders of KMP and EPB filed five putative class action lawsuits in the Court of Chancery of the State of Delaware in connection with our November 26, 2014 acquisition, pursuant to three separate merger agreements, of all of the outstanding common units of KMP and EPB and all of the outstanding shares of KMR that we did not already own. The lawsuits were consolidated under the caption In re Kinder Morgan, Inc. Corporate Reorganization Litigation (Consolidated Case No. 10093-VCL). On December 12, 2014, the plaintiffs filed a Verified Second Consolidated Amended Class Action Complaint, which purported to assert claims on behalf of both the former EPB unitholders and the former KMP unitholders. The EPB plaintiff alleged that (i) El Paso Pipeline GP Company, L.L.C. ( EPGP ), the general partner of EPB, and the directors of EPGP breached duties under the EPB partnership agreement, including the implied covenant of good faith and fair dealing, by entering into the EPB Transaction; (ii) EPB, E Merger Sub LLC, KMI and individual defendants aided and abetted such breaches; and (iii) EPB, E Merger Sub LLC, KMI, and individual defendants tortiously interfered with the EPB partnership agreement by causing EPGP to breach its duties under the EPB partnership agreement. The KMP plaintiffs alleged that (i) KMR, KMGP, and individual defendants breached duties under the KMP partnership agreement, including the implied duty of good faith and fair dealing, by entering into the KMP Transaction and by failing to adequately disclose material facts related to the transaction; (ii) KMI aided and abetted such breach; and (iii) KMI, KMP, KMR, P Merger Sub LLC, and individual defendants tortiously interfered with the rights of the plaintiffs and the putative class under the KMP partnership agreement by causing KMGP to breach its duties under the KMP partnership agreement. The complaint sought declaratory relief that the transactions were unlawful and unenforceable, reformation, rescission, rescissory or compensatory damages, interest, and attorneys’ and experts’ fees and costs. On December 30, 2014, the defendants moved to dismiss the complaint. On April 2, 2015, the EPB plaintiff and the defendants submitted a stipulation and proposed order of dismissal, agreeing to dismiss all claims brought by the EPB plaintiff with prejudice as to the EPB lead plaintiff and without prejudice to all other members of the putative EPB class. The Court entered such order on April 2, 2015. On August 24, 2015, the Court issued an order granting the defendants’ motion to dismiss the remaining counts of the complaint for failure to state a claim. On September 21, 2015, plaintiffs filed a notice of appeal to the Supreme Court of the State of Delaware, captioned Haynes Family Trust et al. v. Kinder Morgan G.P., Inc. et al. (Case No. 515). On March 10, 2016, the Delaware Supreme Court affirmed the dismissal of all claims on appeal and this matter is now concluded. 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, 2016 and 2015 , our total reserve for legal matters was $407 million and $463 million , respectively. The reserve primarily relates to various claims from regulatory proceedings arising in our products and natural gas pipeline segments and certain corporate matters. 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 and pays a minimal fee to be part of the group. 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. After a dispute with the EPA concerning certain provision of the FS, the parties agreed that the EPA would complete the FS and that the LWG may dispute the FS within 14 days of the publication of the proposed remedy for cleanup. EPA issued the FS and the Proposed Plan on June 8, 2016. The EPA’s Proposed Plan included a combination of dredging, capping, and enhanced natural recovery. Comments on the FS and the Proposed Plan were submitted by the LWG and on our own behalf on September 7, 2016. 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 has 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. 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 have filed an answer, general denial, and affirmative defenses in response to the Second Amended Complaint and fact discovery is proceeding. Mission Valley Terminal Lawsuit In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the State of California, filed a lawsuit against us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and methyl tertiary butyl ether (MTBE) impacted soils and groundwater beneath the City’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility. The case was filed in the Superior Court of California, San Diego County and was removed in 2007 to the U.S. District Court, Southern District of California (Case No. 07CV1883WCAB). The City disclosed in discovery that it was seeking approximately $170 million in damages for alleged lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property. Later, in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of other claims that increased its claim for damages to approximately $365 million . On November 29, 2012, the Court issued a Notice of Tentative Rulings on the parties’ summary adjudication motions. The Court tentatively granted our partial motions for summary judgment on the City’s claims for water and real estate damages and the State’s claims for violations of California Business and Professions Code § 17200, tentatively denied the City’s motion for summary judgment on its claims of liability for nuisance and trespass, and tentatively granted our cross motion for summary judgment on such claims. On January 25, 2013, the Court rendered judgment in favor of all defendants on all claims asserted by the City. On February 20, 2013, the City of San Diego filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit. On May 21, 2015, the Court of Appeals issued a memorandum decision which affirmed the District Court’s summary judgment in our favor with respect to the City’s claim under California Safe Drinking Water and Toxic Enforcement Act, but reversed both the District Court’s summary judgment decision in our favor on the City’s remaining claims and the District Court’s decision to exclude the City’s expert testimony. The Court of Appeals issued a mandate returning the case to the U.S. District Court. On June 17, 2016, the parties entered into a settlement resolving all claims related to the historical contamination at the City’s stadium property. The settlement provides for a $20 million payment to the City, a waiver and release by the City of all claims which were asserted or could have been asserted in the litigation, and an agreement by defendants to indemnify the City for additional, incremental costs, if any, incurred by the City in the redevelopment of the stadium property or the development of groundwater beneath the stadium property, that would not have been incurred but for the historical releases from the Mission Valley Terminal. By Order dated June 17, 2016, the District Court granted dismissal of the litigation. This site remains under the regulatory oversight and order of the California Regional Water Quality Control Board (RWQCB). SFPP completed the soil and groundwater remediation at the City of San Diego’s stadium property site and conducted quarterly sampling and monitoring through 2015 as part of the compliance evaluation required by the RWQCB. The RWQCB issued a notice of no further action with respect to the stadium property site on May 4, 2016. SFPP’s remediation effort is now fo

Recent Accounting Pronoucements

Recent Accounting Pronoucements (Notes)	12 Months Ended
	Dec. 31, 2016
Accounting Changes and Error Corrections [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. We are in the process of comparing our current revenue recognition policies to the requirements of Topic 606 for each of our revenue categories. While we have not identified any material differences in the amount and timing of revenue recognition for the categories we have reviewed to date, our evaluation is not complete and we have not concluded on the overall impacts of adopting Topic 606. 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 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 will adopt Topic 606 effective January 1, 2018. Topic 606 provides for adoption either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. We plan to make a determination as to our method of adoption once we more fully complete our evaluation of the impacts of the standard on our revenue recognition and we are better able to evaluate the cost-benefit of each method. ASU No. 2014-15 On August 27, 2014, the FASB issued ASU No. 2014-15, “ Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern .” This ASU provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures if management concludes that substantial doubt exists or that its plans alleviate substantial doubt that was raised. We adopted ASU 2014-15 for the year ended December 31, 2016 with no impact to our financial statements. ASU No. 2015-02 On February 18, 2015, the FASB issued ASU No. 2015-02, “ Consolidation (Topic 810) - Amendments to the Consolidated Analysis. ” This ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. We adopted ASU No. 2015-02 effective January 1, 2016 with no impact to our financial statements. 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 do not expect the effect of ASU No. 2015-11 to have a material impact on our financial statements. ASU No. 2016-02 On February 25, 2016, the FASB issued ASU 2016-02, “ Leases (Topic 842) .” This ASU requires that lessees will be required to 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. 2016-05 On March 10, 2016, the FASB issued ASU 2016-05, “ Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships .” This ASU clarifies that for the purposes of applying the guidance in Topic 815, a change in the counterparty to a derivative instrument that has been designated as the hedging instrument in an existing hedging relationship would not, in and of itself, be considered a termination of the derivative instrument. We adopted ASU 2016-05 in the first quarter of 2016 with no material impact to our financial statements. ASU No. 2016-09 On March 30, 2016, the FASB issued ASU 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 do not expect the effect of ASU No. 2016-09 to have a material impact on our financial statements. ASU No. 2016-13 On June 16, 2016, the FASB issued ASU 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. 2016-15 On August 26, 2016, the FASB issued ASU 2016-15, “ Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments (Topic 230) .” This ASU is intended to reduce the diversity in practice around how certain transactions are classified within the statement of cash flows. We adopted ASU No. 2016-15 in the third quarter of 2016 with no material impact to our financial statements. ASU No. 2016-18 On November 17, 2016, the FASB issued ASU 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. ASU No. 2016-18 will be effective for us as of January 1, 2018. We are currently reviewing the effect of this ASU to our financial statements. ASU No. 2017-04 On January 26, 2017, the FASB issued ASU 2017-04, “A SU 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.

Guarantee of Securities of Subs

Guarantee of Securities of Subsidiaries (Notes)	12 Months Ended
	Dec. 31, 2016
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 30, 2016, Copano (previously reflected as a Subsidiary Issuer and Guarantor) repaid the $332 million principal amount of its 7.125% senior notes due 2021. Copano continues to be a subsidiary guarantor under the cross guarantee agreement mentioned above. For all periods presented, financial statement balances and activities for Copano are now reflected within the Subsidiary Guarantor column, and the Subsidiary Issuer and Guarantor-Copano column has been eliminated. 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. Excluding fair value adjustments, as of December 31, 2016, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $14,235 million , $19,485 million , and $4,191 million of Guaranteed Notes outstanding, respectively. Included in the Subsidiary Guarantors debt balance as presented in the accompanying December 31, 2016 condensed consolidating balance sheets are approximately $169 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, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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 December 31, 2016 and 2015 , the gross carrying amounts of these intangible assets was $4,305 million and $4,335 million , respectively and the accumulated amortization was $986 million and $784 million , respectively, resulting in net carrying amounts of $3,318 million and $3,551 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, 2016 , 2015 and 2014 , the amortization expense on our intangibles totaled $223 million , $221 million and $143 million , respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2017 – 2021) is approximately $215 million , $213 million , $211 million , $209 million , and $208 million , respectively. As of December 31, 2016 , the weighted average amortization period for our intangible assets was approximately seventeen years . Other intangibles are evaluated for recoverability consistent with the discussion above on long-lived asset impairments.
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.
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.
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 $103 million and $60 million as of December 31, 2016 and 2015 , 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, 2016 and 2015 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 $39 million and $91 million as of December 31, 2016 and 2015 , respectively. The decrease was primarily associated with certain coal customers’ receivables that were written off in 2016 and had been reserved in prior periods.
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, 2016 and 2015 , our gas imbalance receivables—including both trade and related party receivables—totaled $108 million and $21 million , respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2016 and 2015 , our gas imbalance payables—including both trade and related party payables—totaled $45 million and $17 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, for certain depreciable assets, we employ the composite depreciation method, applying 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. The units-of-production depreciation rate is determined by field and for our oil and gas producing fields that have no proved reserves, the units-of-production depreciation rate is based on each field’s probable reserves and NYMEX forward curve prices. 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, Policy [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 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. Prior to us conducting the 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 [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 $767 million and $808 million as of December 31, 2016 and 2015 , 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, 2016, 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 and $138 million , as of December 31, 2016 and 2015 , respectively. 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. The increase in the equity method goodwill balance from December 31, 2015 is due to the sale of a 50% interest in our SNG natural gas pipeline system, see Note 3.
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 for further information.
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 carbon dioxide producing activities included within operations and maintenance totaled $349 million , $366 million and $403 million for the years ended December 31, 2016, 2015 and 2014, 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” 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 effective. 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 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 income/(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, 2016 and 2015 (in millions): December 31, 2016 2015 Current regulatory assets $ 49 $ 55 Non-current regulatory assets 330 378 Total regulatory assets(a) $ 379 $ 433 Current regulatory liabilities $ 101 $ 161 Non-current regulatory liabilities 108 166 Total regulatory liabilities(b) $ 209 $ 327 _______ (a) Regulatory assets as of December 31, 2016 include (i) $188 million of unamortized losses on disposal of assets; (ii) $107 million income tax gross up on equity AFUDC; and (iii) $84 million of other assets including amounts related to fuel tracker arrangements. Approximately $172 million of the regulatory assets, with a weighted average remaining recovery period of 20 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, 2016 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 $24 million of the $108 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 22 years , while the remaining $84 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, 2016
Income Tax Disclosure [Abstract]
Income Tax Uncertainties, Policy [Policy Text Block]	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, 2016
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, 2016 and 2015 (in millions): December 31, 2016 2015 Current regulatory assets $ 49 $ 55 Non-current regulatory assets 330 378 Total regulatory assets(a) $ 379 $ 433 Current regulatory liabilities $ 101 $ 161 Non-current regulatory liabilities 108 166 Total regulatory liabilities(b) $ 209 $ 327 _______ (a) Regulatory assets as of December 31, 2016 include (i) $188 million of unamortized losses on disposal of assets; (ii) $107 million income tax gross up on equity AFUDC; and (iii) $84 million of other assets including amounts related to fuel tracker arrangements. Approximately $172 million of the regulatory assets, with a weighted average remaining recovery period of 20 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, 2016 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 $24 million of the $108 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 22 years , while the remaining $84 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, 2016 2015 2014 Class P $ 548 $ 214 $ 1,015 Participating securities: Restricted stock awards(a) 4 13 11 Net Income Available to Common Stockholders $ 552 $ 227 $ 1,026 Year Ended December 31, 2016 2015 2014 Basic Weighted Average Common Shares Outstanding 2,230 2,187 1,137 Effect of dilutive securities: Warrants — 6 — Diluted Weighted Average Common Shares Outstanding 2,230 2,193 1,137 ________ (a) As of December 31, 2016 , there were approximately 9 million such restricted stock awards. T
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	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, 2016 2015 2014 Unvested restricted stock awards 8 7 7 Warrants to purchase our Class P shares(a) 293 291 312 Convertible trust preferred securities 8 8 10 Mandatory convertible preferred stock(b) 58 10 n/a _______ n/a - not applicable (a) Each warrant entitles 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, at any time until May 25, 2017. The potential dilutive effect of the warrants does 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 dividends.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	As of December 31, 2016, our preliminary allocation of the purchase price for the BP terminals acquisition and the purchase allocation for other significant acquisitions completed during 2016 , 2015 and 2014 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 ) (4) 11/14 Pennsylvania and Florida Jones Act Tankers 270 — 270 8 25 — (33 ) (5) 1/14 American Petroleum Tankers and State Class Tankers 961 6 951 6 64 — (66 )

Impairments (Tables)

Impairments (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 Natural Gas Pipelines Impairment of goodwill $ — $ 1,150 $ — Impairments of long-lived assets(a) 106 79 — Losses on divestitures of long-lived assets(b) 94 43 5 Impairment of equity investments(c) 606 26 — Impairment at equity investee(d) 7 — — CO 2 Impairments of long-lived assets(e) 20 606 243 Gains on divestitures of long-lived assets (1 ) — — Impairment at equity investee(d) 9 26 — Terminals Impairments of long-lived assets(f) 19 188 — Losses on divestitures of long-lived assets(g) 80 3 29 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 (3 ) Gain on divestiture of equity investment (12 ) — — Other gains on divestitures of long-lived assets (7 ) (1 ) — Pre-tax losses on impairments and divestitures, net $ 1,013 $ 2,125 $ 274 _______ (a) 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) 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) 2016 and 2015 amounts are losses on impairments recorded by equity investees and included in “Earnings from equity investments” in 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. 2014 amount is primarily related to oil and gas properties. (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) 2016 amount primarily relates to an agreement to sell 20 bulk terminals that handle mostly coal and steel products, predominately located along the inland river system. The sale of seven locations closed in the fourth quarter of 2016. (h) 2016 amount represents project write-offs associated with the canceled Palmetto project.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Operating Loss Carryforwards [Line Items]
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, 2016 2015 2014 U.S. $ 1,466 $ 611 $ 2,941 Foreign 172 161 150 Total Income Before Income Taxes $ 1,638 $ 772 $ 3,091
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, 2016 2015 2014 Current tax expense (benefit) Federal $ (148 ) $ (125 ) $ (16 ) State (28 ) (7 ) 36 Foreign 6 4 13 Total (170 ) (128 ) 33 Deferred tax expense (benefit) Federal 998 653 572 State 51 (4 ) 14 Foreign 38 43 29 Total 1,087 692 615 Total tax provision $ 917 $ 564 $ 648
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, 2016 2015 2014 Federal income tax $ 573 35.0 % $ 271 35.0 % $ 1,082 35.0 % Increase (decrease) as a result of: State deferred tax rate change 11 0.7 % (24 ) (3.1 )% — — % Taxes on foreign earnings 28 1.7 % 26 3.5 % 40 1.3 % Net effects of consolidating KMP and EPB and other noncontrolling interests (4 ) (0.3 )% 15 2.0 % (433 ) (14.0 )% State income tax, net of federal benefit 26 1.6 % 12 1.5 % 37 1.2 % Dividend received deduction (48 ) (2.9 )% (51 ) (6.6 )% (50 ) (1.6 )% Adjustments to uncertain tax positions (23 ) (1.4 )% (14 ) (1.9 )% (5 ) (0.2 )% Valuation allowance on investment and tax credits 34 2.1 % — — % 61 2.0 % Disposition of certain international holdings — — % — — % (112 ) (3.6 )% Nondeductible goodwill 301 18.5 % 323 41.7 % — — % Other 19 1.1 % 6 0.8 % 28 0.9 % Total $ 917 56.1 % $ 564 72.9 % $ 648 21.0 %
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Deferred tax assets and liabilities result from the following (in millions): December 31, 2016 2015 Deferred tax assets Employee benefits $ 401 $ 394 Accrued expenses 118 129 Net operating loss, capital loss and tax credit carryforwards 1,307 1,344 Derivative instruments and interest rate and currency swaps 22 45 Debt fair value adjustment 74 110 Investments 2,804 3,607 Other 14 3 Valuation allowances (184 ) (152 ) Total deferred tax assets 4,556 5,480 Deferred tax liabilities Property, plant and equipment 177 143 Other 27 14 Total deferred tax liabilities 204 157 Net deferred tax assets $ 4,352 $ 5,323
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, 2016 2015 2014 Balance at beginning of period $ 148 $ 189 $ 209 Additions based on current year tax positions 3 4 12 Additions based on prior year tax positions 7 — — Reductions based on prior year tax positions (1 ) (6 ) (3 ) Reductions based on settlements with taxing authority (26 ) (25 ) (24 ) Reductions due to lapse in statute of limitations (9 ) (14 ) (5 ) Balance at end of period $ 122 $ 148 $ 189

Property, Plant and Equipment34

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	As of December 31, 2016 and 2015 , our property, plant and equipment, net consisted of the following (in millions): December 31, 2016 2015 Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 19,341 $ 19,855 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 23,298 22,979 Other(a) 4,780 4,719 Accumulated depreciation, depletion and amortization (12,306 ) (10,851 ) 35,113 36,702 Land and land rights-of-way 1,431 1,450 Construction work in process 2,161 2,395 Property, plant and equipment, net $ 38,705 $ 40,547

Investments Investments (Tables

Investments Investments (Tables)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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, 2016 2015 2014 Citrus Corporation $ 102 $ 96 $ 97 SNG 58 — — FEP 51 55 55 Gulf LNG Holdings Group, LLC 48 49 48 MEP 40 45 45 Plantation Pipe Line Company 37 29 29 Watco Companies, LLC 25 16 13 Red Cedar Gathering Company 24 26 33 Cortez Pipeline Company(a) 24 (3 ) 25 Ruby 15 18 15 Parkway Pipeline LLC 14 5 8 NGPL Holdings LLC 12 — — Liberty Pipeline Group LLC 11 9 6 EagleHawk 10 24 (7 ) Sierrita Gas Pipeline LLC 7 9 3 Double Eagle Pipeline LLC 5 3 (1 ) Bear Creek Storage 2 — — Fort Union Gas Gathering L.L.C.(b) 1 16 16 All others 11 17 21 Total earnings from equity investments $ 497 $ 414 $ 406 Amortization of excess costs (59 ) (51 ) (45 ) _______ (a) 2016 and 2015 amounts include $9 million and $26 million , respectively, representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company. (b) 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, 2016 and 2015 , our investments consisted of the following (in millions): December 31, 2016 2015 Citrus Corporation $ 1,709 $ 1,719 SNG 1,505 — Ruby 798 1,093 Gulf LNG Holdings Group, LLC 485 516 NGPL Holdings LLC 475 153 Plantation Pipe Line Company 333 327 EagleHawk 329 348 MEP 328 713 Red Cedar Gathering Company 191 185 Watco Companies, LLC 180 201 Double Eagle Pipeline LLC 151 158 FEP 101 116 Liberty Pipeline Group LLC 75 79 Bear Creek Storage 61 — Sierrita Gas Pipeline LLC 57 60 Utopia Holding LLC 55 — Fort Union Gas Gathering L.L.C. 25 50 Parkway Pipeline LLC — 131 All others 169 183 Total equity investments 7,027 6,032 Bond investments — 8 Total investments $ 7,027 $ 6,040
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, 2016
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, 2016 and 2015 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 $ 5,719 $ 1,528 $ 1,908 $ 221 $ 1,573 $ 591 $ 29,067 Accumulated impairment losses (1,643 ) (447 ) — (1,197 ) (70 ) (679 ) (377 ) (4,413 ) December 31, 2014 15,884 5,272 1,528 711 151 894 214 24,654 Acquisitions(a) — 93 — 217 — 11 — 321 Currency translation — — — — — — (35 ) (35 ) Impairment — (1,150 ) — — — — — (1,150 ) December 31, 2015 15,884 4,215 1,528 928 151 905 179 23,790 Currency translation — — — — — — 6 6 Divestitures(b) (1,635 ) — — — — (9 ) — (1,644 ) December 31, 2016 $ 14,249 $ 4,215 $ 1,528 $ 928 $ 151 $ 896 $ 185 $ 22,152 _______ (a) 2015 includes $93 million and $217 million , respectively, related to the February 2015 acquisition of Hiland by Natural Gas Pipelines Non-Regulated and Products Pipelines, and $7 million related to the February 2015 acquisition of Vopak terminal assets by Terminals, all of which are discussed in Note 3.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 KMI Unsecured term loan facility, variable rate, due January 26, 2019(a) $ 1,000 $ — Senior notes 1.50% through 8.25%, due 2016 through 2098(b)(c) 13,236 13,346 Credit facility expiring November 26, 2019 — — Commercial paper borrowings — — KMP Senior notes, 2.65% through 9.00%, due 2016 through 2044(c) 19,485 19,985 TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(a)(c) 1,540 1,790 EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(c) 1,115 1,115 Copano senior notes, 7.125%, due April 1, 2021(c)(d) — 332 CIG senior notes, 4.15% through 6.85%, due 2026 through 2037(c)(e) 475 100 SNG notes, 4.40% through 8.00%, due 2017 through 2032(c)(f) — 1,211 Other Subsidiary Borrowings (as obligor) Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(a)(c) 786 1,636 Hiland Partners Holdings LLC, senior notes, 5.50% and 7.25%, due 2020 and 2022(c)(g) 225 974 EPC Building, LLC, promissory note, 3.967%, due 2016 through 2035 433 443 Trust I preferred securities, 4.75%, due March 31, 2028(h) 221 221 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(i) 100 100 Other miscellaneous debt(j) 285 300 Total debt – KMI and Subsidiaries 38,901 41,553 Less: Current portion of debt(a)(f)(k) 2,696 821 Total long-term debt – KMI and Subsidiaries(l) $ 36,205 $ 40,732 _______ (a) On January 26, 2016, we entered into a $1 billion three -year unsecured term loan facility with a variable interest rate, which is determined in the same manner as interest on our revolving credit facility borrowings. In January 2016, we repaid $850 million of maturing 5.70% senior notes, and in February 2016, we repaid $250 million of maturing 8.00% senior notes primarily using proceeds from the three-year term loan. Since we refinanced a portion of the maturing debt with proceeds from long-term debt, we classified $1 billion of the maturing debt within “Long-term debt” on our consolidated balance sheet as of December 31, 2015. (b) Amounts include senior notes that are denominated in Euros and have been converted and are respectively reported above at the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro and the December 31, 2015 exchange rate of 1.0862 U.S. dollars per Euro. For the year ended December 31, 2016 , our debt decreased by $43 million as a result of the change in the exchange rate of U.S dollars per Euro. The decrease 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 ”). (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) On September 30, 2016, we repaid the $332 million principal amount of 7.125% senior notes due 2021, plus accrued interest. We recognized a $28.3 million gain from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2016 consisting of an $11.8 million premium on the debt repaid and a $40.1 million gain from the write-off of unamortized purchase accounting associated with the extinguished debt. Copano continues to be a subsidiary guarantor under a cross guarantee agreement (see Note 19). (e) On August 16, 2016, CIG completed a private offering of $375 million in principal amount of 4.15% senior notes due August 15, 2026. The net proceeds of $372 million received from the offering were used to reduce debt incurred as the result of the repayment of CIG’s senior notes that matured in 2015 and for general corporate purposes. (f) Due to the September 1, 2016 sale of a 50% interest in SNG, we no longer consolidate SNG’s accounts in our consolidated financial statements. As of the transaction date, SNG had $1,211 million of debt outstanding (including a current portion of $500 million ). (g) On October 1, 2016, a portion of the proceeds from the sale of a 50% interest in SNG was used to repay the $749 million principal amount of Hiland’s 7.25% senior notes due 2020, plus accrued interest. We recognized a $17.3 million gain from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2016 consisting of a $27.1 million premium on the debt repaid and a $44.4 million gain from the write-off of unamortized purchase accounting associated with the extinguished debt. (h) Capital Trust I (Trust I), is a 100% -owned business trust that as of December 31, 2016 , 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. 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, 2016 , the outstanding balance of $221 million (of which $111 million was classified as current) was bifurcated between debt ( $199 million ) and equity ( $22 million ). During the years ended December 31, 2016 and 2015 , 200 and 1,176,015 , respectively, of Trust I Preferred Securities had been converted into (i) 143 and 846,369 shares of our Class P common stock; (ii) approximately $5,000 and $30 million in cash; and (iii) 220 and 1,293,615 in warrants, respectively. (i) As of December 31, 2016 and 2015, 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. (j) 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, 2016 , the principal amounts of the Totem and High Plains financing obligations were $71 million and $92 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. (k) Amounts include outstanding credit facility and commercial paper borrowings and other debt maturing within 12 months. See “—Maturities of Debt” below. (l) Excludes our “Debt fair value adjustments” which, as of December 31, 2016 and 2015 , increased our combined debt balances by $1,149 million and $1,674 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. Credit Facilities and Restrictive Covenants 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. As of December 31, 2016 , we were in compliance with all required financial covenants. Our credit facility included the following restrictive covenants as of December 31, 2016 : • 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, 2016 , we had no borrowings outstanding under our five -year $5.0 billion revolving credit facility, no borrowings outstanding under our $4.0 billion commercial paper program and $160 million in letters of credit. Our availability under our revolving credit facility as of December 31, 2016 was $4,840 million . Current Portion of Debt The primary components of our current portion of debt include the following significant series of long-term notes: As of December 31, 2016 $600 million 6.00% notes due February 2017 $300 million 7.50% notes due April 2017 $355 million 5.95% notes due April 2017 $786 million 7.00% notes due June 2017 $500 million 2.00% notes due December 2017 As of December 31, 2015 $500 million 3.50% notes due March 2016 Long-term Debt Issuances, Repayments and Other Significant Changes in Debt Following are significant long-term debt issuances, repayments and other significant changes made during 2016 and 2015 : 2016 2015 Issuances $1.0 billion unsecured term loan facility due 2019 $800 million 5.05% notes due 2046 $375 million 4.15% notes due 2026 $815 million 1.50% notes due 2022(a) $543 million 2.25% notes due 2027(a) Repayments $850 million 5.70% notes due 2016 $300 million 5.625% notes due 2015 $500 million 3.50% notes due 2016 $250 million 5.15% notes due 2015 $250 million 8.00% notes due 2016 $340 million 6.80% notes due 2015 $67 million 8.25% notes due 2016 $375 million 4.10% notes due 2015 $332 million 7.125% notes due 2021 $749 million 7.25% notes due 2020 Other significant changes $1,211 million reduction due to the deconsolidation of SNG, including a current portion of $500 million (see Note 3) $1,413 million assumption of senior notes and other borrowings due to the Hiland acquisition of which $368 million was immediately paid down after closing (see Note 3)(b) _______ (a) Senior notes are denominated in Euros and are presented above in U.S. dollars at the exchange rate on the issuance date of 1.0862 U.S. dollars per Euro. We entered into cross-currency swap agreements associated with these senior notes (see Note 14—“Risk Management—Foreign Currency Risk Management”). (b) As of the February 13, 2015 Hiland acquisition date, we assumed (i) $975 million in principal amount of senior notes (which were valued at $1,043 million as of the acquisition date) and (ii) $368 million of other borrowings that were immediately repaid after closing, primarily consisting of borrowings outstanding under a revolving credit facility. The senior notes are subject to our cross guarantee agreement discussed in Note 19. Maturities of Debt The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2016 , are summarized as follows (in millions): Year Total 2017 $ 2,696 2018 2,328 2019 3,820 2020 2,204 2021 2,422 Thereafter 25,431 Total $ 38,901 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, 2016 , 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 2016 2015 Purchase accounting debt fair value adjustments $ 806 $ 1,135 Carrying value adjustment to hedged debt 220 380 Unamortized portion of proceeds received from the early termination of interest rate swap agreements 342 397 Unamortized debt discount/premiums (80 ) (86 ) Unamortized debt issuance costs (139 ) (152 ) Total debt fair value adjustments $ 1,149 $ 1,674 Interest Rates, Interest Rate Swaps and Contingent Debt The weighted average interest rate on all of our borrowings was 4.95% during 2016 and 4.92% during 2015 . Information on our interest rate swaps is contained in Note 14. For information about our contingent debt agreements, see Note 13 “Commitments and Contingent Liabilities— Contingent Debt ”).
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, 2016 2015 KMI Unsecured term loan facility, variable rate, due January 26, 2019(a) $ 1,000 $ — Senior notes 1.50% through 8.25%, due 2016 through 2098(b)(c) 13,236 13,346 Credit facility expiring November 26, 2019 — — Commercial paper borrowings — — KMP Senior notes, 2.65% through 9.00%, due 2016 through 2044(c) 19,485 19,985 TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(a)(c) 1,540 1,790 EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(c) 1,115 1,115 Copano senior notes, 7.125%, due April 1, 2021(c)(d) — 332 CIG senior notes, 4.15% through 6.85%, due 2026 through 2037(c)(e) 475 100 SNG notes, 4.40% through 8.00%, due 2017 through 2032(c)(f) — 1,211 Other Subsidiary Borrowings (as obligor) Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(a)(c) 786 1,636 Hiland Partners Holdings LLC, senior notes, 5.50% and 7.25%, due 2020 and 2022(c)(g) 225 974 EPC Building, LLC, promissory note, 3.967%, due 2016 through 2035 433 443 Trust I preferred securities, 4.75%, due March 31, 2028(h) 221 221 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(i) 100 100 Other miscellaneous debt(j) 285 300 Total debt – KMI and Subsidiaries 38,901 41,553 Less: Current portion of debt(a)(f)(k) 2,696 821 Total long-term debt – KMI and Subsidiaries(l) $ 36,205 $ 40,732 _______ (a) On January 26, 2016, we entered into a $1 billion three -year unsecured term loan facility with a variable interest rate, which is determined in the same manner as interest on our revolving credit facility borrowings. In January 2016, we repaid $850 million of maturing 5.70% senior notes, and in February 2016, we repaid $250 million of maturing 8.00% senior notes primarily using proceeds from the three-year term loan. Since we refinanced a portion of the maturing debt with proceeds from long-term debt, we classified $1 billion of the maturing debt within “Long-term debt” on our consolidated balance sheet as of December 31, 2015. (b) Amounts include senior notes that are denominated in Euros and have been converted and are respectively reported above at the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro and the December 31, 2015 exchange rate of 1.0862 U.S. dollars per Euro. For the year ended December 31, 2016 , our debt decreased by $43 million as a result of the change in the exchange rate of U.S dollars per Euro. The decrease 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 ”). (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) On September 30, 2016, we repaid the $332 million principal amount of 7.125% senior notes due 2021, plus accrued interest. We recognized a $28.3 million gain from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2016 consisting of an $11.8 million premium on the debt repaid and a $40.1 million gain from the write-off of unamortized purchase accounting associated with the extinguished debt. Copano continues to be a subsidiary guarantor under a cross guarantee agreement (see Note 19). (e) On August 16, 2016, CIG completed a private offering of $375 million in principal amount of 4.15% senior notes due August 15, 2026. The net proceeds of $372 million received from the offering were used to reduce debt incurred as the result of the repayment of CIG’s senior notes that matured in 2015 and for general corporate purposes. (f) Due to the September 1, 2016 sale of a 50% interest in SNG, we no longer consolidate SNG’s accounts in our consolidated financial statements. As of the transaction date, SNG had $1,211 million of debt outstanding (including a current portion of $500 million ). (g) On October 1, 2016, a portion of the proceeds from the sale of a 50% interest in SNG was used to repay the $749 million principal amount of Hiland’s 7.25% senior notes due 2020, plus accrued interest. We recognized a $17.3 million gain from the early extinguishment of debt, included within “Interest, net” on the accompanying consolidated statements of income for the year ended December 31, 2016 consisting of a $27.1 million premium on the debt repaid and a $44.4 million gain from the write-off of unamortized purchase accounting associated with the extinguished debt. (h) Capital Trust I (Trust I), is a 100% -owned business trust that as of December 31, 2016 , 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. 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, 2016 , the outstanding balance of $221 million (of which $111 million was classified as current) was bifurcated between debt ( $199 million ) and equity ( $22 million ). During the years ended December 31, 2016 and 2015 , 200 and 1,176,015 , respectively, of Trust I Preferred Securities had been converted into (i) 143 and 846,369 shares of our Class P common stock; (ii) approximately $5,000 and $30 million in cash; and (iii) 220 and 1,293,615 in warrants, respectively. (i) As of December 31, 2016 and 2015, 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. (j) 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, 2016 , the principal amounts of the Totem and High Plains financing obligations were $71 million and $92 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. (k) Amounts include outstanding credit facility and commercial paper borrowings and other debt maturing within 12 months. See “—Maturities of Debt” below. (l) Excludes our “Debt fair value adjustments” which, as of December 31, 2016 and 2015 , increased our combined debt balances by $1,149 million and $1,674 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 Significant Long-Term Debt Issuances, Repayments and Other Significant Changes in Debt [Table Text Block]	Following are significant long-term debt issuances, repayments and other significant changes made during 2016 and 2015 : 2016 2015 Issuances $1.0 billion unsecured term loan facility due 2019 $800 million 5.05% notes due 2046 $375 million 4.15% notes due 2026 $815 million 1.50% notes due 2022(a) $543 million 2.25% notes due 2027(a) Repayments $850 million 5.70% notes due 2016 $300 million 5.625% notes due 2015 $500 million 3.50% notes due 2016 $250 million 5.15% notes due 2015 $250 million 8.00% notes due 2016 $340 million 6.80% notes due 2015 $67 million 8.25% notes due 2016 $375 million 4.10% notes due 2015 $332 million 7.125% notes due 2021 $749 million 7.25% notes due 2020 Other significant changes $1,211 million reduction due to the deconsolidation of SNG, including a current portion of $500 million (see Note 3) $1,413 million assumption of senior notes and other borrowings due to the Hiland acquisition of which $368 million was immediately paid down after closing (see Note 3)(b) _______ (a) Senior notes are denominated in Euros and are presented above in U.S. dollars at the exchange rate on the issuance date of 1.0862 U.S. dollars per Euro. We entered into cross-currency swap agreements associated with these senior notes (see Note 14—“Risk Management—Foreign Currency Risk Management”). (b) As of the February 13, 2015 Hiland acquisition date, we assumed (i) $975 million in principal amount of senior notes (which were valued at $1,043 million as of the acquisition date) and (ii) $368 million of other borrowings that were immediately repaid after closing, primarily consisting of borrowings outstanding under a revolving credit facility. The senior notes are subject to our cross guarantee agreement discussed in Note 19.
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, 2016 , are summarized as follows (in millions): Year Total 2017 $ 2,696 2018 2,328 2019 3,820 2020 2,204 2021 2,422 Thereafter 25,431 Total $ 38,901
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 2016 2015 Purchase accounting debt fair value adjustments $ 806 $ 1,135 Carrying value adjustment to hedged debt 220 380 Unamortized portion of proceeds received from the early termination of interest rate swap agreements 342 397 Unamortized debt discount/premiums (80 ) (86 ) Unamortized debt issuance costs (139 ) (152 ) Total debt fair value adjustments $ 1,149 $ 1,674

Share-based Compensation and 38

Share-based Compensation and Employee Benefits Share-based Compensation and Employee Benefits (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 December 31, 2015 December 31, 2014 Shares Weighted Average Shares Weighted Average Shares Weighted Average Grant Date Fair Value Outstanding at beginning of period 7,645,105 $ 37.91 7,373,294 $ 37.63 6,382,885 $ 37.38 Granted 2,816,599 21.36 1,488,467 38.20 1,694,668 36.01 Vested (1,226,652 ) 38.53 (817,797 ) 35.66 (460,032 ) 28.84 Forfeited (196,915 ) 35.74 (398,859 ) 38.51 (244,227 ) 36.39 Outstanding at end of period 9,038,137 $ 32.72 7,645,105 $ 37.91 7,373,294 $ 37.63
Schedule of Share-based Compensation Arrangement 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 2017 1,476,832 2018 2,352,443 2019 4,358,728 2020 539,790 2021 199,850 Thereafter 110,494 Total Outstanding 9,038,137
Schedule of Defined Benefit Plans Disclosures [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, 2016 and 2015 (in millions): Pension Benefits OPEB 2016 2015 2016 2015 Change in benefit obligation: Benefit obligation at beginning of period $ 2,654 $ 2,804 $ 509 $ 624 Service cost 36 33 1 — Interest cost 89 99 16 21 Actuarial loss (gain) 127 (109 ) (42 ) (101 ) Benefits paid (180 ) (173 ) (41 ) (39 ) Participant contributions 3 — 2 2 Medicare Part D subsidy receipts — — 1 2 Exchange rate changes 4 — 1 — Other(a) 151 — 26 — Benefit obligation at end of period 2,884 2,654 473 509 Change in plan assets: Fair value of plan assets at beginning of period 2,050 2,377 325 389 Actual return (loss) on plan assets 157 (204 ) 29 (45 ) Employer contributions 8 50 16 16 Participant contributions 3 — 2 2 Medicare Part D subsidy receipts — — 1 2 Benefits paid (180 ) (173 ) (41 ) (39 ) Exchange rate changes 3 — — — Other(a) 119 — — — Fair value of plan assets at end of period 2,160 2,050 332 325 Funded status - net liability at December 31, $ (724 ) $ (604 ) $ (141 ) $ (184 ) _______ (a) 2016 amounts represent December 31, 2015 balances associated with our Canadian pension and OPEB plans and Plantation Pipeline OPEB plan for prospective inclusion in these disclosures, which associated net periodic benefit costs were reported separately in prior years.
Schedule of Net Funded Status [Table Text Block]	Components of Funded Status . The following table details the amounts recognized in our balance sheet at December 31, 2016 and 2015 related to our pension and OPEB plans (in millions): Pension Benefits OPEB 2016 2015 2016 2015 Non-current benefit asset(a) $ — $ — $ 153 $ 139 Current benefit liability — — (16 ) (16 ) Non-current benefit liability(a) (724 ) (604 ) (278 ) (307 ) Funded status - net liability at December 31, $ (724 ) $ (604 ) $ (141 ) $ (184 ) _______ (a) 2016 OPEB amount includes $29 million of non-current benefit assets and $12 million of non-current benefit liabilities related to plans we sponsor which are associated with employee services provided to unconsolidated joint ventures, and for which we have recorded an offsetting related party deferred charge/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, 2016 and 2015 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 2016 2015 2016 2015 Unrecognized net actuarial (loss) gain $ (682 ) $ (558 ) $ 69 $ 23 Unrecognized prior service (cost) credit (5 ) (4 ) 18 19 Accumulated other comprehensive (loss) income $ (687 ) $ (562 ) $ 87 $ 42
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, 2016 and 2015 (in millions): Pension Assets 2016 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Cash $ 10 $ — $ — $ 10 $ 15 $ — $ — $ 15 Short-term investment funds — 100 — 100 — 110 — 110 Mutual funds(a) 197 — — 197 70 — — 70 Equities(b) 283 — — 283 271 — — 271 Fixed income securities — 428 — 428 — 449 — 449 Immediate participation guarantee contract — — 16 16 — — 15 15 Derivatives — (2 ) — (2 ) — (14 ) — (14 ) Subtotal $ 490 $ 526 $ 16 1,032 $ 356 $ 545 $ 15 916 Measured at NAV(c) Common/collective trusts(d) 829 775 Private investment funds(e) 290 347 Private limited partnerships(f) 9 12 Subtotal 1,128 1,134 Total plan assets fair value $ 2,160 $ 2,050 _______ (a) For 2016 and 2015 , this category includes mutual funds which are invested in equity. (b) Plan assets include $126 million and $91 million of KMI Class P common stock for 2016 and 2015 , respectively. (c) Plan assets for which fair value was measured using NAV as a practical expedient. (d) Common/collective trust funds were invested in approximately 39% fixed income and 61% equity in 2016 and 45% fixed income and 55% equity in 2015 . (e) Private investment funds were invested in approximately 54% fixed income and 46% equity in 2016 and 46% fixed income and 54% equity in 2015 . (f) Private limited partnerships were invested in real estate, venture and buyout funds for 2016 and 2015 . OPEB Assets 2016 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Short-term investment funds $ — $ 15 $ — $ 15 $ — $ 16 $ — $ 16 Equities 11 — — 11 8 — — 8 Master limited partnerships 57 — — 57 51 — — 51 Guaranteed insurance contracts — — 47 47 — — 49 49 Mutual funds 1 — — 1 1 — — 1 Subtotal $ 69 $ 15 $ 47 131 $ 60 $ 16 $ 49 125 Measured at NAV(a) Common/collective trusts(b) 68 71 Fixed income trusts 64 58 Limited partnerships(c) 69 71 Subtotal 201 200 Total plan assets fair value $ 332 $ 325 _______ (a) Plan assets for which fair value was measured using NAV as a practical expedient. (b) Common/collective trust funds which are invested in approximately 72% equity and 28% fixed income securities for 2016 and 67% equity and 33% fixed income securities for 2015. (c) For 2016 and 2015 , 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, 2016 and 2015 (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 2016 Insurance contracts $ 15 $ — $ 1 $ — $ 16 2015 Insurance contracts $ 15 $ — $ — $ — $ 15 OPEB Assets Balance at Beginning of Period Transfers In (Out) Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period 2016 Insurance contracts $ 49 $ — $ (2 ) $ — $ 47 2015 Insurance contracts $ 51 $ — $ (1 ) $ (1 ) $ 49 Changes in the underlying value of Level 3 assets due to the effect of changes of fair value were immaterial for the years ended December 31, 2016 and 2015 .
Schedule of Expected Benefit Payments [Table Text Block]	d 2015 . Expected Payment of Future Benefits and Employer Contributions . As of December 31, 2016 , we expect to make the following benefit payments under our plans (in millions): Fiscal year Pension Benefits OPEB(a) 2017 $ 235 $ 39 2018 237 38 2019 232 39 2020 231 37 2021 220 37 2022 - 2026 1,016 168 _______ (a) Includes a reduction of approximately $3 million in each of the years 2017 - 2021 and approximately $16 million in aggregate for 2022 - 2026 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
Schedule or Description of Weighted Average Discount Rate [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 2016 , 2015 and 2014 : Pension Benefits OPEB 2016 2015 2014 2016 2015 2014 Assumptions related to benefit obligations: Discount rate 3.83 % 4.05 % 3.66 % 3.69 % 3.91 % 3.56 % Rate of compensation increase 3.52 % 3.50 % 4.50 % n/a n/a n/a Assumptions related to benefit costs: Discount rate for benefit obligations 4.05 % 3.66 % 4.45 % 3.91 % 3.56 % 4.34 % Discount rate for interest on benefit obligations 3.24 % 3.66 % 4.45 % 3.18 % 3.56 % 4.34 % Discount rate for service cost 4.15 % 3.66 % 4.45 % 4.36 % 3.56 % 4.34 % Discount rate for interest on service cost 3.50 % 3.66 % 4.45 % 4.17 % 3.56 % 4.34 % Expected return on plan assets(a) 7.31 % 7.50 % 7.50 % 7.07 % 7.08 % 7.43 % Rate of compensation increase 3.51 % 4.50 % 3.50 % 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 2016 , 2015 and 2014 .
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, 2016 and 2015 (in millions): 2016 2015 One-percentage point increase: Aggregate of service cost and interest cost $ 1 $ 2 Accumulated postretirement benefit obligation 27 31 One-percentage point decrease: Aggregate of service cost and interest cost $ (1 ) $ (1 ) Accumulated postretirement benefit obligation (23 ) (27 )
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 2016 2015 2014 2016 2015 2014 Components of net benefit cost: Service cost $ 36 $ 33 $ 21 $ 1 $ — $ — Interest cost 89 99 112 16 21 25 Expected return on assets (151 ) (172 ) (171 ) (19 ) (23 ) (24 ) Amortization of prior service cost (credit) 1 — — (3 ) (3 ) (2 ) Amortization of net actuarial loss (gain) 35 5 — — 1 (1 ) Net benefit (credit) cost(a) 10 (35 ) (38 ) (5 ) (4 ) (2 ) Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 116 267 285 (48 ) (49 ) 10 Prior service cost (credit) arising during period — — — — — — Amortization or settlement recognition of net actuarial loss (34 ) (5 ) — — (1 ) — Amortization of prior service credit — — — 1 1 1 Exchange rate changes 1 — — — — — Total recognized in total other comprehensive (income) loss 83 262 285 (47 ) (49 ) 11 Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ 93 $ 227 $ 247 $ (52 ) $ (53 ) $ 9 _______ (a) 2016 OPEB amount includes $4 million of net benefit credits related to plans that we sponsor that are associated with employee services provided to unconsolidated joint ventures. We charge or refund these costs or credits associated with these plans 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, 2016
Stockholders' Equity Note [Abstract]
Schedule of Distributions by Noncontrolling Interests [Table Text Block]	The following table provides information about distributions from our noncontrolling interests (in millions except per unit and i-unit distribution amounts): Year Ended December 31, 2014 KMP(a) Per unit cash distribution declared for the period $ 4.17 Per unit cash distribution paid in the period $ 5.53 Cash distributions paid in the period to the public $ 1,654 EPB(a) Per unit cash distribution declared for the period $ 1.95 Per unit cash distribution paid in the period $ 2.60 Cash distributions paid in the period to the public $ 347 KMR(a)(b) Share distributions paid in the period to the public 7,794,183 _______ (a) As a result of the Merger Transactions, no distribution was declared starting with the fourth quarter of 2014. (b) KMR’s distributions were paid in the form of additional shares or fractions thereof calculated by dividing the KMP cash distribution per common unit by the average of the market closing prices of a KMR share determined for a ten-trading day period ending on the trading day immediately prior to the ex-dividend date for the shares. Represents share distributions made in the period to noncontrolling interests and excludes 1,127,712 of shares distributed in 2014 on KMR shares we directly and indirectly owned.
Schedule of Dividends Payable [Table Text Block]	The following table provides information about our per share dividends: Year Ended December 31, 2016 2015 2014 Per common share cash dividend declared for the period $ 0.50 $ 1.605 $ 1.74 Per common share cash dividend paid in the period 0.50 1.93 1.70
Schedule of Warrants Outstanding Roll Forward [Table Text Block]	The table below sets forth the changes in our outstanding warrants: Warrants 2016 2015 2014 Beginning balance 293,263,797 298,135,976 347,933,107 Warrants issued with conversions of EP Trust I Preferred securities(a) — 1,293,615 4,315 Warrants exercised — (71,268 ) (18,040 ) Warrants repurchased and canceled — (6,094,526 ) (49,783,406 ) Ending balance 293,263,797 293,263,797 298,135,976 _______ (a) See Note 9.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Schedule of Related Party Transactions [Table Text Block]	The following tables summarize our affiliate balance sheet balances and income statement activity (in millions): December 31, 2016 2015 Balance sheet location Accounts receivable, net $ 37 $ 25 Other current assets — 36 Deferred charges and other assets 10 — $ 47 $ 61 Current portion of debt $ 6 $ 6 Accounts payable 28 22 Other current liabilities 9 10 Long-term debt 161 167 Other long-term liabilities and deferred credits 29 — $ 233 $ 205 Year Ended December 31, 2016 2015 2014 Income statement location Revenues Services $ 71 $ 72 $ 29 Product sales and other 71 71 86 $ 142 $ 143 $ 115 Operating Costs, Expenses and Other Costs of sales $ 38 $ 60 $ 74 Other operating expenses 75 55 57

Commitments and Contingent Li41

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 (in millions): Year Commitment 2017 $ 106 2018 94 2019 86 2020 75 2021 61 Thereafter 342 Total minimum payments $ 764

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments [Table Text Block]	As of December 31, 2016 , 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 (19.7 ) MMBbl Crude oil basis (1.3 ) MMBbl Natural gas fixed price (38.4 ) Bcf Natural gas basis (19.3 ) Bcf Derivatives not designated as hedging contracts Crude oil fixed price (1.7 ) MMBbl Crude oil basis (0.1 ) MMBbl Natural gas fixed price (5.2 ) Bcf Natural gas basis (1.4 ) Bcf NGL and other fixed price (5.0 ) MMBbl
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets (in millions): Fair Value of Derivative Contracts Asset derivatives Liability derivatives December 31, December 31, 2016 2015 2016 2015 Location Fair value Fair value Derivatives designated as hedging contracts Natural gas and crude derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 101 $ 359 $ (57 ) $ (13 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 70 244 (24 ) — Subtotal 171 603 (81 ) (13 ) Interest rate swap agreements Fair value of derivative contracts/(Other current liabilities) 94 111 — — Deferred charges and other assets/(Other long-term liabilities and deferred credits) 206 273 (57 ) (9 ) Subtotal 300 384 (57 ) (9 ) Cross-currency swap agreements Fair value of derivative contracts/(Other current liabilities) — — (7 ) (6 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (24 ) (46 ) Subtotal — — (31 ) (52 ) Total 471 987 (169 ) (74 ) Derivatives not designated as hedging contracts Natural gas, crude, NGL and other derivative contracts Fair value of derivative contracts/(Other current liabilities) 3 35 (29 ) (1 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (1 ) — Subtotal 3 35 (30 ) (1 ) Interest rate swap agreements Fair value of derivative contracts/(Other current liabilities) — 1 — (11 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — — (5 ) Subtotal — 1 — (16 ) Power derivative contracts Fair value of derivative contracts/(Other current liabilities) — 1 — (17 ) Subtotal — 1 — (17 ) Total 3 37 (30 ) (34 ) Total derivatives $ 474 $ 1,024 $ (199 ) $ (108 )
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, 2016 2015 2014 Interest rate swap agreements Interest, net $ (180 ) $ 25 $ 207 Hedged fixed rate debt Interest, net $ 160 $ (33 ) $ (204 ) 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, 2016 2015 2014 2016 2015 2014 2016 2015 2014 Energy commodity derivative contracts $ (115 ) $ 201 $ 424 Revenues—Natural gas sales $ 15 $ 54 $ (1 ) Revenues—Natural gas sales $ — $ — $ — Revenues—Product sales and other 148 236 26 Revenues—Product sales and other (12 ) 2 11 Costs of sales (17 ) (15 ) 4 Costs of sales — — — Interest rate swap agreements(c) (2 ) (4 ) (15 ) Interest, net (3 ) (3 ) (4 ) Interest, net — — — Cross-currency swap 13 (33 ) — Other, net (27 ) — — Other, net — — — Total $ (104 ) $ 164 $ 409 Total $ 116 $ 272 $ 25 Total $ (12 ) $ 2 $ 11 _______ (a) We expect to reclassify an approximate $8 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of December 31, 2016 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, 2016 2015 2014 Energy commodity derivative contracts Revenues—Natural gas sales $ (10 ) $ 17 $ (7 ) Revenues—Product sales and other (26 ) 176 20 Costs of sales 3 (2 ) — Other (income) expense, net — — (2 ) Interest rate swap agreements Interest, net 63 (15 ) — Total(a) $ 30 $ 176 $ 11 ________ (a) For the years ended December 31, 2016 and 2015, includes an approximate gain of $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, 2013 $ (3 ) $ 2 $ (23 ) $ (24 ) Other comprehensive gain (loss) before reclassifications 254 (68 ) (212 ) (26 ) Gains reclassified from accumulated other comprehensive loss (22 ) — (1 ) (23 ) Impact of Merger Transactions (See Note 1) 98 (42 ) — 56 Net current-period other comprehensive income (loss) 330 (110 ) (213 ) 7 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 )

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 Energy commodity derivative contracts(a) $ 6 $ 168 $ — $ 174 $ (43 ) $ — $ 131 Interest rate swap agreements $ — $ 300 $ — $ 300 $ (18 ) $ — $ 282 As of December 31, 2015 Energy commodity derivative contracts(a) $ 48 $ 589 $ 2 $ 639 $ (12 ) $ (37 ) $ 590 Interest rate swap agreements $ — $ 385 $ — $ 385 $ (8 ) $ — $ 377 Balance sheet liability fair value measurements by level Level 1 Level 2 Level 3 Gross amount Contracts available for netting Collateral posted(c) Net amount 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 ) As of December 31, 2015 Energy commodity derivative contracts(a) $ (4 ) $ (10 ) $ (17 ) $ (31 ) $ 12 $ — $ (19 ) Interest rate swap agreements $ — $ (25 ) $ — $ (25 ) $ 8 $ — $ (17 ) Cross-currency swap agreements $ — $ (52 ) $ — $ (52 ) $ — $ — $ (52 ) _______ (a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and options and NGL swaps. Level 3 consists primarily of power derivative contracts. (b) Cash margin deposits held by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities” on our accompanying consolidated balance sheets. (c) Cash margin deposits posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Restricted Deposits” on our accompanying consolidated balance sheets.
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, 2016 2015 Derivatives-net asset (liability) Beginning of period $ (15 ) $ (61 ) Total gains or (losses) included in earnings (9 ) (13 ) Settlements 24 59 End of period $ — $ (15 ) 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, 2016 December 31, 2015 Carrying value Estimated fair value Carrying value Estimated fair value Total debt $ 40,050 $ 41,015 $ 43,227 $ 37,481

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Financial information by segment follows (in millions): Year Ended December 31, 2016 2015 2014 Revenues Natural Gas Pipelines Revenues from external customers $ 7,998 $ 8,704 $ 10,153 Intersegment revenues 7 21 15 CO 2 1,221 1,699 1,960 Terminals Revenues from external customers 1,921 1,878 1,717 Intersegment revenues 1 1 1 Products Pipelines Revenues from external customers 1,631 1,828 2,068 Intersegment revenues 18 3 — Kinder Morgan Canada 253 260 291 Corporate and intersegment eliminations(a) 8 9 21 Total consolidated revenues $ 13,058 $ 14,403 $ 16,226 Year Ended December 31, 2016 2015 2014 Operating expenses(b) Natural Gas Pipelines $ 4,393 $ 4,738 $ 6,241 CO 2 399 432 494 Terminals 768 836 746 Products Pipelines 573 772 1,258 Kinder Morgan Canada 87 87 106 Corporate and intersegment eliminations 2 26 8 Total consolidated operating expenses $ 6,222 $ 6,891 $ 8,853 Year Ended December 31, 2016 2015 2014 Other expense (income)(c) Natural Gas Pipelines $ 199 $ 1,269 $ 5 CO 2 19 606 243 Terminals 99 190 29 Products Pipelines 76 2 (3 ) Kinder Morgan Canada — (1 ) — Corporate (7 ) — 1 Total consolidated other expense (income) $ 386 $ 2,066 $ 275 Year Ended December 31, 2016 2015 2014 DD&A Natural Gas Pipelines $ 1,041 $ 1,046 $ 897 CO 2 446 556 570 Terminals 435 433 337 Products Pipelines 221 206 166 Kinder Morgan Canada 44 46 51 Corporate 22 22 19 Total consolidated DD&A $ 2,209 $ 2,309 $ 2,040 Year Ended December 31, 2016 2015 2014 Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments Natural Gas Pipelines $ (269 ) $ 285 $ 279 CO 2 22 (5 ) 26 Terminals 19 17 18 Products Pipelines 56 36 37 Corporate — — 1 Total consolidated equity earnings $ (172 ) $ 333 $ 361 Year Ended December 31, 2016 2015 2014 Other, net-income (expense) Natural Gas Pipelines $ 19 $ 24 $ 24 Terminals 4 8 12 Products Pipelines 2 4 (1 ) Kinder Morgan Canada 15 8 15 Corporate 4 (1 ) 30 Total consolidated other, net-income (expense) $ 44 $ 43 $ 80 Year Ended December 31, 2016 2015 2014 Segment EBDA(d) Natural Gas Pipelines $ 3,211 $ 3,067 $ 4,264 CO 2 827 658 1,248 Terminals 1,078 878 973 Products Pipelines 1,067 1,106 856 Kinder Morgan Canada 181 182 200 Total segment EBDA 6,364 5,891 7,541 DD&A (2,209 ) (2,309 ) (2,040 ) Amortization of excess cost of equity investments (59 ) (51 ) (45 ) General and administrative expenses (669 ) (690 ) (610 ) Interest expense, net (1,806 ) (2,051 ) (1,798 ) Corporate(a) 17 (18 ) 43 Income tax expense (917 ) (564 ) (648 ) Total consolidated net income $ 721 $ 208 $ 2,443 Year Ended December 31, 2016 2015 2014 Capital expenditures Natural Gas Pipelines $ 1,227 $ 1,642 $ 935 CO 2 276 725 792 Terminals 983 847 1,049 Products Pipelines 244 524 680 Kinder Morgan Canada 124 142 156 Corporate 28 16 5 Total consolidated capital expenditures $ 2,882 $ 3,896 $ 3,617 2016 2015 Investments at December 31 Natural Gas Pipelines $ 6,185 $ 5,080 Terminals 252 306 Products Pipelines 566 641 Kinder Morgan Canada 20 10 Corporate 4 3 Total consolidated investments $ 7,027 $ 6,040 2016 2015 Assets at December 31 Natural Gas Pipelines $ 50,428 $ 53,704 CO 2 4,065 4,706 Terminals 9,725 9,083 Products Pipelines 8,329 8,464 Kinder Morgan Canada 1,572 1,434 Corporate assets(e) 6,108 6,694 Assets held for sale 78 19 Total consolidated assets $ 80,305 $ 84,104 _______ (a) Includes a management fee for services we perform as operator of an equity investee. (b) Includes natural gas purchases and other 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) expense, net. (d) Includes revenues, earnings from equity investments, other, net, less operating expenses, and other (income) expense, 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 operations) 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 segments (in millions): Year Ended December 31, 2016 2015 2014 Revenues from external customers U.S. $ 12,459 $ 13,797 $ 15,605 Canada 483 479 437 Mexico 116 127 184 Total consolidated revenues from external customers $ 13,058 $ 14,403 $ 16,226 December 31, 2016 2015 2014 Long-term assets, excluding goodwill and other intangibles U.S. $ 49,125 $ 51,679 $ 49,992 Canada 2,399 2,193 2,268 Mexico 82 67 81 Total consolidated long-lived assets $ 51,606 $ 53,939 $ 52,341

General (Details)

General (Details)	11 Months Ended
	Nov. 25, 2014
KMP [Member]
Entity Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	10.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	2.00%
EPB [Member]
Entity Information [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	39.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	2.00%

Summary of Significant Accoun46

Summary of Significant Accounting Policies Cash Equivalents and Restricted Deposits (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Restricted deposits	$ 103	$ 60

Summary of Significant Accoun47

Summary of Significant Accounting Policies Accounts Receivable, Net (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Allowance for Doubtful Accounts Receivable	$ 39	$ 91

Summary of Significant Accoun48

Summary of Significant Accounting Policies Gas Imbalances (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Gas imbalance receivable	$ 108	$ 21
Gas imbalance payable	$ 45	$ 17

Summary of Significant Accoun49

Summary of Significant Accounting Policies Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Composite depreciation rate, low	1.09%
Composite depreciation rate, high	23.00%

Summary of Significant Accoun50

Summary of Significant Accounting Policies Equity investment and excess costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Sep. 01, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Non-current regulatory liabilities	$ 108		$ 166
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	17 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	$ 767		808
Goodwill [Member] | Unamortization [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method of Accounting and Excess Investment Cost	$ 956		$ 138

Summary of Significant Accoun51

Summary of Significant Accounting Policies Goodwill (Details)	12 Months Ended
	Dec. 31, 2016
May 31st [Member]
Goodwill [Line Items]
Number of Operating Segments	7

Summary of Significant Accoun52

Summary of Significant Accounting Policies Other Intangibles (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Intangible Assets, Gross (Excluding Goodwill)	$ 4,305	$ 4,335
Finite-Lived Intangible Assets, Accumulated Amortization	986	784
Intangible Assets, Net (Excluding Goodwill)	3,318	3,551
Amortization of Intangible Assets	223	$ 221	$ 143
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	215
Finite-Lived Intangible Assets, Amortization Expense, Year Two	213
Finite-Lived Intangible Assets, Amortization Expense, Year Three	211
Finite-Lived Intangible Assets, Amortization Expense, Year Four	209
Finite-Lived Intangible Assets, Amortization Expense, Year Five	$ 208
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	17 years

Summary of Significant Accoun53

Summary of Significant Accounting Policies Operations and Maintenance (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 349	$ 366	$ 403

Summary of Significant Accoun54

Summary of Significant Accounting Policies Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets and Liabilities [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	$ 172
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	20 years
Remaining Amounts of Regulatory Liabilities Subject to Crediting Period	$ 24
Current regulatory assets	49	$ 55
Non-current regulatory assets	330	378
Total regulatory assets(a)	379	433
Current regulatory liabilities	101	161
Non-current regulatory liabilities	$ 108	166
Remaining Recovery Period of Regulatory Liabilities Subject to Defined Crediting Period	22 years
Total regulatory liabilities(b)	$ 209	$ 327
Remaining Amounts of Regulatory Liabilities Not Subject to Defined Crediting Period	84
Loss on Disposal of Assets [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	188
Income Tax Gross Up on AFUDC Equity [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	107
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets(a)	$ 84

Summary of Significant Accoun55

Summary of Significant Accounting Policies Earnings per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ 552	$ 227	$ 1,026
Basic Weighted Average Common Shares Outstanding	2,230	2,187	1,137
Incremental Common Shares Attributable to Dilutive Effect of Call Options and Warrants	0	6	0
Diluted Weighted Average Common Shares Outstanding	2,230	2,193	1,137
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	8	7	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	293	291	312
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	8	8	10
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	10
Class P
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ 548	$ 214	$ 1,015
Basic Weighted Average Common Shares Outstanding	2,230	2,187	1,137
Restricted stock awards(a)
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ 4	$ 13	$ 11
Unvested Restricted Stock Awards, Issued and Non Issued	9

Acquisitions and Divestitures B

Acquisitions and Divestitures Business Combinations and Acquisitions of Investments (Details) - USD ($) $ in Millions	Dec. 31, 2016	Feb. 01, 2016	Dec. 31, 2015	Feb. 27, 2015	Feb. 13, 2015	Dec. 31, 2014	Nov. 05, 2014	Jan. 17, 2014
Business Acquisition [Line Items]
Goodwill	$ 22,152		$ 23,790			$ 24,654
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)
Pennsylvania and Florida Jones Act Tankers (Crowley) [Member]
Business Acquisition [Line Items]
Purchase price							$ 270
Current assets							0
Property, plant, and equipment							270
Deferred charges & other							8
Goodwill							25
Debt							0
Other liabilities							$ (33)
American Petroleum Tankers and State Class Tankers [Member]
Business Acquisition [Line Items]
Purchase price								$ 961
Current assets								6
Property, plant, and equipment								951
Deferred charges & other								6
Goodwill								64
Debt								0
Other liabilities								$ (66)

Acquisitions and Divestitures (

Acquisitions and Divestitures (1) BP Products North America Inc. (BP) Terminal Assets (Details) $ in Millions	Feb. 01, 2016USD ($)Terminals	Dec. 31, 2016USD ($)Terminals	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Contributions from noncontrolling interests | $		$ 117	$ 11	$ 1,767
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%
Contributions 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 contributed to equity investment	10
Products Pipelines | New Joint Venture with BP [Member] | BP Terminal Assets [Member]
Business Acquisition [Line Items]
Number of terminals contributed to equity investment	5

Acquisitions and Divestitures58

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 Divestitures59

Acquisitions and Divestitures (3) Hiland (Details) - USD ($) $ in Millions	Feb. 13, 2015	Feb. 13, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Repayments of Debt Assumed			$ 10,060	$ 15,116	$ 17,801
Hiland Partners, LP [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 3,122
Repayments of Debt Assumed	$ 368	$ 368
Finite-Lived Intangible Asset, Useful Life	16 years 5 months

Acquisitions and Divestitures60

Acquisitions and Divestitures (4) Pennsylvania and Florida Jones Act Tankers (Crowley) (Details) - Pennsylvania and Florida Jones Act Tankers (Crowley) [Member] $ in Millions	Nov. 05, 2014USD ($)MBbls
Business Acquisition [Line Items]
Number of Vessels	2
Business Combination, Consideration Transferred | $	$ 270
Tanker Capacity (MBbl) | MBbls	330

Acquisitions and Divestitures61

Acquisitions and Divestitures (5) American Petroleum Tankers and State Class Tankers (Details) $ in Millions	Jan. 17, 2014USD ($)MBbls
American Petroleum Tankers and State Class Tankers [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest | $	$ 961
American Petroleum Tankers [Member]
Business Acquisition [Line Items]
Number of Vessels	5
Tanker Capacity (MBbl)	330
Vessel Time Charter, Operating Remaining contract term	4 years
Vessel Time Charter, Operating Renewal Term (up to)	2 years
Dynamics NASSCO shipyard [Member] | State Class Tankers [Member]
Business Acquisition [Line Items]
Number of Vessels	4
Tanker Capacity (MBbl)	330
Vessel Time Charter, Operating Remaining contract term	5 years
Vessel Time Charter, Operating Renewal Term (up to)	3 years

Acquisitions and Divestitures A

Acquisitions and Divestitures Asset Purchase (Details) - Elba Liquification Company LLC [Member] $ in Millions	Jul. 15, 2015USD ($)
Property, Plant and Equipment [Line Items]
Payments to Acquire Assets, Investing Activities	$ 185
Shell US Gas & Power LLC [Member]
Property, Plant and Equipment [Line Items]
Equity Method Investment, Ownership Percentage	49.00%
Capacity Subscribed, Percent	100.00%

Acquisitions and Divestitures I

Acquisitions and Divestitures Investment Acquisition (Details) - NGPL Holdings LLC $ in Millions	Dec. 10, 2015USD ($)
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	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. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%

Acquisitions and Divestitures S

Acquisitions and Divestitures Sale of Equity Interest in SNG (Details) - USD ($) $ in Millions	Sep. 01, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Oct. 01, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of equity interests in subsidiaries, net		$ 1,401	$ 0	$ 0
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 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Equity Interest Sold	50.00%				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%

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 ($)Terminals	Dec. 31, 2016USD ($)Terminals	Dec. 31, 2016USD ($)Terminals	Dec. 31, 2015USD ($)
Long Lived Assets Held-for-sale [Line Items]
Assets held for sale		$ 78	$ 78	$ 19
Terminal Asset Sale [Member]
Long Lived Assets Held-for-sale [Line Items]
Number of terminals | Terminals	20
Proceeds from Sale of Property, Plant, and Equipment	$ 100
Gain (loss) on impairments and divestitures, net			(81)
Goodwill, Period Increase (Decrease)			$ 7
Number of Terminals Sales Transaction Closed | Terminals		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		7
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		13	13
Assets held for sale		$ 61	$ 61

Impairments (Details)

Impairments (Details) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016Terminals	Dec. 31, 2016USD ($)Terminals	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Oct. 31, 2016Terminals	Sep. 01, 2016
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss / Gain on impairments and disposals of long-lived assets, equity investments and goodwill, net		$ 1,013	$ 2,125	$ 274
Loss on impairment of goodwill		0	1,150	0
Gain on impairments and divestitures of equity investments, net		$ 610	30	0
number of investments	2	2
Regulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairments of long-lived assets			32
Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairment of goodwill		$ 0	1,150	0
Loss on impairments of long-lived assets		106	79	0
Disposal Group, Not Discontinued Operation, (Gain) Loss on Disposal		94	43	5
Gain on impairments and divestitures of equity investments, net		606	26	0
Nonregulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairments of long-lived assets			47
CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairments of long-lived assets		20	606	243
Disposal Group, Not Discontinued Operation, (Gain) Loss on Disposal		(1)	0	0
Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairments of long-lived assets		19	188	0
Disposal Group, Not Discontinued Operation, (Gain) Loss on Disposal		80	3	29
Gain on impairments and divestitures of equity investments, net		$ 16	4	0
Number of terminals | Terminals	20	20
Products Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairments of long-lived assets		$ 66	0	0
Disposal Group, Not Discontinued Operation, (Gain) Loss on Disposal		10	(1)	3
Gain on impairments and divestitures of equity investments, net		(12)	0	0
Other
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Disposal Group, Not Discontinued Operation, (Gain) Loss on Disposal		(7)	(1)	0
Investee [Member] | Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Gain on impairments and divestitures of equity investments, net		7	0	0
Investee [Member] | CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Gain on impairments and divestitures of equity investments, net		9	26	$ 0
Oil and Gas Properties [Member] | CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairments of long-lived assets			399
Source and transportation projects [Member] | CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairments of long-lived assets			207
Before income tax [Member] | Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairments of long-lived assets			$ 175
MEP
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Gain on impairments and divestitures of equity investments, net		350
Ruby
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
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, Not Discontinued Operation, (Gain) Loss on Disposal		84
Disposal Group, Equity Interest Sold						50.00%
Terminal Asset Sale [Member]
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Disposal Group, Not Discontinued Operation, (Gain) Loss on Disposal		$ 81
Number of terminals | Terminals					20
Number of Terminals Sales Transaction Closed | Terminals	7

Income Taxes (Details)

Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income from Continuing Operations Before Income Taxes
U.S.	$ 1,466,000,000	$ 611,000,000	$ 2,941,000,000
Foreign	172,000,000	161,000,000	150,000,000
Income Before Income Taxes	1,638,000,000	772,000,000	3,091,000,000
Current tax expense (benefit) [Abstract]
Federal (Benefit)	(148,000,000)	(125,000,000)	(16,000,000)
State	(28,000,000)	(7,000,000)	36,000,000
Foreign	6,000,000	4,000,000	13,000,000
Total	(170,000,000)	(128,000,000)	33,000,000
Deferred tax expense (benefit) [Abstract]
Federal	998,000,000	653,000,000	572,000,000
State	51,000,000	(4,000,000)	14,000,000
Foreign	38,000,000	43,000,000	29,000,000
Total	1,087,000,000	692,000,000	615,000,000
Total tax provision	917,000,000	564,000,000	648,000,000
Effective Income Tax Rate Reconciliation [Abstract]
Federal income tax	$ 573,000,000	$ 271,000,000	$ 1,082,000,000
Federal income tax	35.00%	35.00%	35.00%
State deferred tax rate change	$ 11,000,000	$ (24,000,000)	$ 0
State deferred tax rate change	0.70%	(3.10%)	0.00%
Taxes on foreign earnings	$ 28,000,000	$ 26,000,000	$ 40,000,000
Taxes on foreign earnings	1.70%	3.50%	1.30%
Net effects of consolidating KMP and EPB and other noncontrolling interests	$ (4,000,000)	$ 15,000,000	$ (433,000,000)
Net effects of consolidating KMP and EPB and other noncontrolling interests,	(0.30%)	2.00%	(14.00%)
State income tax, net of federal benefit	$ 26,000,000	$ 12,000,000	$ 37,000,000
State income tax, net of federal benefit	1.60%	1.50%	1.20%
Dividend received deduction	$ (48,000,000)	$ (51,000,000)	$ (50,000,000)
Dividend received deduction	(2.90%)	(6.60%)	(1.60%)
Adjustments to uncertain tax positions	$ (23,000,000)	$ (14,000,000)	$ (5,000,000)
Adjustments to uncertain tax positions	(1.40%)	(1.90%)	(0.20%)
Valuation allowance on investment and tax credits	$ 34,000,000	$ 0	$ 61,000,000
Valuation allowance on investment and tax credits	2.10%	0.00%	2.00%
Disposition of certain international holdings	$ 0	$ 0	$ (112,000,000)
Disposition of certain international holdings	0.00%	0.00%	(3.60%)
Nondeductible goodwill	$ 301,000,000	$ 323,000,000	$ 0
Nondeductible goodwill	18.50%	41.70%	0.00%
Other	$ 19,000,000	$ 6,000,000	$ 28,000,000
Other	1.10%	0.80%	0.90%
Total	$ 917,000,000	$ 564,000,000	$ 648,000,000
Total	56.10%	72.90%	21.00%
Components of Deferred Tax Assets and Liabilities [Abstract]
Employee benefits	$ 401,000,000	$ 394,000,000
Accrued expenses	118,000,000	129,000,000
Net operating loss, capital loss, tax credit carryforwards	1,307,000,000	1,344,000,000
Derivative instruments and interest rate and currency swaps	22,000,000	45,000,000
Debt fair value adjustment	74,000,000	110,000,000
Investments	2,804,000,000	3,607,000,000
Other	14,000,000	3,000,000
Valuation Allowance	(184,000,000)	(152,000,000)
Total deferred tax assets	4,556,000,000	5,480,000,000
Property, plant and equipment	177,000,000	143,000,000
Other	27,000,000	14,000,000
Total deferred tax liabilities	204,000,000	157,000,000
Net deferred tax assets	4,352,000,000	5,323,000,000
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Valuation Allowance	184,000,000	152,000,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	32,000,000
Deferred Tax Assets, Operating Loss Carryforwards	1,128,000,000	1,005,000,000
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	175,000,000	339,000,000
Deferred Tax Assets, Capital Loss Carryforwards	$ 4,000,000
Required minimum likelihood for benefits to be recognized in the financial statements	50.00%
Reconciliation of Gross Unrecognized Tax Benefits, Excluding Interest and Penalties
Unrecognized Tax Benefits, Beginning	$ 148,000,000	189,000,000	$ 209,000,000
Additions based on current year tax positions	3,000,000	4,000,000	12,000,000
Additions based on prior year tax positions	7,000,000	0	0
Reductions based on prior year tax positions	(1,000,000)	(6,000,000)	(3,000,000)
Reductions based on settlements with taxing authority	(26,000,000)	(25,000,000)	(24,000,000)
Reductions due to lapse in statute of limitations	(9,000,000)	(14,000,000)	(5,000,000)
Unrecognized Tax Benefits, Ending	122,000,000	148,000,000	189,000,000
Income Tax Examination, Penalties and Interest Expense	2,000,000	(4,000,000)	(1,000,000)
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	28,000,000	24,000,000	28,000,000
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0	2,000,000
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	2,000,000
Unrecognized tax benefits, income tax penalties and interest accruing next year	124,000,000
Does Not Expire [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	153,000,000
Majority expire from 2017 - 2023 [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	21,000,000
Deferred Tax Asset, Investments [Member] | Natural Gas Pipelines
Components of Deferred Tax Assets and Liabilities [Abstract]
Valuation Allowance			(61,000,000)
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Valuation Allowance			$ 61,000,000
Capital Loss Carryforward [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	4,000,000
Foreign Tax Authority [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	18,000,000
Foreign net operating losses [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	10,000,000
Net operating loss, capital loss, tax credit carryforwards [Member]
Components of Deferred Tax Assets and Liabilities [Abstract]
Valuation Allowance	(123,000,000)	(91,000,000)
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Valuation Allowance	123,000,000	$ 91,000,000
Domestic Tax Authority [Member] | Expires 2018 - 2036
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	2,700,000,000
Domestic Tax Authority [Member] | State and Local Jurisdiction [Member] | Expires from 2017 - 2036 [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	3,000,000,000
Foreign Tax Authority [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Foreign	183,000,000
Foreign Tax Authority [Member] | Does Not Expire [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Not Subject to Expiration	137,000,000
Foreign Tax Authority [Member] | Expires from 2029 - 2036 [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	46,000,000
Retained Earnings [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards	9,000,000
Deferred Income Tax Charge [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax Increase (Decrease)	(151,000,000)
Deferred Compensation, Share-based Payments [Member]
Deferred Tax Assets and Valuation Allowances [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards	$ 9,000,000

Property, Plant and Equipment C

Property, Plant and Equipment Classes and Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Accumulated depreciation, depletion and amortization	$ (12,306)	$ (10,851)
Public Utilities, Property, Plant and Equipment, Equipment	35,113	36,702
Land and land rights-of-way	1,431	1,450
Construction work in process	2,161	2,395
Property, plant and equipment, net	38,705	40,547
Public Utilities, Property, Plant and Equipment, Common	12,900	16,089
Depreciation, depletion and amortization	2,209	2,309	$ 2,040
Charged against PPE [Member]
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Depreciation, depletion and amortization	1,970	2,059	$ 1,862
Gas Transmission Equipment [Member]
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Pipelines (Natural gas, liquids, crude oil and CO2)	19,341	19,855
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)	23,298	22,979
Property, Plant and Equipment, Other Types [Member]
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Other(a)	$ 4,780	$ 4,719

Property, Plant and Equipment A

Property, Plant and Equipment Asset Retirement Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Asset Retirement Obligation	$ 193	$ 215
Asset Retirement Obligation, Current	$ 9	$ 9

Investments Equity investments

Investments Equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Investment [Line Items]
Payments to Acquire Equity Method Investments	$ 408	$ 96	$ 389
Total equity investments	7,027	6,032
Held-to-maturity Securities	0	8
Long-term Investments	$ 7,027	6,040
Citrus Corporation
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 1,709	1,719
SNG
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 1,505	0
Ruby
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 798	1,093
Gulf LNG Holdings Group, LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 485	516
NGPL Holdings LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 475	153
Plantation Pipe Line Company
Investment [Line Items]
Equity Method Investment, Ownership Percentage	51.17%
Total equity investments	$ 333	327
EagleHawk
Investment [Line Items]
Equity Method Investment, Ownership Percentage	25.00%
Total equity investments	$ 329	348
MEP
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 328	713
Red Cedar Gathering Company
Investment [Line Items]
Equity Method Investment, Ownership Percentage	49.00%
Total equity investments	$ 191	185
Watco Companies, LLC
Investment [Line Items]
Common Unit, Issued	13,000
Total equity investments	$ 180	201
Double Eagle Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 151	158
FEP
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 101	116
Liberty Pipeline Group LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 75	79
Bear Creek Storage
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 61	0
Sierrita Gas Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	35.00%
Total equity investments	$ 57	60
Utopia Holding LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 55	0
Fort Union Gas Gathering L.L.C.
Investment [Line Items]
Equity Method Investment, Ownership Percentage	37.04%
Total equity investments	$ 25	50
Parkway Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Total equity investments	$ 0	131
Cortez Pipeline Company
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
All Other Legal Entities [Member]
Investment [Line Items]
Total equity investments	$ 169	$ 183
Preferred stock | Watco Companies, LLC
Investment [Line Items]
Quarterly preferred distribution rate	3.25%
Preferred Class B [Member] | Watco Companies, LLC
Investment [Line Items]
Quarterly preferred distribution rate	3.00%
Common Units | Watco Companies, LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	3.40%
Southern Natural Gas Company LLC [Member] | SNG
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
SNG | Bear Creek Storage
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
MGI Enterprises U.S. LLC [Member] | Sierrita Gas Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	35.00%
MIT Pipeline Investment Americas, Inc. | Sierrita Gas Pipeline LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	30.00%
Riverstone Investment Group LLC [Member] | Utopia Holding LLC
Investment [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Brookfield [Member] | NGPL Holdings LLC
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Net Investment Income [Line Items]
Impairment charge pre-tax	$ (610)	$ (30)	$ 0
Income (Loss) from Equity Method Investments	497	414	406
Income (loss) from Equity Method Investments, Net of Impairments	497	414	406
Amortization of excess costs	$ (59)	(51)	(45)
Citrus Corporation
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 102	96	97
SNG
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 58	0	0
FEP
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 51	55	55
Gulf LNG Holdings Group, LLC
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 48	49	48
MEP
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Impairment charge pre-tax	$ (350)
Income (Loss) from Equity Method Investments	$ 40	45	45
Plantation Pipe Line Company
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	51.17%
Income (Loss) from Equity Method Investments	$ 37	29	29
Watco Companies, LLC
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	$ 25	16	13
Red Cedar Gathering Company
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	49.00%
Income (Loss) from Equity Method Investments	$ 24	26	33
Cortez Pipeline Company
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Impairment charge pre-tax	$ (9)	(26)
Income (Loss) from Equity Method Investments	$ 24	(3)	25
Ruby
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Impairment charge pre-tax	$ (250)
Income (Loss) from Equity Method Investments	$ 15	18	15
Parkway Pipeline LLC
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 14	5	8
NGPL Holdco LLC
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	$ 12	0	0
Liberty Pipeline Group LLC
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 11	9	6
EagleHawk
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	25.00%
Income (Loss) from Equity Method Investments	$ 10	24	(7)
Sierrita Gas Pipeline LLC
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	35.00%
Income (Loss) from Equity Method Investments	$ 7	9	3
Double Eagle [Member]
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 5	3	(1)
Bear Creek Storage
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Income (Loss) from Equity Method Investments	$ 2	0	0
Fort Union Gas Gathering L.L.C.
Net Investment Income [Line Items]
Equity Method Investment, Ownership Percentage	37.04%
Impairment charge pre-tax	$ (7)
Income (Loss) from Equity Method Investments	1	16	16
All Other Legal Entities [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	$ 11	$ 17	$ 21

Investments Investments (Detail

Investments Investments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)
Schedule of Equity Method Investments [Line Items]
Preferred Stock, Value, Issued (Share)	1,600,000	1,600,000
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest | $	$ (408)	$ (96)	$ (389)
Citrus Corporation
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Miles Of Pipeline	5,300
SNG
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Ruby
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Gulf LNG Holdings Group, LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Plantation Pipeline Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	51.17%
EagleHawk
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	25.00%
MEP
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Red Cedar Gathering Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	49.00%
Watco Companies, LLC
Schedule of Equity Method Investments [Line Items]
Profit participation rate	0.40%
Double Eagle Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Fayetteville Express
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%
Bear Creek Storage Company L.L.C.
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Sierrita Gas Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	35.00%
Utopia Holding LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Fort Union Gas Gathering L.L.C.
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	37.04%
Parkway Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Cortez Pipeline Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Energy Transfers Partners L.P. | Citrus Corporation
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Energy Transfers Partners L.P. | MEP
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%
GE Financial Services and The Blackstone Group L.P. [Member] | Gulf LNG Holdings Group, LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Brookfield [Member] | NGPL Holdings, LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
BHP Billiton [Member] | EagleHawk
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	75.00%
Southern Ute Indian Tribe [Member] | Red Cedar Gathering Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	51.00%
Magellan Midstream Partners [Member] | Double Eagle Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Valero Energy Corp. [Member] | Parkway Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
ONEOK Partners L.P. [Member] | Fort Union Gas Gathering L.L.C.
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	37.04%
Powder River Midstream, LLC [Member] | Fort Union Gas Gathering L.L.C.
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	11.11%
Western Gas Wyoming, LLC [Member] | Fort Union Gas Gathering L.L.C.
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	14.81%
MGI Enterprises U.S. LLC [Member] | Sierrita Gas Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	35.00%
MIT Pipeline Investment Americas, Inc. | Sierrita Gas Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	30.00%
Riverstone Investment Group LLC [Member] | Utopia Holding LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Preferred Class A | Watco Companies, LLC
Schedule of Equity Method Investments [Line Items]
Preferred Stock, Value, Issued (Share)	100,000
Quarterly preferred distribution rate	3.25%
Preferred Class B [Member] | Watco Companies, LLC
Schedule of Equity Method Investments [Line Items]
Preferred Stock, Value, Issued (Share)	50,000
Quarterly preferred distribution rate	3.00%

Investments Summary of Signific

Investments Summary of Significant Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summarized Financial Information for Significant Equity Investments [Line Items]
Percent of investee information represented	100.00%
Revenues	$ 4,084	$ 3,857	$ 3,829
Costs and expenses	3,056	3,408	3,063
Net income	1,028	449	$ 766
Current assets	892	811
Non-current assets	22,170	19,745
Current liabilities	3,532	1,009
Non-current liabilities	9,187	11,227
Partners’/owners’ equity	$ 10,343	$ 8,320

Goodwill Goodwill - Rollforward

Goodwill Goodwill - Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Feb. 27, 2015
Goodwill [Line Items]
Historical Goodwill			$ 29,067
Accumulated impairment losses			(4,413)
Goodwill	$ 22,152	$ 23,790	24,654
Acquisitions(a)		321
Impairment	(1,644)
Currency translation	6	(35)
Loss on impairment of goodwill	0	(1,150)	0
Natural Gas Pipelines Regulated
Goodwill [Line Items]
Historical Goodwill			17,527
Accumulated impairment losses			(1,643)
Goodwill	14,249	15,884	15,884
Acquisitions(a)		0
Impairment	(1,635)
Currency translation	0	0
Loss on impairment of goodwill		0
Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Historical Goodwill			5,719
Accumulated impairment losses			(447)
Goodwill	4,215	4,215	5,272
Acquisitions(a)		93
Impairment	0
Currency translation	0	0
Loss on impairment of goodwill		(1,150)
CO2
Goodwill [Line Items]
Historical Goodwill			1,528
Accumulated impairment losses			0
Goodwill	1,528	1,528	1,528
Acquisitions(a)		0
Impairment	0
Currency translation	0	0
Loss on impairment of goodwill		0
Products Pipelines
Goodwill [Line Items]
Historical Goodwill			1,908
Accumulated impairment losses			(1,197)
Goodwill	928	928	711
Acquisitions(a)		217
Impairment	0
Currency translation	0	0
Loss on impairment of goodwill		0
Products Pipelines Terminals
Goodwill [Line Items]
Historical Goodwill			221
Accumulated impairment losses			(70)
Goodwill	151	151	151
Acquisitions(a)		0
Impairment	0
Currency translation	0	0
Loss on impairment of goodwill		0
Terminals
Goodwill [Line Items]
Historical Goodwill			1,573
Accumulated impairment losses			(679)
Goodwill	896	905	894
Acquisitions(a)		11
Impairment	(9)
Currency translation	0	0
Loss on impairment of goodwill		0
Kinder Morgan Canada
Goodwill [Line Items]
Historical Goodwill			591
Accumulated impairment losses			(377)
Goodwill	185	179	$ 214
Acquisitions(a)		0
Impairment	0
Currency translation	$ 6	(35)
Loss on impairment of goodwill		0
KMI Acquisition of Hiland Partners Holding LLC [Member] | Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Acquisitions(a)		93
KMI Acquisition of Hiland Partners Holding LLC [Member] | Products Pipelines
Goodwill [Line Items]
Acquisitions(a)		217
Vopak Terminal Assets [Member]
Goodwill [Line Items]
Goodwill				$ 6
Vopak Terminal Assets [Member] | Terminals
Goodwill [Line Items]
Acquisitions(a)		$ 7
Minimum [Member]
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	9.00%
Maximum [Member]
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount	80.00%

Goodwill Goodwill (Details)

Goodwill Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Sep. 01, 2016
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	$ (1,644)
Natural Gas Pipelines Regulated
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	(1,635)
Terminals
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	(9)
Products Pipelines Terminals
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	0
CO2
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	0
Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Goodwill, Written off Related to Sale of Business Unit	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Fair Value [Line Items]
Loss on impairment of goodwill	$ 0	$ 1,150	$ 0
Natural Gas Pipelines Non-Regulated
Schedule of Fair Value [Line Items]
Loss on impairment of goodwill		1,150
Natural Gas Pipelines
Schedule of Fair Value [Line Items]
Loss on impairment of goodwill	$ 0	$ 1,150	$ 0

Debt (Details)

Debt (Details) - USD ($)

Oct. 01, 2016

Sep. 30, 2016

Sep. 01, 2016

Aug. 16, 2016

Feb. 01, 2016

Jan. 26, 2016

Jan. 05, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Feb. 13, 2015

Dec. 31, 2013

Debt Instrument [Line Items]

Preferred interest in general partner of KMP

$ 100,000,000

$ 100,000,000

Less: Current portion of debt(a)(f)(k)

2,696,000,000

821,000,000

Total Long-term debt - KMI and Subsidiaries(l)

$ 37,354,000,000

42,406,000,000

Long-term Debt, Current Maturities

$ 1,000,000,000

Debt, Weighted Average Interest Rate

4.95%

4.92%

Gain (Loss) on Extinguishment of Debt

$ 45,000,000

$ 0

$ 0

Repayments of Debt

$ 10,060,000,000

$ 15,116,000,000

$ 17,801,000,000

Preferred Stock, Liquidation Preference Per Share

$ 1,000

$ 1,000

Value of preferred securities value assigned to debt

$ 199,000,000

Value of preferred securities value assigned to equity

$ 22,000,000

EP Trust I Preferred security conversions

1,000,000

Preferred stock, shares outstanding (in shares)

1,600,000

1,600,000

0

0

Preferred Stock, Dividend Rate, Percentage

9.75%

9.75%

Debt Instrument, Fair Value Disclosure

$ 1,149,000,000

$ 1,674,000,000

Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Amount Outstanding

$ 0

Debt Instrument, Term

5 years

Line of Credit Facility, Current Borrowing Capacity

$ 5,000,000,000

$ 5,000,000,000

Commercial Paper [Member]

Debt Instrument [Line Items]

Commercial Paper

$ 0

Debt Instrument, Term

270 days

Kinder Morgan, Inc. [Member]

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. [Member] | Senior unsecured revolving credit facility [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Amount Outstanding

$ 0

0

Kinder Morgan, Inc. [Member] | Commercial Paper [Member]

Debt Instrument [Line Items]

Commercial Paper

$ 0

$ 0

Colorado Interstate Gas Company, L.L.C. [Member]

Debt Instrument [Line Items]

Construction Costs Funded

50.00%

SNG

Debt Instrument [Line Items]

Equity Method Investment, Ownership Percentage

50.00%

Capital Trust I [Member]

Debt Instrument [Line Items]

Trust Convertible Preferred Securities Outstanding

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

$ 38,901,000,000

$ 41,553,000,000

Total Long-term debt - KMI and Subsidiaries(l)

$ 36,205,000,000

40,732,000,000

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. [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,000,000,000

$ 1,000,000,000

0

Debt Instrument, Term

3 years

Proceeds from Issuance of Long-term Debt

1,000,000,000

KMI Senior Notes,1.50% through 8.25%, due 2016 through 2098 [Member] | Kinder Morgan, Inc. [Member]

Debt Instrument [Line Items]

Senior Notes

13,236,000,000

13,346,000,000

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

19,485,000,000

19,985,000,000

KMP Senior notes, 7.00% through 8.375%, due 2016 through 2037 [Member] | TGP [Member]

Debt Instrument [Line Items]

Senior Notes

1,540,000,000

1,790,000,000

KMP 5.95% through 8.625%, due 2017 through 2032 [Member] [Member] | EPNG [Member]

Debt Instrument [Line Items]

Senior Notes

1,115,000,000

1,115,000,000

KMP 7.125% Senior Notes due April 1, 2021 (Copano) [Member] | Subsidiary Issuer and Guarantor - Copano

Debt Instrument [Line Items]

Senior Notes

0

332,000,000

Interest rate, stated percentage

7.125%

Gain (Loss) on Extinguishment of Debt

$ 28,300,000

Repayments of Debt

332,000,000

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

475,000,000

100,000,000

KMP Notes, 4.40% through 8.00%, due 2017 through 2032 [Member] | SNG

Debt Instrument [Line Items]

Notes Payable

0

1,211,000,000

Debt Instrument, Increase (Decrease), Other, Net

$ 1,211,000,000

KMI 5.70% through 6.40% series, due 2016 through 2036 [Member] | Kinder Morgan Finance Company, LLC [Member]

Debt Instrument [Line Items]

Senior Notes

786,000,000

1,636,000,000

KMI Senior Notes, 5.50% and 7.25%, due 2020 and 2022 [Member] | Hiland Partners Holding LLC [Member]

Debt Instrument [Line Items]

Senior Notes

225,000,000

974,000,000

$ 975,000,000

KMI Promissory note 3.967%, due 2016 through 2035 [Member] | EPC Building LLC [Member]

Debt Instrument [Line Items]

Notes Payable

$ 433,000,000

443,000,000

Interest rate, stated percentage

3.967%

KMI EP Capital Trust I 4.75%, due 2028 [Member]

Debt Instrument [Line Items]

Value of cash issued in debt conversion

$ 5,000

30,000,000

KMI EP Capital Trust I 4.75%, due 2028 [Member] | Capital Trust I [Member]

Debt Instrument [Line Items]

Senior Notes

$ 221,000,000

221,000,000

Interest rate, stated percentage

4.75%

Long-term Debt, Current Maturities

$ 111,000,000

Preferred Stock, Liquidation Preference Per Share

$ 50

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

$ 100,000,000

$ 100,000,000

Preferred stock, par value (in dollars per share)

$ 1,000

$ 1,000

Other Miscellaneous Subsidiary Debt [Member] | KMI, KMP and EPB [Member]

Debt Instrument [Line Items]

Notes Payable

$ 285,000,000

$ 300,000,000

5.70% Senior Notes due January 5, 2016 [Member] | Kinder Morgan Finance Company, LLC [Member]

Debt Instrument [Line Items]

Short-term Debt, Refinanced, Amount

$ 850,000,000

Interest rate, stated percentage

5.70%

Repayments of Debt

$ 850,000,000

TGP 8.00% Senior Notes due February 1, 2016 [Member] | TGP [Member]

Debt Instrument [Line Items]

Short-term Debt, Refinanced, Amount

$ 250,000,000

Interest rate, stated percentage

8.00%

Repayments of Debt

$ 250,000,000

KMP Senior Notes, 4.15% due August 15,2026 [Member] | Colorado Interstate Gas Company, L.L.C. [Member]

Debt Instrument [Line Items]

Senior Notes

$ 375,000,000

Interest rate, stated percentage

4.15%

4.15%

Proceeds from Issuance of Long-term Debt

$ 372,000,000

$ 375,000,000

KMP Senior Notes, 5.90%, due April 1, 2017 [Member] | SNG

Debt Instrument [Line Items]

Interest rate, stated percentage

5.90%

KMI Senior Notes 7.25%, due 2020 [Member] | Hiland Partners Holding LLC [Member]

Debt Instrument [Line Items]

Interest rate, stated percentage

7.25%

7.25%

Gain (Loss) on Extinguishment of Debt

$ 17,300,000

Repayments of Debt

749,000,000

$ 749,000,000

Capital Trust [Member]

Debt Instrument [Line Items]

Conversion of Stock, Shares Converted

200

1,176,015

Totem [Member] | El Paso Pipeline Partners, L.P. [Member]

Debt Instrument [Line Items]

Capital Lease Obligations

$ 71,000,000

High Plains [Member] | El Paso Pipeline Partners, L.P. [Member]

Debt Instrument [Line Items]

Capital Lease Obligations

$ 92,000,000

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

Class P | Capital Trust [Member]

Debt Instrument [Line Items]

EP Trust I Preferred security conversions

143

846,369

Warrant [Member] | Capital Trust [Member]

Debt Instrument [Line Items]

Debt Conversion, Converted Instrument, Warrants or Options Issued

220

1,293,615

Euro Member Countries, Euro | Senior Notes [Member]

Debt Instrument [Line Items]

Foreign Currency Exchange Rate, Translation

1.0517

1.0862

Translation Adjustment Functional to Reporting Currency, Increase (Decrease), Gross of Tax

$ 43,000,000

Minimum [Member] | KMI Senior Notes,1.50% through 8.25%, due 2016 through 2098 [Member] | Kinder Morgan, Inc. [Member]

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] | KMP Notes, 4.40% through 8.00%, due 2017 through 2032 [Member] | SNG

Debt Instrument [Line Items]

Interest rate, stated percentage

4.40%

Minimum [Member] | KMI 5.70% through 6.40% series, due 2016 through 2036 [Member] | Kinder Morgan Finance Company, LLC [Member]

Debt Instrument [Line Items]

Interest rate, stated percentage

5.70%

Minimum [Member] | KMI Senior Notes, 5.50% and 7.25%, due 2020 and 2022 [Member] | Hiland Partners Holding LLC [Member]

Debt Instrument [Line Items]

Interest rate, stated percentage

5.50%

Maximum [Member] | KMI Senior Notes,1.50% through 8.25%, due 2016 through 2098 [Member] | Kinder Morgan, Inc. [Member]

Debt Instrument [Line Items]

Interest rate, stated percentage

8.25%

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] | KMP Notes, 4.40% through 8.00%, due 2017 through 2032 [Member] | SNG

Debt Instrument [Line Items]

Interest rate, stated percentage

8.00%

Maximum [Member] | KMI 5.70% through 6.40% series, due 2016 through 2036 [Member] | Kinder Morgan Finance Company, LLC [Member]

Debt Instrument [Line Items]

Interest rate, stated percentage

6.40%

Maximum [Member] | KMI Senior Notes, 5.50% and 7.25%, due 2020 and 2022 [Member] | Hiland Partners Holding LLC [Member]

Debt Instrument [Line Items]

Interest rate, stated percentage

7.25%

Premium on debt repaid [Member] | KMP 7.125% Senior Notes due April 1, 2021 (Copano) [Member] | Subsidiary Issuer and Guarantor - Copano

Debt Instrument [Line Items]

Gain (Loss) on Extinguishment of Debt

(11,800,000)

Premium on debt repaid [Member] | KMI Senior Notes 7.25%, due 2020 [Member] | Hiland Partners Holding LLC [Member]

Debt Instrument [Line Items]

Gain (Loss) on Extinguishment of Debt

27,100,000

Purchase Accounting [Member] | KMP 7.125% Senior Notes due April 1, 2021 (Copano) [Member] | Subsidiary Issuer and Guarantor - Copano

Debt Instrument [Line Items]

Gain (Loss) on Extinguishment of Debt

$ 40,100,000

Purchase Accounting [Member] | KMI Senior Notes 7.25%, due 2020 [Member] | Hiland Partners Holding LLC [Member]

Debt Instrument [Line Items]

Gain (Loss) on Extinguishment of Debt

$ 44,400,000

Sale Equity Interest in SNG [Member]

Debt Instrument [Line Items]

Disposal Group, Equity Interest Sold

50.00%

Sale Equity Interest in SNG [Member] | Southern Natural Gas Company LLC [Member]

Debt Instrument [Line Items]

Disposal Group, Equity Interest Sold

50.00%

50.00%

Equity Method Investment, Ownership Percentage

50.00%

Short-term Debt [Member] | KMP Senior Notes, 5.90%, due April 1, 2017 [Member] | SNG

Debt Instrument [Line Items]

Debt Instrument, Increase (Decrease), Other, Net

$ 500,000,000

Credit Facilities and Restricti

Credit Facilities and Restrictive Covenants (Details) $ in Millions	Jan. 26, 2016USD ($)	Dec. 31, 2016USD ($)	Nov. 26, 2014USD ($)
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount		$ 160
Remaining borrowing capacity		$ 4,840
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Term		5 years
Line of Credit Facility, Prior Borrowing Capacity	$ 4,000
Line of Credit Facility, Current Borrowing Capacity	$ 5,000	$ 5,000
Line of Credit Facility, Amount Outstanding		0
Commercial Paper [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Term	270 days
Commercial Paper, Current Borrowing Capacity		4,000	$ 4,000
Commercial Paper		$ 0
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%

Debt Current Portion of Debt

Debt Current Portion of Debt - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
KMP Senior notes, 6.0%, due February 1, 2017 [Member] | KMP(a)
Debt Instrument [Line Items]
Senior Notes, Current	$ 600
Debt Instrument, Interest Rate, Stated Percentage	6.00%
KMP Senior notes, 7.50%, due April 1, 2017 [Member] | TGP [Member]
Debt Instrument [Line Items]
Senior Notes, Current	$ 300
Debt Instrument, Interest Rate, Stated Percentage	7.50%
KMP Senior Notes, 5.95%, due April 15, 2017 [Member] | EPNG [Member]
Debt Instrument [Line Items]
Senior Notes, Current	$ 355
Debt Instrument, Interest Rate, Stated Percentage	5.95%
KMI Senior Notes, 7.0%, due June 15, 2017 [Member] | Kinder Morgan, Inc. [Member]
Debt Instrument [Line Items]
Senior Notes, Current	$ 786
Debt Instrument, Interest Rate, Stated Percentage	7.00%
KMI Senior Notes, 2.0%, due December 1, 2017 [Member] | Kinder Morgan, Inc. [Member]
Debt Instrument [Line Items]
Senior Notes, Current	$ 500
Debt Instrument, Interest Rate, Stated Percentage	2.00%
KMP 3.5% Senior Notes due March 1, 2016 [Member] | KMP(a)
Debt Instrument [Line Items]
Senior Notes, Current		$ 500
Debt Instrument, Interest Rate, Stated Percentage	3.50%	3.50%

Debt Long-term Debt Issuances,

Debt Long-term Debt Issuances, Repayments and Other Significant Changes in Debt(Details) - USD ($) $ in Millions

Oct. 01, 2016

Sep. 30, 2016

Sep. 01, 2016

Aug. 16, 2016

Feb. 01, 2016

Jan. 05, 2016

Feb. 13, 2015

Feb. 13, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Jan. 26, 2016

Debt Instrument [Line Items]

Debt Instrument, Fair Value Disclosure

$ 1,149

$ 1,674

Repayments of Debt

10,060

15,116

$ 17,801

Kinder Morgan, Inc. [Member] | Senior unsecured term loan facility, variable, due May 6, 2017 [Member]

Debt Instrument [Line Items]

Senior Notes

1,000

$ 0

$ 1,000

Proceeds from Issuance of Long-term Debt

$ 1,000

Kinder Morgan, Inc. [Member] | KMI 5.05% Senior Notes Due 2046 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

5.05%

Proceeds from Issuance of Long-term Debt

$ 800

Kinder Morgan, Inc. [Member] | KMI 1.50% Senior Notes Due 2022 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

1.50%

Proceeds from Issuance of Long-term Debt

$ 815

Kinder Morgan, Inc. [Member] | KMI 2.25% Senior Notes Due 2027 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

2.25%

Proceeds from Issuance of Long-term Debt

$ 543

Kinder Morgan, Inc. [Member] | KMI 8.25% Senior Notes due February 15, 2016 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

8.25%

Repayments of Debt

$ 67

Kinder Morgan, Inc. [Member] | KMI 5.15% Senior Notes due March 1, 2015 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

5.15%

Repayments of Debt

$ 250

Colorado Interstate Gas Company, L.L.C. [Member] | KMP Senior Notes, 4.15% due August 15,2026 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 375

Debt Instrument, Interest Rate, Stated Percentage

4.15%

4.15%

Proceeds from Issuance of Long-term Debt

$ 372

$ 375

Colorado Interstate Gas Company, L.L.C. [Member] | CIG 6.800% Senior Notes due November 15, 2015 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

6.80%

Repayments of Debt

$ 340

Kinder Morgan Finance Company, LLC [Member] | 5.70% Senior Notes due January 5, 2016 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

5.70%

Repayments of Debt

$ 850

Hiland Partners Holding LLC [Member] | KMI Senior Notes, 5.50% and 7.25%, due 2020 and 2022 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 975

$ 975

$ 225

$ 974

Hiland Partners Holding LLC [Member] | KMI Senior Notes 7.25%, due 2020 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

7.25%

7.25%

Repayments of Debt

$ 749

$ 749

Kinder Morgan Energy Partners, L.P. [Member] | KMP 3.5% Senior Notes due March 1, 2016 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

3.50%

3.50%

Repayments of Debt

$ 500

Kinder Morgan Energy Partners, L.P. [Member] | KMP 5.625% Senior Notes due February 15, 2015 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

5.625%

Repayments of Debt

$ 300

Kinder Morgan Energy Partners, L.P. [Member] | KMP 4.100% Senior Notes due November 15, 2015 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

4.10%

Repayments of Debt

$ 375

TGP [Member] | TGP 8.00% Senior Notes due February 1, 2016 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

8.00%

Repayments of Debt

$ 250

Subsidiary Issuer and Guarantor - Copano | KMP 7.125% Senior Notes due April 1, 2021 (Copano) [Member]

Debt Instrument [Line Items]

Senior Notes

$ 0

$ 332

Debt Instrument, Interest Rate, Stated Percentage

7.125%

Repayments of Debt

$ 332

SNG | KMP Notes, 4.40% through 8.00%, due 2017 through 2032 [Member]

Debt Instrument [Line Items]

Debt Instrument, Increase (Decrease), Other, Net

$ 1,211

SNG | KMP Senior Notes, 5.90%, due April 1, 2017 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

5.90%

Short-term Debt [Member] | SNG | KMP Senior Notes, 5.90%, due April 1, 2017 [Member]

Debt Instrument [Line Items]

Debt Instrument, Increase (Decrease), Other, Net

$ 500

KMI Acquisition of Hiland Partners Holding LLC [Member] | Hiland Partners Holding LLC [Member] | KMI Senior Notes, 5.50% and 7.25%, due 2020 and 2022 [Member]

Debt Instrument [Line Items]

Debt Instrument, Fair Value Disclosure

1,043

1,043

Hiland Partners, LP [Member]

Debt Instrument [Line Items]

Repayments of Debt

368

368

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt

$ 1,413

$ 1,413

Euro Member Countries, Euro | Senior Notes [Member]

Debt Instrument [Line Items]

Foreign Currency Exchange Rate, Translation

1.0517

1.0862

Debt Maturties of Debt

Debt Maturties of Debt $ in Millions	Dec. 31, 2016USD ($)
Debt Disclosure [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 2,696
Long-term Debt, Maturities, Repayments of Principal in Year Two	2,328
Long-term Debt, Maturities, Repayments of Principal in Year Three	3,820
Long-term Debt, Maturities, Repayments of Principal in Year Four	2,204
Long-term Debt, Maturities, Repayments of Principal in Year Five	2,422
Long-term Debt, Maturities, Repayments of Principal after Year Five	25,431
Total debt outstanding	$ 38,901

Debt Debt Fair Value Adjustment

Debt Debt Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Amortization Period of Deferred Gain (Loss) on Discontinuation of Fair Value Hedge	16 years
Debt Fair Value Adjustments	$ 1,149	$ 1,674
Amount the adjustment to fair value of debt was increased by related to the fair value of interest rate swaps	220	380
Deferred Gain (Loss) on Discontinuation of Interest Rate Fair Value Hedge	342	397
Debt Instrument, Fair Value Disclosure	1,149	1,674
Purchase Accounting [Member]
Debt Instrument [Line Items]
Debt Fair Value Adjustments	806	1,135
Unamortized Debt Discount Amounts [Member]
Debt Instrument [Line Items]
Debt Fair Value Adjustments	(80)	(86)
Unamortized Debt Issuance Costs [Member]
Debt Instrument [Line Items]
Debt Fair Value Adjustments	$ (139)	$ (152)

Debt Interest Rates, Interest R

Debt Interest Rates, Interest Rate Swaps and Contingent Debt (Details)	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	4.95%	4.92%

Share-based Compensation and 84

Share-based Compensation and Employee Benefits Share-based Compensation (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Vested (shares)	(1,000,000)
Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan [Member] | Restricted Stock [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
Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan [Member] | Restricted Stock [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, Options, Grants in Period, Net of Forfeitures	31,880	9,580	6,210
Stock Issued During Period, Value, Share-based Compensation, Net of Forfeitures	$ 400	$ 401	$ 220
kinder morgan inc 2015 amended and restated stock incentive plan [Member] | Restricted Stock [Member] | Class P
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at beginning of year (shares)	7,645,105	7,373,294	6,382,885
Outstanding, beginning of period (value per share)	$ 37.91	$ 37.63	$ 37.38
Granted (shares)	2,816,599	1,488,467	1,694,668
Granted (value per share)	$ 21.36	$ 38.20	$ 36.01
Vested (shares)	(1,226,652)	(817,797)	(460,032)
Vested (value per share)	$ 38.53	$ 35.66	$ 28.84
Forfeited (shares)	(196,915)	(398,859)	(244,227)
Forfeited (value per share)	$ 35.74	$ 38.51	$ 36.39
Outstanding at end of year (shares)	9,038,137	7,645,105	7,373,294
Outstanding, end of period (value per share)	$ 32.72	$ 37.91	$ 37.63
Intrinsic value of restricted stock vested during the period	$ 25,000	$ 31,000	$ 17,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	7,645,105	7,373,294	6,382,885	9,038,137	7,645,105
Restricted Stock or Unit Expense	$ 66,000	$ 52,000	$ 51,000
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	$ 9,000	$ 15,000	$ 6,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options				$ 133,000	$ 154,000
kinder morgan inc 2015 amended and restated stock incentive plan [Member] | Restricted Stock [Member] | Class P | Year 2017 [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (shares)	1,476,832
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	1,476,832			1,476,832
kinder morgan inc 2015 amended and restated stock incentive plan [Member] | Restricted Stock [Member] | Class P | Year 2018 [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (shares)	2,352,443
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	2,352,443			2,352,443
kinder morgan inc 2015 amended and restated stock incentive plan [Member] | Restricted Stock [Member] | Class P | Year 2019 [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (shares)	4,358,728
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	4,358,728			4,358,728
kinder morgan inc 2015 amended and restated stock incentive plan [Member] | Restricted Stock [Member] | Class P | Year 2020 [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (shares)	539,790
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	539,790			539,790
kinder morgan inc 2015 amended and restated stock incentive plan [Member] | Restricted Stock [Member] | Class P | Year 2021 [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (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] | Restricted Stock [Member] | Class P | Thereafter [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (shares)	110,494
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	110,494			110,494
kinder morgan inc 2015 amended and restated stock incentive plan [Member] | Restricted Stock [Member] | Class P | Minimum [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [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] | Restricted Stock [Member] | Class P | Maximum [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	10 years

Share-based Compensation and 85

Share-based Compensation and Employee Benefits Pensions and Other Postretirement Benefit Plans (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jan. 01, 2014
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year	$ 44
Defined Benefit Plan, Future Amortization of Gain (Loss)	(45)
Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit)	$ (1)
Savings plan [Member]
Savings Plan [Abstract]
Defined Contribution Plan, Employer Matching Contribution, Percent	5.00%
Defined Contribution Plan, Cost Recognized	$ 48	$ 46	$ 42
Pension Plan [Member]
Pension Plans [Abstract]
defined benefit plan covered employee percentage				100.00%
Defined Benefit Plan,Vesting Period	3 years
Defined Benefit Plan, Net Periodic Benefit Cost	$ 10	(35)	(38)
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, beginning of period	2,654	2,804
Defined Benefit Plan, Service Cost	36	33	21
Defined Benefit Plan, Interest Cost	89	99	112
Defined Benefit Plan, Actuarial (Gain) Loss	127	(109)
Defined Benefit Plan, Benefits Paid	(180)	(173)
Defined Benefit Plan, Contributions by Plan Participants	3	0
Defined Benefit Plan, Medicare Part D Subsidy Receipts	0	0
Defined Benefit Plan, Foreign Currency Exchange Rate Gain (Loss)	4	0
Defined Benefit Plan, Benefit Obligation, end of period	2,884	2,654	2,804
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	2,050	2,377
Defined Benefit Plan, Actual (Loss) Return on Plan Assets	157	(204)
Defined Benefit Plan, Contributions by Employer	8	50
Defined Benefit Plan, Contributions by Plan Participants	3	0
Defined Benefit Plan, Medicare Part D Subsidy Receipts	0	0
Defined Benefit Plan, Benefits Paid	(180)	(173)
Defined Benefit Plan, Foreign Currency Exchange Rate Changes, Plan Assets	3	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	2,160	2,050	2,377
Defined Benefit Plan, Funded Status of Plan				$ (724)	$ (604)
Components of Funded Status [Abstract]
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent				0	0
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities				0	0
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent				(724)	(604)
Defined Benefit Plan, Funded Status of Plan				(724)	(604)
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				(682)	(558)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax				(5)	(4)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax				(687)	(562)
Defined Benefit Plan, Accumulated Benefit Obligation				2,834	2,615
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	$ 2,050	$ 2,377	$ 2,377	2,160	$ 2,050	$ 2,377
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, 2017				235
Defined Benefit Plan, Expected Future Benefit Payments, 2018				237
Defined Benefit Plan, Expected Future Benefit Payments, 2019				232
Defined Benefit Plan, Expected Future Benefit Payments, 2020				231
Defined Benefit Plan, Expected Future Benefit Payments, 2021				220
Defined Benefit Plan, Expected Future Benefit Payments, 2022-2026				$ 1,016
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate				3.83%	4.05%	3.66%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase				3.52%	3.50%	4.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	7.31%	7.50%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.51%	4.50%	3.50%
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income [Abstract]
Defined Benefit Plan, Service Cost	$ 36	$ 33	$ 21
Defined Benefit Plan, Interest Cost	89	99	112
Defined Benefit Plan, Expected Return on Plan Assets	(151)	(172)	(171)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	1	0	0
Defined Benefit Plan, Amortization of Net Actuarial Loss (Gain)	35	5	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements and Curtailments	0	0	0
Defined Benefit Plan, Net Periodic Benefit Cost	10	(35)	(38)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	116	267	285
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	(34)	(5)	0
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax	0	0	0
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax	1	0	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Tax	83	262	285
Total Net benefit cost and other comprehensive income (loss) recognized	93	227	247
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	356
Defined Benefit Plan, Fair Value of Plan Assets, end of year	490	356
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	356	356		$ 490	$ 356
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	15
Defined Benefit Plan, Fair Value of Plan Assets, end of year	10	15
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	15	15		10	15
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	70
Defined Benefit Plan, Fair Value of Plan Assets, end of year	197	70
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	70	70		197	70
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	271
Defined Benefit Plan, Fair Value of Plan Assets, end of year	283	271
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	271	271		283	271
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 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	545
Defined Benefit Plan, Fair Value of Plan Assets, end of year	526	545
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	545	545		526	545
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	110
Defined Benefit Plan, Fair Value of Plan Assets, end of year	100	110
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	110	110		100	110
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	449
Defined Benefit Plan, Fair Value of Plan Assets, end of year	428	449
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	449	449		428	449
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	(14)
Defined Benefit Plan, Fair Value of Plan Assets, end of year	(2)	(14)
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	(14)	(14)		(2)	(14)
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	15
Defined Benefit Plan, Fair Value of Plan Assets, end of year	16	15
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	15	15		16	15
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	15	15
Defined Benefit Plan, Fair Value of Plan Assets, end of year	16	15	15
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	15	15	15	16	15	$ 15
Changes in Pension and OPEB Assets [Abstract]
Defined Benefit Plan, Transfers Between Measurement Levels	0	0
Defined Benefit Plan Change in Fair Value of Plan Assets Level 3 Reconciliation, Period Increase (Decrease)	1	0
Defined Benefit Plan, Purchases, Sales, and Settlements	0	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
Other Postretirement Benefit Plan [Member]
Pension Plans [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost	(5)	(4)	(2)
Other Postretirement Benefit Plans [Abstract]
Purchase of Medical Coverage through Medicare Exchange Participant, Age							65
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, beginning of period	509	624
Defined Benefit Plan, Service Cost	1	0	0
Defined Benefit Plan, Interest Cost	16	21	25
Defined Benefit Plan, Actuarial (Gain) Loss	(42)	(101)
Defined Benefit Plan, Benefits Paid	(41)	(39)
Defined Benefit Plan, Contributions by Plan Participants	2	2
Defined Benefit Plan, Medicare Part D Subsidy Receipts	1	2
Defined Benefit Plan, Foreign Currency Exchange Rate Gain (Loss)	1	0
Defined Benefit Plan, Benefit Obligation, end of period	473	509	624
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	325	389
Defined Benefit Plan, Actual (Loss) Return on Plan Assets	29	(45)
Defined Benefit Plan, Contributions by Employer	16	16
Defined Benefit Plan, Contributions by Plan Participants	2	2
Defined Benefit Plan, Medicare Part D Subsidy Receipts	1	2
Defined Benefit Plan, Benefits Paid	(41)	(39)
Defined Benefit Plan, Foreign Currency Exchange Rate Changes, Plan Assets	0	0
Defined Benefit Plan, Fair Value of Plan Assets, end of year	332	325	389
Defined Benefit Plan, Funded Status of Plan				(141)	(184)
Components of Funded Status [Abstract]
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent				153	139
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities				(16)	(16)
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent				(278)	(307)
Defined Benefit Plan, Funded Status of Plan				(141)	(184)
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax				69	23
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax				18	19
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax				87	42
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation				415	444
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets				121	121
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	$ 325	$ 389	$ 389	332	$ 325	$ 389
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, 2017				39
Defined Benefit Plan, Expected Future Benefit Payments, 2018				38
Defined Benefit Plan, Expected Future Benefit Payments, 2019				39
Defined Benefit Plan, Expected Future Benefit Payments, 2020				37
Defined Benefit Plan, Expected Future Benefit Payments, 2021				37
Defined Benefit Plan, Expected Future Benefit Payments, 2022-2026				$ 168
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate				3.69%	3.91%	3.56%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	7.07%	7.08%	7.43%
Unrelated Business Income Tax Rate	21.00%	21.00%	21.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	9.30%
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	$ 2
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	27	31
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	(23)	(27)
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income [Abstract]
Defined Benefit Plan, Service Cost	1	0	$ 0
Defined Benefit Plan, Interest Cost	16	21	25
Defined Benefit Plan, Expected Return on Plan Assets	(19)	(23)	(24)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(3)	(3)	(2)
Defined Benefit Plan, Amortization of Net Actuarial Loss (Gain)	0	1	(1)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements and Curtailments	0	0	0
Defined Benefit Plan, Net Periodic Benefit Cost	(5)	(4)	(2)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	(48)	(49)	10
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	0	(1)	0
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, Pension and Other Postretirement Benefit Plans, Adjustment, before Tax	(47)	(49)	11
Total Net benefit cost and other comprehensive income (loss) recognized	(52)	(53)	9
Other Postretirement Benefit 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	60
Defined Benefit Plan, Fair Value of Plan Assets, end of year	69	60
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	60	60		$ 69	$ 60
Other Postretirement Benefit 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 Benefit 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 Benefit 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	8
Defined Benefit Plan, Fair Value of Plan Assets, end of year	11	8
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	8	8		11	8
Other Postretirement Benefit 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	51
Defined Benefit Plan, Fair Value of Plan Assets, end of year	57	51
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	51	51		57	51
Other Postretirement Benefit 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 Benefit 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	16
Defined Benefit Plan, Fair Value of Plan Assets, end of year	15	16
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16	16		15	16
Other Postretirement Benefit 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	16
Defined Benefit Plan, Fair Value of Plan Assets, end of year	15	16
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16	16		15	16
Other Postretirement Benefit 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 Benefit 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 Benefit 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 Benefit 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 Benefit 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	49
Defined Benefit Plan, Fair Value of Plan Assets, end of year	47	49
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	49	49		47	49
Other Postretirement Benefit 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 Benefit 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 Benefit 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 Benefit 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 Benefit 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	49	51
Defined Benefit Plan, Fair Value of Plan Assets, end of year	47	49	51
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	49	51	51	47	49	$ 51
Changes in Pension and OPEB Assets [Abstract]
Defined Benefit Plan, Transfers Between Measurement Levels	0	0
Defined Benefit Plan Change in Fair Value of Plan Assets Level 3 Reconciliation, Period Increase (Decrease)	(2)	(1)
Defined Benefit Plan, Purchases, Sales, and Settlements	0	(1)
United States Pension Plan of US Entity [Member]
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Fiscal Year	$ 22
United States Pension Plan of US Entity [Member] | Cash [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	0.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	5.00%
United States Pension Plan of US Entity [Member] | Equity Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	34.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	59.00%
United States Pension Plan of US Entity [Member] | Fixed Income Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	37.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	57.00%
United States Pension Plan of US Entity [Member] | Alternative Investments [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	0.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	2.00%
United States Pension Plan of US Entity [Member] | Class P | Equity Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	0.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	10.00%
United States Postretirement Benefit Plan of US Entity [Member]
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Fiscal Year	$ 7
United States Postretirement Benefit Plan of US Entity [Member] | Cash [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	0.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	20.00%
United States Postretirement Benefit Plan of US Entity [Member] | Equity Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	15.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	55.00%
United States Postretirement Benefit Plan of US Entity [Member] | Master Limited Partnerships [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	13.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	39.00%
United States Postretirement Benefit Plan of US Entity [Member] | Fixed Income Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	15.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	47.00%
Canadian Pension Plan [Member]
Pension Plans [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost		12	10
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Other Changes	$ 151	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Other	119	0
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Fiscal Year	$ 8
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost		12	$ 10
Canadian Pension Plan [Member] | Equity Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	0.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	55.00%
Canadian Pension Plan [Member] | Fixed Income Securities [Member]
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	45.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	100.00%
Canadian Postretirement Benefit Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Other Changes	$ 26	0
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
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	916
Defined Benefit Plan, Fair Value of Plan Assets, end of year	1,032	916
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	916	916		1,032	916
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	15
Defined Benefit Plan, Fair Value of Plan Assets, end of year	10	15
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	15	15		10	15
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	110
Defined Benefit Plan, Fair Value of Plan Assets, end of year	100	110
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	110	110		100	110
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	70
Defined Benefit Plan, Fair Value of Plan Assets, end of year	197	70
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	70	70		197	70
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	271
Defined Benefit Plan, Fair Value of Plan Assets, end of year	283	271
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	271	271		283	271
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	449
Defined Benefit Plan, Fair Value of Plan Assets, end of year	428	449
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	449	449		428	449
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	15
Defined Benefit Plan, Fair Value of Plan Assets, end of year	16	15
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	15	15		16	15
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	(14)
Defined Benefit Plan, Fair Value of Plan Assets, end of year	(2)	(14)
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	(14)	(14)		(2)	(14)
Within Fair Value Hierarchy [Member] | 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	91
Defined Benefit Plan, Fair Value of Plan Assets, end of year	126	91
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	91	91		126	91
Within Fair Value Hierarchy [Member] | Other Postretirement Benefit 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	125
Defined Benefit Plan, Fair Value of Plan Assets, end of year	131	125
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	125	125		131	125
Within Fair Value Hierarchy [Member] | Other Postretirement Benefit 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	16
Defined Benefit Plan, Fair Value of Plan Assets, end of year	15	16
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	16	16		15	16
Within Fair Value Hierarchy [Member] | Other Postretirement Benefit 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 Benefit 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	8
Defined Benefit Plan, Fair Value of Plan Assets, end of year	11	8
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	8	8		11	8
Within Fair Value Hierarchy [Member] | Other Postretirement Benefit 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	51
Defined Benefit Plan, Fair Value of Plan Assets, end of year	57	51
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	51	51		57	51
Within Fair Value Hierarchy [Member] | Other Postretirement Benefit 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	49
Defined Benefit Plan, Fair Value of Plan Assets, end of year	47	49
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	49	49		47	49
Fair Value, Net Asset Value as Practical Expedient [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	1,134
Defined Benefit Plan, Fair Value of Plan Assets, end of year	1,128	1,134
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	1,134	1,134		1,128	1,134
Fair Value, Net Asset Value as Practical Expedient [Member] | Pension Plan [Member] | Common collective trusts [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	775
Defined Benefit Plan, Fair Value of Plan Assets, end of year	829	775
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	775	775		829	775
Fair Value, Net Asset Value as Practical Expedient [Member] | Pension Plan [Member] | Private Investment Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	347
Defined Benefit Plan, Fair Value of Plan Assets, end of year	290	347
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	347	347		290	347
Fair Value, Net Asset Value as Practical Expedient [Member] | Pension Plan [Member] | Limited Partnership [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	12
Defined Benefit Plan, Fair Value of Plan Assets, end of year	9	12
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	12	12		9	12
Fair Value, Net Asset Value as Practical Expedient [Member] | Other Postretirement Benefit 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	200
Defined Benefit Plan, Fair Value of Plan Assets, end of year	201	200
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	200	200		201	200
Fair Value, Net Asset Value as Practical Expedient [Member] | Other Postretirement Benefit Plan [Member] | Common collective trusts [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	71
Defined Benefit Plan, Fair Value of Plan Assets, end of year	68	71
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	71	71		68	71
Fair Value, Net Asset Value as Practical Expedient [Member] | Other Postretirement Benefit Plan [Member] | Fixed Income Trusts [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	58
Defined Benefit Plan, Fair Value of Plan Assets, end of year	64	58
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	58	58		64	58
Fair Value, Net Asset Value as Practical Expedient [Member] | Other Postretirement Benefit Plan [Member] | Limited Partnership [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets, beginning of year	71
Defined Benefit Plan, Fair Value of Plan Assets, end of year	69	71
Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets	71	$ 71		69	$ 71
Each of Next Five Years [Member] | Other Postretirement Benefit Plan [Member]
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Medicare prescription drug, improvement and modernization act, annual subsidy	3
Five Fiscal Years Thereafter [Member] | Other Postretirement Benefit Plan [Member]
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Medicare prescription drug, improvement and modernization act, annual subsidy	$ 16
Benefit obligation [Member] | Pension Plan [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.05%	3.66%	4.45%
Benefit obligation [Member] | Other Postretirement Benefit Plan [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.91%	3.56%	4.34%
Discount rate for interest on benefit obligations [Member] | Pension Plan [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.24%	3.66%	4.45%
Discount rate for interest on benefit obligations [Member] | Other Postretirement Benefit Plan [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.18%	3.56%	4.34%
Discount rate for service cost [Member] | Pension Plan [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.15%	3.66%	4.45%
Discount rate for service cost [Member] | Other Postretirement Benefit Plan [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.36%	3.56%	4.34%
Discount rate for interest on service cost [Member] | Pension Plan [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.50%	3.66%	4.45%
Discount rate for interest on service cost [Member] | Other Postretirement Benefit Plan [Member]
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.17%	3.56%	4.34%
Other Affiliates [Member] | Other Postretirement Benefit Plan [Member]
Pension Plans [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost	$ 4
Components of Funded Status [Abstract]
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent				29
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent				$ (12)
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost	$ 4
Equity Securities [Member] | Fair Value, Net Asset Value as Practical Expedient [Member] | Pension Plan [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				61.00%	55.00%
Equity Securities [Member] | Fair Value, Net Asset Value as Practical Expedient [Member] | Pension Plan [Member] | Private Investment Funds [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				46.00%	54.00%
Equity Securities [Member] | Fair Value, Net Asset Value as Practical Expedient [Member] | Other Postretirement Benefit Plan [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				72.00%	67.00%
Fixed Income Securities [Member] | Fair Value, Net Asset Value as Practical Expedient [Member] | Pension Plan [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				39.00%	45.00%
Fixed Income Securities [Member] | Fair Value, Net Asset Value as Practical Expedient [Member] | Pension Plan [Member] | Private Investment Funds [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				54.00%	46.00%
Fixed Income Securities [Member] | Fair Value, Net Asset Value as Practical Expedient [Member] | Other Postretirement Benefit Plan [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations				28.00%	33.00%

Share-based Compensation and 86

Share-based Compensation and Employee Benefits Other Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 8	$ 10	$ 13

Common Equity (Details)

Common Equity (Details) $ / shares in Units, $ in Millions	Jan. 18, 2017$ / shares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 19, 2014USD ($)	Dec. 31, 2013shares
Class of Stock [Line Items]
Warrant Repurchase Program, Remaining Authorized Repurchase Amount | $		$ 90
Payments for Repurchase of Warrants | $			$ 12	$ 98
Share issued (in shares)			103,000,000
Issuances of common shares | $			$ 3,870
Dividends Per Common Share Declared for the Period | $ / shares		$ 0.50	$ 1.605	$ 1.74
Debt Instrument, Convertible, Conversion Ratio		1
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ / shares		$ 40
Warrants outstanding		293,263,797	293,263,797	298,135,976		347,933,107
Warrants exercised		0	(71,268)	(18,040)
Warrants repurchased and canceled		0	(6,094,526)	(49,783,406)
Class P
Class of Stock [Line Items]
Payments for Repurchase of Common Stock | $				$ 94
Dividends Per Common Share Declared for the Period | $ / shares		$ 0.50	$ 1.605	$ 1.74
Per common share cash dividend paid in the period | $ / shares		0.50	$ 1.93	$ 1.70
Subsequent Event [Member]
Class of Stock [Line Items]
Dividends Per Common Share Declared for the Period | $ / shares	$ 0.125
Warrant [Member]
Class of Stock [Line Items]
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ / shares		$ 40
Conversion of EP Trust I Preferred Securities [Member]
Class of Stock [Line Items]
Warrants issued with conversions of EP Trust I Preferred securities(a)		0	1,293,615	4,315
Equity distribution agreement [Member] | Class P
Class of Stock [Line Items]
Stock Sold During the Period, Shares			102,614,508
Value of Stock Available for Sale Under Equity Distribution Agreement | $					$ 5,000
Share issued (in shares)			102,614,508
Issuances of common shares | $			$ 3,900

Stockholders' Equity Mandatory

Stockholders' Equity Mandatory Convertible Preferred Stock (Details) $ / shares in Units, $ in Millions	Oct. 19, 2016$ / shares	Oct. 30, 2015USD ($)$ / sharesshares	Dec. 31, 2016$ / sharesshares	Dec. 31, 2015$ / sharesshares
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
Issuances of common shares | shares				103,000,000
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%
Preferred Stock, Liquidation Preference Per Share		$ 1,000
Dividends, Preferred Stock	$ 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) - USD ($) $ / shares in Units, $ in Millions	11 Months Ended	12 Months Ended
	Nov. 25, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Contributions from noncontrolling interests		$ 117	$ 11	$ 1,767
KMP, EPB and KMR [Member]
Contributions from noncontrolling interests	$ 1,695
Noncontrolling Interest, Increase from Subsidiary Equity Issuance	1,640
Income Tax Effects Allocated Directly to Equity, Equity Transactions	19
Adjustments to Additional Paid in Capital, Other	$ 36
KMP(a)
Per unit cash distribution declared for the period				$ 4.17
Per unit cash distribution paid in the period				$ 5.53
Cash distributions paid in the period to the public				$ 1,654
EPB(a)
Per unit cash distribution declared for the period				$ 1.95
Per unit cash distribution paid in the period				$ 2.60
Cash distributions paid in the period to the public				$ 347
KMR(a)(b)
Share distributions paid in the period to the public				7,794,183
Subsidiary Share Distribution, Shares Distributed to Parent				1,127,712
Equity distribution agreement [Member] | KMP, EPB and KMR [Member]
Noncontrolling Interest, Shares or Equity Units Issued	30,000,000

Related Party Transactions Affi

Related Party Transactions Affiliated Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
RELATED PARTY ASSETS
Other current assets	$ 337	$ 266
Deferred charges and other assets	1,522	2,029
RELATED PARTY LIABILITIES [Abstract]
Other current liabilities	1,085	1,059
RELATED PARTY REVENUES [Abstract]
Services	8,146	8,290	$ 7,650
Product sales and other	2,458	3,274	4,461
Total Revenues	13,058	14,403	16,226
RELATED PARTY COST OF SALES [Abstract]
Costs of sales	3,498	4,115	6,278
Other operating expenses	386	2,066	275
Affiliated Entity [Member]
RELATED PARTY ASSETS
Accounts receivable, net	37	25
Other current assets	0	36
Deferred charges and other assets	10	0
Total Assets	47	61
RELATED PARTY LIABILITIES [Abstract]
Current portion of debt	6	6
Accounts payable	28	22
Other current liabilities	9	10
Long-term debt	161	167
Other long-term liabilities and deferred credits	29	0
Total Liabilities	233	205
RELATED PARTY REVENUES [Abstract]
Services	71	72	29
Product sales and other	71	71	86
Total Revenues	142	143	115
RELATED PARTY COST OF SALES [Abstract]
Costs of sales	38	60	74
Other operating expenses	$ 75	$ 55	$ 57

Related Party Transactions Note

Related Party Transactions Notes Receivable (Details) - USD ($)	Mar. 01, 2016	Feb. 03, 2017	Dec. 31, 2016	Dec. 31, 2015
Loans Receivable [Member] | Midcontinent Express Pipeline LLC [Member]
Related Party Transaction [Line Items]
Notes receivable from affiliates			$ 0	$ 0
Plantation Pipe Line Company
Related Party Transaction [Line Items]
Notes Receivable Principal Received, Related Party	$ 35,000,000
Equity Method Investment, Ownership Percentage			51.17%
Notes receivable from affiliates				$ 35,000,000
Subsequent Event [Member] | Loans Receivable [Member] | Midcontinent Express Pipeline LLC [Member] | Midcontinent Express Pipeline LLC [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage		50.00%
Subsequent Event [Member] | Maximum [Member] | Loans Receivable [Member] | Midcontinent Express Pipeline LLC [Member]
Related Party Transaction [Line Items]
Notes Receivable, Borrowing Capacity		$ 40,000,000

Related Party Transactions Subs

Related Party Transactions Subsequent Event (Details) - Loans Receivable [Member] - MEP - USD ($)	Feb. 03, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Notes receivable from affiliates, current		$ 0	$ 0
Subsequent Event [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Notes Receivable, Borrowing Capacity	$ 40,000,000
MEP | Subsequent Event [Member]
Related Party Transaction [Line Items]
Renewal Term	1 year
Equity Method Investment, Ownership Percentage	50.00%
MEP | London Interbank Offered Rate (LIBOR) [Member] | Subsequent Event [Member]
Related Party Transaction [Line Items]
Loans Receivable, Basis Spread on Variable Rate	1.50%

Commitments and Contingent Li93

Commitments and Contingent Liabilities Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 106
Operating Leases, Future Minimum Payments, Due in Two Years	94
Operating Leases, Future Minimum Payments, Due in Three Years	86
Operating Leases, Future Minimum Payments, Due in Four Years	75
Operating Leases, Future Minimum Payments, Due in Five Years	61
Operating Leases, Future Minimum Payments, Due Thereafter	342
Operating Leases, Future Minimum Payments Due	764
Operating Leases, Rent Expense	$ 138	$ 143	$ 114
Minimum [Member]
Operating Leased Assets [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract	1 year
Maximum [Member]
Operating Leased Assets [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract	41 years

Commitments and Contingent Li94

Commitments and Contingent Liabilities Contingent Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 1,179	$ 1,202
Cortez Pipeline Company
Guarantor Obligations [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
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	$ 100
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

Commitments and Contingent Li95

Commitments and Contingent Liabilities Guarantees and Indemnifications (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 1,179	$ 1,202

Commitments and Contingent Li96

Commitments and Contingent Liabilities Commitments for Jones Act (Details) $ in Millions	Dec. 31, 2016USD ($)
Philly Tankers LLC [Member]
Other Commitments [Line Items]
Purchase Obligation, Due in Next Twelve Months	$ 383
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	$ 195
Philly Tankers LLC [Member]
Other Commitments [Line Items]
Number of Vessels	4

Energy Commodity Price Risk Man

Energy Commodity Price Risk Managment (Details) - Energy commodity derivative contracts(a)	Dec. 31, 2016MMBblsBcf
Designated as Hedging Instrument [Member] | Crude Oil Fixed Price [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	(19.7)
Designated as Hedging Instrument [Member] | Crude Oil Basis [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	(1.3)
Designated as Hedging Instrument [Member] | Natural Gas Fixed Price [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf	(38.4)
Designated as Hedging Instrument [Member] | Natural Gas Basis [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf	(19.3)
Not Designated as Hedging Instrument [Member] | Crude Oil Fixed Price [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	(1.7)
Not Designated as Hedging Instrument [Member] | Crude Oil Basis [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	(0.1)
Not Designated as Hedging Instrument [Member] | Natural Gas Fixed Price [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf	(5.2)
Not Designated as Hedging Instrument [Member] | Natural Gas Basis [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf	(1.4)
Not Designated as Hedging Instrument [Member] | NGL and other fixed price
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	(5)

Interest Rate Risk Managment (D

Interest Rate Risk Managment (Details) - Interest rate swap agreements - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative, Notional Amount		$ 11,000
Fair Value Hedging [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 9,775	$ 9,700

Risk Management Foreign Currenc

Risk Management Foreign Currency Risk Management (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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
Kinder Morgan, Inc. [Member] | KMI 1.50% Senior Notes Due 2022 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		1.50%
Kinder Morgan, Inc. [Member] | KMI 2.25% Senior Notes Due 2027 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.25%
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, 2016	Dec. 31, 2015
Interest rate swap agreements
Derivatives, Fair Value [Line Items]
Asset derivatives	$ 282	$ 377
Liability derivatives	(39)	(17)
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	471	987
Liability derivatives	(169)	(74)
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a)
Derivatives, Fair Value [Line Items]
Asset derivatives	171	603
Liability derivatives	(81)	(13)
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	101	359
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(57)	(13)
Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	70	244
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)	0
Designated as Hedging Instrument [Member] | Interest rate swap agreements
Derivatives, Fair Value [Line Items]
Asset derivatives	300	384
Liability derivatives	(57)	(9)
Designated as Hedging Instrument [Member] | Currency Swap [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Liability derivatives	(31)	(52)
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Interest rate swap agreements | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	94	111
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Interest rate swap agreements | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	0	0
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Interest rate swap agreements | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	206	273
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Interest rate swap agreements | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(57)	(9)
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Currency Swap [Member] | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Currency Swap [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(7)	(6)
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Currency Swap [Member] | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Currency Swap [Member] | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(24)	(46)
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	474	1,024
Liability derivatives	(199)	(108)
Not Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a)
Derivatives, Fair Value [Line Items]
Asset derivatives	3	35
Liability derivatives	(30)	(1)
Not Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	3	35
Not Designated as Hedging Instrument [Member] | Energy commodity derivative contracts(a) | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(29)	(1)
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	(1)	0
Not Designated as Hedging Instrument [Member] | Interest rate swap agreements
Derivatives, Fair Value [Line Items]
Asset derivatives	0	1
Liability derivatives	0	(16)
Not Designated as Hedging Instrument [Member] | Interest rate swap agreements | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	1
Not Designated as Hedging Instrument [Member] | Interest rate swap agreements | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	0	(11)
Not Designated as Hedging Instrument [Member] | Interest rate swap agreements | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Not Designated as Hedging Instrument [Member] | Interest rate swap agreements | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	0	(5)
Not Designated as Hedging Instrument [Member] | Power Derivative Contract [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	1
Liability derivatives	0	(17)
Not Designated as Hedging Instrument [Member] | Power Derivative Contract [Member] | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	1
Not Designated as Hedging Instrument [Member] | Power Derivative Contract [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	0	(17)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	3	37
Liability derivatives	$ (30)	$ (34)

Effect of Derivative Contracts

Effect of Derivative Contracts on the Income Statement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Interest rate swap agreements | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 63	$ (15)	$ 0
Energy commodity derivative contracts(a)
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	30	176	11
Derivative, Loss on Derivative	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	(10)	17	(7)
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	(26)	176	20
Energy commodity derivative contracts(a) | Costs of sales
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3	(2)	0
Energy commodity derivative contracts(a) | Other expense (income) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0	(2)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Loss to be reclassified within twelve months	8
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	(104)	164	409
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)	116	272	25
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	(12)	2	11
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	(2)	(4)	(15)
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	(180)	25	207
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)	(4)
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	160	(33)	(204)
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	(115)	201	424
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)	15	54	(1)
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)	148	236	26
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	(12)	2	11
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)	(17)	(15)	4
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	13	(33)	0
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)	(27)	0	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, 2016	Dec. 31, 2015
Credit Derivatives [Line Items]
Letters of Credit Outstanding, Amount	$ 160
Energy commodity derivative contracts(a)
Credit Derivatives [Line Items]
Letters of Credit Outstanding, Amount	0	$ 2
Contract and Over the Counter [Member] | Energy commodity derivative contracts(a)
Credit Derivatives [Line Items]
Derivative, Collateral, Right to Reclaim Cash	37	0
Derivative, Collateral, Obligation to Return Cash	0	$ 37
One notch credit downgrade [Member] | Energy commodity derivative contracts(a)
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	10
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, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 219	$ 327	$ (3)
Accumulated Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Net of Tax	(322)	(108)	2
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(358)	(236)	(23)
Accumulated other comprehensive loss	(461)	(17)	(24)
Other Comprehensive Income Unrealized Gain Loss On Derivatives Arising During Period Net Of Tax Portion Attributable To Parent	(104)	164	254
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax, Before Reclassifications, Portion Attributable to Parent	34	(214)	(68)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax	(14)	(122)	(212)
OCI, before Reclassifications, Net of Tax, Attributable to Parent	(84)	(172)	(26)
Other Comprehensive Income Reclassification Adjustment On Derivatives Included In Net Income Net Of Tax Portion Attributable To Parent	(116)	(272)	(22)
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	(1)
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	(116)	(272)	(23)
Other Comprehensive Income Impact of Merger Transactions on Derivatives Arising During Period Net Of Tax Portion Attributable To Parent			98
Other Comprehensive Income (Loss), Foreign Currency adjustment on Impact of Merger Transactions, Net of Tax			(42)
Other Comprehensive (Income) Loss, Impact of Merger Transactions on Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax			0
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent, Impact of Merger Transactions			56
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax, Portion Attributable to Parent	(220)	(108)	330
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax, Portion Attributable to Parent	34	(214)	(110)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent	(14)	(122)	(213)
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), Pension and Other Postretirement Benefit Plans, Net of Tax	(372)	(358)	(236)
Accumulated other comprehensive loss	(661)	(461)	(17)
Net current-period other comprehensive (loss) income	$ (200)	$ (444)	$ 7

Fair Value of Derivative Contra

Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Energy commodity derivative contracts(a)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 174	$ 639
Derivative Asset, Contracts Available for Netting	(43)	(12)
Derivative Liability, Fair Value, Gross Liability	(111)	(31)
Derivative Liability, Not Offset, Policy Election Deduction	43	12
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	(15)	(61)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Liability Net, Gain (Loss) Included in Earnings	(9)	(13)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Liability Net, Settlements	24	59
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	0	(15)
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	300	385
Derivative Asset, Contracts Available for Netting	(18)	(8)
Derivative Liability, Fair Value, Gross Liability	(57)	(25)
Derivative Liability, Not Offset, Policy Election Deduction	18	8
Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Contracts Available for Netting	0	0
Derivative Liability, Fair Value, Gross Liability	(31)	(52)
Derivative Liability, Not Offset, Policy Election Deduction	0	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	6	48
Derivative Liability, Fair Value, Gross Liability	(29)	(4)
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	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	168	589
Derivative Liability, Fair Value, Gross Liability	(82)	(10)
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	300	385
Derivative Liability, Fair Value, Gross Liability	(57)	(25)
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	0	0
Derivative Liability, Fair Value, Gross Liability	(31)	(52)
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	2
Derivative Liability, Fair Value, Gross Liability	0	(17)
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	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	131	590
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(31)	(19)
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	282	377
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(39)	(17)
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	0	0
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(31)	(52)
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	0	(37)
Derivative, Collateral, Right to Reclaim Cash	37	0
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	0	0
Derivative, Collateral, Right to Reclaim Cash	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	0	0
Derivative, Collateral, Right to Reclaim Cash	$ 0	$ 0

Fair Value of Debt (Details)

Fair Value of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 1,149	$ 1,674
Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	40,050	43,227
Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 41,015	$ 37,481

Reportable Segments Revenues (D

Reportable Segments Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues
Revenues	$ 13,058	$ 14,403	$ 16,226
Single customer exceeding 10% of total [Member]
Revenues
Revenues	0	0	0
Operating Segments | CO2
Revenues
Revenues	1,221	1,699	1,960
Operating Segments | Kinder Morgan Canada
Revenues
Revenues	253	260	291
Operating Segments | External Customer [Member] | Natural Gas Pipelines
Revenues
Revenues	7,998	8,704	10,153
Operating Segments | External Customer [Member] | Terminals
Revenues
Revenues	1,921	1,878	1,717
Operating Segments | External Customer [Member] | Products Pipelines
Revenues
Revenues	1,631	1,828	2,068
Operating Segments | Intersegment revenues | Natural Gas Pipelines
Revenues
Revenues	7	21	15
Operating Segments | Intersegment revenues | Terminals
Revenues
Revenues	1	1	1
Operating Segments | Intersegment revenues | Products Pipelines
Revenues
Revenues	18	3	0
Corporate, Non-Segment and intersegment eliminations
Revenues
Revenues	$ 8	$ 9	$ 21

Reportable Segments Operating e

Reportable Segments Operating expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Operating expenses(b)	$ 6,222	$ 6,891	$ 8,853
Total segment assets | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Operating expenses(b)	4,393	4,738	6,241
Total segment assets | CO2
Segment Reporting Information [Line Items]
Operating expenses(b)	399	432	494
Total segment assets | Terminals
Segment Reporting Information [Line Items]
Operating expenses(b)	768	836	746
Total segment assets | Products Pipelines
Segment Reporting Information [Line Items]
Operating expenses(b)	573	772	1,258
Total segment assets | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Operating expenses(b)	87	87	106
Corporate, Non-Segment and intersegment eliminations
Segment Reporting Information [Line Items]
Operating expenses(b)	$ 2	$ 26	$ 8

Reportable Segments Other expen

Reportable Segments Other expense (income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Other operating expenses	$ 386	$ 2,066	$ 275
Total segment assets | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other operating expenses	199	1,269	5
Total segment assets | CO2
Segment Reporting Information [Line Items]
Other operating expenses	19	606	243
Total segment assets | Terminals
Segment Reporting Information [Line Items]
Other operating expenses	99	190	29
Total segment assets | Products Pipelines
Segment Reporting Information [Line Items]
Other operating expenses	76	2	(3)
Total segment assets | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Other operating expenses	0	(1)	0
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Other operating expenses	$ (7)	$ 0	$ 1

Reportable Segments Depreciatio

Reportable Segments Depreciation, depletion and amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
DD&A	$ 2,209	$ 2,309	$ 2,040
Total segment assets | Natural Gas Pipelines
Segment Reporting Information [Line Items]
DD&A	1,041	1,046	897
Total segment assets | CO2
Segment Reporting Information [Line Items]
DD&A	446	556	570
Total segment assets | Terminals
Segment Reporting Information [Line Items]
DD&A	435	433	337
Total segment assets | Products Pipelines
Segment Reporting Information [Line Items]
DD&A	221	206	166
Total segment assets | Kinder Morgan Canada
Segment Reporting Information [Line Items]
DD&A	44	46	51
Corporate, Non-Segment
Segment Reporting Information [Line Items]
DD&A	$ 22	$ 22	$ 19

Reportable Segments Earnings (l

Reportable Segments Earnings (loss) from equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	$ (172)	$ 333	$ 361
Total segment assets | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	(269)	285	279
Total segment assets | CO2
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	22	(5)	26
Total segment assets | Terminals
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	19	17	18
Total segment assets | Products Pipelines
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	56	36	37
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	$ 0	$ 0	$ 1

Reportable Segments Other, net-

Reportable Segments Other, net-income(expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Other, net	$ 44	$ 43	$ 80
Including gains on remeasurement and sales of investments [Member]
Segment Reporting Information [Line Items]
Other, net	44	43	80
Total segment assets | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other, net	19	24	24
Total segment assets | Terminals
Segment Reporting Information [Line Items]
Other, net	4	8	12
Total segment assets | Products Pipelines
Segment Reporting Information [Line Items]
Other, net	2	4	(1)
Total segment assets | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Other, net	15	8	15
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Other, net	$ 4	$ (1)	$ 30

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
DD&A	$ (2,209)	$ (2,309)	$ (2,040)
Amortization of excess cost of equity investments	(59)	(51)	(45)
General and administrative expenses	(669)	(690)	(610)
Interest expense, net	(1,806)	(2,051)	(1,798)
Income tax expense	(917)	(564)	(648)
Net Income	721	208	2,443
Total segment operating expenses
Segment Reporting Information [Line Items]
Segment EBDA(d)	6,364	5,891	7,541
Total segment assets | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(d)	3,211	3,067	4,264
DD&A	(1,041)	(1,046)	(897)
Total segment assets | CO2
Segment Reporting Information [Line Items]
Segment EBDA(d)	827	658	1,248
DD&A	(446)	(556)	(570)
Total segment assets | Terminals
Segment Reporting Information [Line Items]
Segment EBDA(d)	1,078	878	973
DD&A	(435)	(433)	(337)
Total segment assets | Products Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(d)	1,067	1,106	856
DD&A	(221)	(206)	(166)
Total segment assets | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Segment EBDA(d)	181	182	200
DD&A	(44)	(46)	(51)
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Segment EBDA(d)	17	(18)	43
DD&A	$ (22)	$ (22)	$ (19)

Reportable Segments Capital exp

Reportable Segments Capital expenditures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Capital expenditures	$ 2,882	$ 3,896	$ 3,617
Total segment assets | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	1,227	1,642	935
Total segment assets | CO2
Segment Reporting Information [Line Items]
Capital expenditures	276	725	792
Total segment assets | Terminals
Segment Reporting Information [Line Items]
Capital expenditures	983	847	1,049
Total segment assets | Products Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	244	524	680
Total segment assets | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Capital expenditures	124	142	156
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Capital expenditures	$ 28	$ 16	$ 5

Reportable Segments Investments

Reportable Segments Investments (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Investments	$ 7,027	$ 6,040
Total segment assets | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments	6,185	5,080
Total segment assets | Terminals
Segment Reporting Information [Line Items]
Investments	252	306
Total segment assets | Products Pipelines
Segment Reporting Information [Line Items]
Investments	566	641
Total segment assets | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Investments	20	10
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Investments	$ 4	$ 3

Reportable Segments Assets (Det

Reportable Segments Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Assets at December 31	$ 80,305	$ 84,104
Assets held for sale	78	19
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Assets at December 31	6,108	6,694
Total segment assets | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets at December 31	50,428	53,704
Total segment assets | CO2
Segment Reporting Information [Line Items]
Assets at December 31	4,065	4,706
Total segment assets | Terminals
Segment Reporting Information [Line Items]
Assets at December 31	9,725	9,083
Total segment assets | Products Pipelines
Segment Reporting Information [Line Items]
Assets at December 31	8,329	8,464
Total segment assets | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Assets at December 31	$ 1,572	$ 1,434

Reportable Segments Geographica

Reportable Segments Geographical information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Total Revenues	$ 13,058	$ 14,403	$ 16,226
Long-term assets, excluding goodwill and other intangibles	51,606	53,939	52,341
U.S.
Segment Reporting Information [Line Items]
Total Revenues	12,459	13,797	15,605
Long-term assets, excluding goodwill and other intangibles	49,125	51,679	49,992
Canada
Segment Reporting Information [Line Items]
Total Revenues	483	479	437
Long-term assets, excluding goodwill and other intangibles	2,399	2,193	2,268
Mexico
Segment Reporting Information [Line Items]
Total Revenues	116	127	184
Long-term assets, excluding goodwill and other intangibles	$ 82	$ 67	$ 81

Reportable Segments Other (Deta

Reportable Segments Other (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues from External Customers [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	10.00%	10.00%	10.00%

Litigation, Environmental an118

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, 2016USD ($)
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	$ 190

Litigation, Environmental an119

Litigation, Environmental and Other Contingencies Other Commercial Matters (Details) - USD ($) $ in Millions	May 24, 2016	Feb. 04, 2016	Apr. 21, 2015	Oct. 25, 2013	Jan. 01, 2004	Sep. 30, 2013	Dec. 31, 2016	Sep. 01, 2011
Gulf LNG Holdings Group, LLC
Loss Contingencies [Line Items]
Equity Method Investment, Ownership Percentage							50.00%
Union Pacific Railroad Company v. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al. [Member] | Pending Litigation [Member] | SFPP L.P. [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value				$ 22.3
Lessee Leasing Arrangements, Operating Leases, Term of Contract				10 years	10 years
Union Pacific Railroad Company v. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al. [Member] | Pending Litigation [Member] | SFPP L.P. [Member] | Loss on Long-term Purchase Commitment [Member]
Loss Contingencies [Line Items]
Loss Contingency, Initial Award Amount, Annual Rent Payable								$ 14
Plains Gas Solutions, LLC v. Tennessee Gas Pipeline Company, L.L.C. et al [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value						$ 100
Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al. [Member]
Loss Contingencies [Line Items]
Payments to Acquire Businesses, Gross			$ 1,130
Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al. [Member] | Elba Liquefaction [Member]
Loss Contingencies [Line Items]
Business Acquisition, Additional Percentage of Interest Acquired			49.00%
Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al. [Member] | SNG
Loss Contingencies [Line Items]
Business Acquisition, Additional Percentage of Interest Acquired			15.00%
Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al. [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value			$ 171
Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al. [Member] | Tentative Settlement [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value		$ 100.2
Price Reporting Litigation [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 300
Price Reporting Litigation [Member] | Dismissed [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 500
Merger Transactions [Member] | Kinder Morgan Energy Partners, L.P. and El Paso Pipeline Partners, L.P. [Member]
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number							5

Litigation, Environmental an120

Litigation, Environmental and Other Contingencies Litigation General (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Loss Contingency, Information about Litigation Matters [Abstract]
Estimated Litigation Liability	$ 407	$ 463

Litigation, Environmental an121

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

Oct. 05, 2016USD ($)

Jul. 28, 2016

Jun. 17, 2016USD ($)

Jun. 08, 2016USD ($)

Dec. 18, 2015USD ($)

Nov. 08, 2013

Oct. 25, 2013USD ($)

Aug. 06, 2013Defendants

Jul. 24, 2013

Aug. 31, 2007USD ($)

Dec. 31, 2000Terminals

Dec. 31, 2016USD ($)TerminalsPartiesDefendants

Dec. 31, 2010USD ($)

Dec. 31, 1969

Dec. 31, 2015USD ($)

Loss Contingencies [Line Items]

Accrual for Environmental Loss Contingencies

$ 302

$ 284

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

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

Union Pacific Railroad Company v. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al. [Member] | Pending Litigation [Member] | SFPP L.P. [Member]

Loss Contingencies [Line Items]

Loss Contingency, Damages Sought, Value

$ 22.3

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

United States District Court, Southern District of California, case number 07CV1883WCAB [Member] | Pending Litigation [Member] | Mission Valley Terminal Facility [Member] | Kinder Morgan Energy Partners, L.P. [Member]

Loss Contingencies [Line Items]

Loss Contingency, Damages Sought, Value

$ 170

$ 365

United States District Court, Southern District of California, case number 07CV1883WCAB [Member] | Tentative Settlement [Member] | Mission Valley Terminal Facility [Member] | Kinder Morgan Energy Partners, L.P. [Member]

Loss Contingencies [Line Items]

Loss Contingency, Damages Sought, Value

$ 20

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] | 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

$ 1,100

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

Loss Contingencies [Line Items]

Environmental Remediation Expense

3,200

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

Loss Contingencies [Line Items]

Environmental Remediation Expense

$ 165

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

Loss Contingencies [Line Items]

Environmental Remediation Expense

$ 1,700

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

Guarantee of Securities of S122

Guarantee of Securities of Subsidiaries Guarantee of Securities of Subsidiaries (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Oct. 01, 2016	Sep. 01, 2016
Repayments of Debt		$ 10,060	$ 15,116	$ 17,801
Parent Issuer and Guarantor
Repayments of Debt		7,322	14,048	5,479
Total debt - KMI and Subsidiaries		14,235
Subsidiary Issuer and Guarantor - KMP
Repayments of Debt		500	675	12,171
Total debt - KMI and Subsidiaries		19,485
Subsidiary Guarantors
Repayments of Debt		2,227	$ 383	$ 142
Total debt - KMI and Subsidiaries		4,191
Capitalized Lease Debt Not Subject to Cross Guarantee Agreement		$ 169
KMP 7.125% Senior Notes due April 1, 2021 (Copano) [Member] | Subsidiary Issuer and Guarantor - Copano
Repayments of Debt	$ 332
Debt Instrument, Interest Rate, Stated Percentage	7.125%
Sale Equity Interest in SNG [Member]
Disposal Group, Equity Interest Sold						50.00%
Southern Natural Gas Company LLC [Member] | Sale Equity Interest in SNG [Member]
Disposal Group, Equity Interest Sold					50.00%	50.00%

Guarantee of Securities of S123

Guarantee of Securities of Subsidiaries Income Statement and Comprehensive Income (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Guarantor Obligations [Line Items]
Total Revenues	$ 13,058,000,000	$ 14,403,000,000	$ 16,226,000,000
Costs of sales	3,498,000,000	4,115,000,000	6,278,000,000
Depreciation, depletion and amortization	2,209,000,000	2,309,000,000	2,040,000,000
Other operating expenses	(1,000,000)	(3,000,000)	1,000,000
Total Operating Costs, Expenses and Other	9,486,000,000	11,956,000,000	11,778,000,000
Operating Income	3,572,000,000	2,447,000,000	4,448,000,000
Earnings from equity investments	497,000,000	414,000,000	406,000,000
Interest Income (Expense), Net	(1,806,000,000)	(2,051,000,000)	(1,798,000,000)
Amortization of excess cost of equity investments and other, net	44,000,000	43,000,000	80,000,000
Income Before Income Taxes	1,638,000,000	772,000,000	3,091,000,000
Income Tax Expense	(917,000,000)	(564,000,000)	(648,000,000)
Net Income	721,000,000	208,000,000	2,443,000,000
Net (Income) Loss Attributable to Noncontrolling Interests	(13,000,000)	45,000,000	(1,417,000,000)
Net Income Attributable to Kinder Morgan, Inc.	708,000,000	253,000,000	1,026,000,000
Preferred Stock Dividends	(156,000,000)	(26,000,000)	0
Net Income Available to Common Stockholders	552,000,000	227,000,000	1,026,000,000
Total other comprehensive (loss) income	200,000,000	444,000,000	(20,000,000)
Comprehensive income	521,000,000	(236,000,000)	2,463,000,000
Comprehensive (income) loss attributable to noncontrolling interests	(13,000,000)	45,000,000	(1,486,000,000)
Comprehensive income attributable to controlling interests	(508,000,000)	191,000,000	(977,000,000)
Parent Issuer and Guarantor
Guarantor Obligations [Line Items]
Total Revenues	34,000,000	37,000,000	36,000,000
Costs of sales	0	0	0
Depreciation, depletion and amortization	18,000,000	22,000,000	21,000,000
Other operating expenses	725,000,000	71,000,000	30,000,000
Total Operating Costs, Expenses and Other	743,000,000	93,000,000	51,000,000
Operating Income	(709,000,000)	(56,000,000)	(15,000,000)
Earnings from consolidated subsidiaries	2,948,000,000	1,430,000,000	2,080,000,000
Earnings from equity investments	0	0	0
Interest Income (Expense), Net	(696,000,000)	(686,000,000)	(513,000,000)
Amortization of excess cost of equity investments and other, net	0	0	0
Income Before Income Taxes	1,543,000,000	688,000,000	1,552,000,000
Income Tax Expense	(835,000,000)	(435,000,000)	(278,000,000)
Net Income	708,000,000	253,000,000	1,274,000,000
Net (Income) Loss Attributable to Noncontrolling Interests	0	0	(248,000,000)
Net Income Attributable to Kinder Morgan, Inc.	708,000,000	253,000,000	1,026,000,000
Preferred Stock Dividends	(156,000,000)	(26,000,000)
Net Income Available to Common Stockholders	552,000,000	227,000,000
Total other comprehensive (loss) income	200,000,000	444,000,000	24,000,000
Comprehensive income	508,000,000	(191,000,000)	1,250,000,000
Comprehensive (income) loss attributable to noncontrolling interests	0	0	(273,000,000)
Comprehensive income attributable to controlling interests	(508,000,000)	191,000,000	(977,000,000)
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	(36,000,000)	38,000,000	5,000,000
Total Operating Costs, Expenses and Other	(36,000,000)	38,000,000	5,000,000
Operating Income	36,000,000	(38,000,000)	(5,000,000)
Earnings from consolidated subsidiaries	2,826,000,000	1,643,000,000	3,977,000,000
Earnings from equity investments	0	0	0
Interest Income (Expense), Net	90,000,000	23,000,000	(111,000,000)
Amortization of excess cost of equity investments and other, net	0	1,000,000	0
Income Before Income Taxes	2,952,000,000	1,629,000,000	3,861,000,000
Income Tax Expense	(5,000,000)	(4,000,000)	(7,000,000)
Net Income	2,947,000,000	1,625,000,000	3,854,000,000
Net (Income) Loss Attributable to Noncontrolling Interests	0	0	(211,000,000)
Net Income Attributable to Kinder Morgan, Inc.	2,947,000,000	1,625,000,000	3,643,000,000
Preferred Stock Dividends	0	0
Net Income Available to Common Stockholders	2,947,000,000	1,625,000,000
Total other comprehensive (loss) income	341,000,000	460,000,000	(275,000,000)
Comprehensive income	2,606,000,000	1,165,000,000	4,129,000,000
Comprehensive (income) loss attributable to noncontrolling interests	0	0	(203,000,000)
Comprehensive income attributable to controlling interests	(2,606,000,000)	(1,165,000,000)	(3,926,000,000)
Subsidiary Guarantors
Guarantor Obligations [Line Items]
Total Revenues	11,572,000,000	12,840,000,000	14,575,000,000
Costs of sales	3,245,000,000	3,747,000,000	5,738,000,000
Depreciation, depletion and amortization	1,872,000,000	1,929,000,000	1,686,000,000
Other operating expenses	2,390,000,000	4,714,000,000	2,972,000,000
Total Operating Costs, Expenses and Other	7,507,000,000	10,390,000,000	10,396,000,000
Operating Income	4,065,000,000	2,450,000,000	4,179,000,000
Earnings from consolidated subsidiaries	245,000,000	118,000,000	443,000,000
Earnings from equity investments	(113,000,000)	384,000,000	407,000,000
Interest Income (Expense), Net	(1,149,000,000)	(1,345,000,000)	(1,084,000,000)
Amortization of excess cost of equity investments and other, net	(20,000,000)	(17,000,000)	(13,000,000)
Income Before Income Taxes	3,028,000,000	1,590,000,000	3,932,000,000
Income Tax Expense	(33,000,000)	(6,000,000)	(71,000,000)
Net Income	2,995,000,000	1,584,000,000	3,861,000,000
Net (Income) Loss Attributable to Noncontrolling Interests	0	0	0
Net Income Attributable to Kinder Morgan, Inc.	2,995,000,000	1,584,000,000	3,861,000,000
Preferred Stock Dividends	0	0
Net Income Available to Common Stockholders	2,995,000,000	1,584,000,000
Total other comprehensive (loss) income	352,000,000	325,000,000	(288,000,000)
Comprehensive income	2,643,000,000	1,259,000,000	4,149,000,000
Comprehensive (income) loss attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to controlling interests	(2,643,000,000)	(1,259,000,000)	(4,149,000,000)
Subsidiary Non-Guarantors
Guarantor Obligations [Line Items]
Total Revenues	1,511,000,000	1,575,000,000	1,621,000,000
Costs of sales	266,000,000	367,000,000	498,000,000
Depreciation, depletion and amortization	319,000,000	358,000,000	333,000,000
Other operating expenses	746,000,000	759,000,000	501,000,000
Total Operating Costs, Expenses and Other	1,331,000,000	1,484,000,000	1,332,000,000
Operating Income	180,000,000	91,000,000	289,000,000
Earnings from consolidated subsidiaries	59,000,000	(30,000,000)	1,120,000,000
Earnings from equity investments	0	0	(1,000,000)
Interest Income (Expense), Net	(51,000,000)	(43,000,000)	(90,000,000)
Amortization of excess cost of equity investments and other, net	5,000,000	8,000,000	48,000,000
Income Before Income Taxes	193,000,000	26,000,000	1,366,000,000
Income Tax Expense	(44,000,000)	(119,000,000)	(292,000,000)
Net Income	149,000,000	(93,000,000)	1,074,000,000
Net (Income) Loss Attributable to Noncontrolling Interests	0	0	0
Net Income Attributable to Kinder Morgan, Inc.	149,000,000	(93,000,000)	1,074,000,000
Preferred Stock Dividends	0	0
Net Income Available to Common Stockholders	149,000,000	(93,000,000)
Total other comprehensive (loss) income	(55,000,000)	326,000,000	168,000,000
Comprehensive income	204,000,000	(419,000,000)	906,000,000
Comprehensive (income) loss attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to controlling interests	(204,000,000)	419,000,000	(906,000,000)
Consolidated KMI
Guarantor Obligations [Line Items]
Total Revenues	13,058,000,000	14,403,000,000	16,226,000,000
Costs of sales	3,498,000,000	4,115,000,000	6,278,000,000
Depreciation, depletion and amortization	2,209,000,000	2,309,000,000	2,040,000,000
Other operating expenses	3,779,000,000	5,532,000,000	3,460,000,000
Total Operating Costs, Expenses and Other	9,486,000,000	11,956,000,000	11,778,000,000
Operating Income	3,572,000,000	2,447,000,000	4,448,000,000
Earnings from consolidated subsidiaries	0	0	0
Earnings from equity investments	(113,000,000)	384,000,000	406,000,000
Interest Income (Expense), Net	(1,806,000,000)	(2,051,000,000)	(1,798,000,000)
Amortization of excess cost of equity investments and other, net	(15,000,000)	(8,000,000)	35,000,000
Income Before Income Taxes	1,638,000,000	772,000,000	3,091,000,000
Income Tax Expense	(917,000,000)	(564,000,000)	(648,000,000)
Net Income	721,000,000	208,000,000	2,443,000,000
Net (Income) Loss Attributable to Noncontrolling Interests	(13,000,000)	45,000,000	(1,417,000,000)
Net Income Attributable to Kinder Morgan, Inc.	708,000,000	253,000,000	1,026,000,000
Preferred Stock Dividends	(156,000,000)	(26,000,000)
Net Income Available to Common Stockholders	552,000,000	227,000,000
Total other comprehensive (loss) income	200,000,000	444,000,000	(20,000,000)
Comprehensive income	521,000,000	(236,000,000)	2,463,000,000
Comprehensive (income) loss attributable to noncontrolling interests	(13,000,000)	45,000,000	(1,486,000,000)
Comprehensive income attributable to controlling interests	(508,000,000)	191,000,000	(977,000,000)
Consolidating Adjustments
Guarantor Obligations [Line Items]
Total Revenues	(59,000,000)	(49,000,000)	(6,000,000)
Costs of sales	(13,000,000)	1,000,000	42,000,000
Depreciation, depletion and amortization	0	0	0
Other operating expenses	(46,000,000)	(50,000,000)	(48,000,000)
Total Operating Costs, Expenses and Other	(59,000,000)	(49,000,000)	(6,000,000)
Operating Income	0	0	0
Earnings from consolidated subsidiaries	(6,078,000,000)	(3,161,000,000)	(7,620,000,000)
Earnings from equity investments	0	0	0
Interest Income (Expense), Net	0	0	0
Amortization of excess cost of equity investments and other, net	0	0	0
Income Before Income Taxes	(6,078,000,000)	(3,161,000,000)	(7,620,000,000)
Income Tax Expense	0	0	0
Net Income	(6,078,000,000)	(3,161,000,000)	(7,620,000,000)
Net (Income) Loss Attributable to Noncontrolling Interests	(13,000,000)	45,000,000	(958,000,000)
Net Income Attributable to Kinder Morgan, Inc.	(6,091,000,000)	(3,116,000,000)	(8,578,000,000)
Preferred Stock Dividends	0	0
Net Income Available to Common Stockholders	(6,091,000,000)	(3,116,000,000)
Total other comprehensive (loss) income	(638,000,000)	(1,111,000,000)	351,000,000
Comprehensive income	(5,440,000,000)	(2,050,000,000)	(7,971,000,000)
Comprehensive (income) loss attributable to noncontrolling interests	(13,000,000)	45,000,000	(1,010,000,000)
Comprehensive income attributable to controlling interests	$ 5,453,000,000	$ 2,005,000,000	$ 8,981,000,000

Guarantee of Securities of S124

Guarantee of Securities of Subsidiaries Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
ASSETS
Cash and cash equivalents	$ 684	$ 229	$ 315	$ 598
All other current assets	337	266
Property, plant and equipment, net	38,705	40,547
Investments	7,027	6,040
Goodwill	22,152	23,790	24,654
Deferred income taxes	4,352	5,323
Other Assets, Noncurrent	1,522	2,029
Total Assets	80,305	84,104
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt		1,000
Long-term debt	37,354	42,406
Total Liabilities	45,503	48,701
Total KMI equity	34,431	35,119
Noncontrolling interests	371	284
Total Stockholders’ Equity	34,802	35,403	34,426	28,285
Total Liabilities and Stockholders’ Equity	80,305	84,104
Parent Issuer and Guarantor
ASSETS
Cash and cash equivalents	471	123	4	83
Due from Affiliate, Current	5,739	2,233
All other current assets	269	126
Property, plant and equipment, net	242	252
Investments	665	16
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	26,907	27,401
Goodwill	13,789	15,089
Notes receivable from affiliates	516	850
Deferred income taxes	6,647	7,501
Other Assets, Noncurrent	72	215
Total Assets	55,317	53,806
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	1,286	67
Other current liabilities - affiliates	3,551	1,328
All other current liabilities	432	321
Long-term debt	13,308	13,845
Notes payable to affiliates	1,533	2,404
Deferred income taxes	0	0
All other long-term liabilities and deferred credits	776	722
Total Liabilities	20,886	18,687
Total KMI equity	34,431	35,119
Noncontrolling interests	0	0
Total Stockholders’ Equity	34,431	35,119
Total Liabilities and Stockholders’ Equity	55,317	53,806
Subsidiary Issuer and Guarantor - KMP
ASSETS
Cash and cash equivalents	0	0	15	88
Due from Affiliate, Current	1,999	1,600
All other current assets	139	119
Property, plant and equipment, net	0	0
Investments	2	2
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	29,421	28,038
Goodwill	22	22
Notes receivable from affiliates	21,608	21,319
Deferred income taxes	0	0
Other Assets, Noncurrent	206	307
Total Assets	53,397	51,407
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	600	500
Other current liabilities - affiliates	13,299	8,682
All other current liabilities	362	458
Long-term debt	19,277	20,053
Notes payable to affiliates	448	448
Deferred income taxes	0	0
All other long-term liabilities and deferred credits	111	193
Total Liabilities	34,097	30,334
Total KMI equity	19,300	21,073
Noncontrolling interests	0	0
Total Stockholders’ Equity	19,300	21,073
Total Liabilities and Stockholders’ Equity	53,397	51,407
Subsidiary Guarantors
ASSETS
Cash and cash equivalents	9	12	17	18
Due from Affiliate, Current	13,207	9,410
All other current assets	1,935	2,161
Property, plant and equipment, net	30,795	33,032
Investments	6,236	5,906
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	4,307	3,493
Goodwill	5,167	5,508
Notes receivable from affiliates	1,132	2,092
Deferred income taxes	0	0
Other Assets, Noncurrent	4,455	4,951
Total Assets	67,243	66,565
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	687	132
Other current liabilities - affiliates	4,197	3,210
All other current liabilities	2,016	1,992
Long-term debt	4,095	7,825
Notes payable to affiliates	20,520	20,462
Deferred income taxes	681	596
All other long-term liabilities and deferred credits	821	909
Total Liabilities	33,017	35,126
Total KMI equity	34,226	31,439
Noncontrolling interests	0	0
Total Stockholders’ Equity	34,226	31,439
Total Liabilities and Stockholders’ Equity	67,243	66,565
Subsidiary Non-Guarantors
ASSETS
Cash and cash equivalents	205	142	279	409
Due from Affiliate, Current	655	688
All other current assets	205	195
Property, plant and equipment, net	7,668	7,263
Investments	124	116
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	4,028	3,320
Goodwill	3,174	3,171
Notes receivable from affiliates	412	358
Deferred income taxes	0	0
Other Assets, Noncurrent	107	107
Total Assets	16,578	15,360
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	123	122
Other current liabilities - affiliates	553	711
All other current liabilities	422	527
Long-term debt	674	683
Notes payable to affiliates	1,167	1,305
Deferred income taxes	1,614	1,582
All other long-term liabilities and deferred credits	517	406
Total Liabilities	5,070	5,336
Total KMI equity	11,508	10,024
Noncontrolling interests	0	0
Total Stockholders’ Equity	11,508	10,024
Total Liabilities and Stockholders’ Equity	16,578	15,360
Consolidated KMI
ASSETS
Cash and cash equivalents	684	229	315	598
Due from Affiliate, Current	0	0
All other current assets	2,545	2,595
Property, plant and equipment, net	38,705	40,547
Investments	7,027	6,040
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	0	0
Goodwill	22,152	23,790
Notes receivable from affiliates	0	0
Deferred income taxes	4,352	5,323
Other Assets, Noncurrent	4,840	5,580
Total Assets	80,305	84,104
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	2,696	821
Other current liabilities - affiliates	0	0
All other current liabilities	3,228	3,244
Long-term debt	37,354	42,406
Notes payable to affiliates	0	0
Deferred income taxes	0	0
All other long-term liabilities and deferred credits	2,225	2,230
Total Liabilities	45,503	48,701
Total KMI equity	34,431	35,119
Noncontrolling interests	371	284
Total Stockholders’ Equity	34,802	35,403
Total Liabilities and Stockholders’ Equity	80,305	84,104
Consolidating Adjustments
ASSETS
Cash and cash equivalents	(1)	(48)	$ 0	$ 0
Due from Affiliate, Current	(21,600)	(13,931)
All other current assets	(3)	(6)
Property, plant and equipment, net	0	0
Investments	0	0
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	(64,663)	(62,252)
Goodwill	0	0
Notes receivable from affiliates	(23,668)	(24,619)
Deferred income taxes	(2,295)	(2,178)
Other Assets, Noncurrent	0	0
Total Assets	(112,230)	(103,034)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	0	0
Other current liabilities - affiliates	(21,600)	(13,931)
All other current liabilities	(4)	(54)
Long-term debt	0	0
Notes payable to affiliates	(23,668)	(24,619)
Deferred income taxes	(2,295)	(2,178)
All other long-term liabilities and deferred credits	0	0
Total Liabilities	(47,567)	(40,782)
Total KMI equity	(65,034)	(62,536)
Noncontrolling interests	371	284
Total Stockholders’ Equity	(64,663)	(62,252)
Total Liabilities and Stockholders’ Equity	$ (112,230)	$ (103,034)

Guarantee of Securities of S125

Guarantee of Securities of Subsidiaries Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	$ 4,787	$ 5,303	$ 4,467
Acquisitions of assets and investments	(333)	(2,079)	(1,388)
Capital expenditures	(2,882)	(3,896)	(3,617)
Proceeds from sale of equity interests in subsidiaries, net	1,401	0	0
Sales of property, plant and equipment, investments, and other net assets, net of removal costs	330	39	5
Contributions to investments	(408)	(96)	(389)
Distributions from equity investments in excess of cumulative earnings	231	228	182
Funding to affiliates	0
Other, net	(44)	98	(3)
Net Cash Used in Investing Activities	(1,705)	(5,706)	(5,210)
Issuances of debt	8,629	14,316	24,573
Payments of debt	(10,060)	(15,116)	(17,801)
Debt issue costs	(19)	(24)	(89)
Cash dividends - common shares	(1,118)	(4,224)	(1,760)
Cash dividends - preferred shares	(154)	0	0
Payments for repurchases of shares and warrants	0	(12)	(192)
Cash consideration of Merger Transactions	0	0	3,937
Issuances of common shares	0	3,870	0
Issuance of mandatory convertible preferred stock (Note 11)	0	1,541	0
Merger Transactions costs	0	(2)	(74)
Contributions from noncontrolling interests	117	11	1,767
Distributions to noncontrolling interests	(24)	(34)	(2,013)
Other, net	0	1	(3)
Net Cash (Used in) Provided by Financing Activities	(2,629)	327	471
Effect of exchange rate changes on cash and cash equivalents	2	(10)	(11)
Net increase (decrease) in Cash and Cash Equivalents	455	(86)	(283)
Cash and Cash Equivalents, at Carrying Value	684	229	315	$ 598
Parent Issuer and Guarantor
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	(3,989)	(4,218)	1,419
Acquisitions of assets and investments	(2)	(1,843)	0
Capital expenditures	(27)	(10)	(1)
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	6	0	0
Contributions to investments	(343)	(21)	0
Distributions from equity investments in excess of cumulative earnings	2,417	2,653	93
Investment in KMP		(159)	(550)
Payments for (Proceeds from) Businesses and Interest in Affiliates			875
Funding to affiliates	(2,820)	(3,204)	(1,949)
Other, net	0	0	0
Net Cash Used in Investing Activities	(769)	(2,584)	(1,532)
Issuances of debt	8,255	14,316	10,594
Payments of debt	(7,322)	(14,048)	(5,479)
Debt issue costs	(16)	(24)	(74)
Cash dividends - common shares	(1,118)	(4,224)	(1,760)
Cash dividends - preferred shares	(154)
Payments for repurchases of shares and warrants		(12)	(192)
Cash consideration of Merger Transactions			3,937
Issuances of common shares		3,870
Issuance of mandatory convertible preferred stock (Note 11)		1,541
Merger Transactions costs		(2)	(74)
Funding from (to) affiliates	5,461	5,502	956
Contributions from parents	0	0	0
Contributions from noncontrolling interests	0	0	0
Distributions to parents	0	0	0
Distributions to noncontrolling interests	0	0	0
Other, net		2	0
Net Cash (Used in) Provided by Financing Activities	5,106	6,921	34
Effect of exchange rate changes on cash and cash equivalents	0	0	0
Net increase (decrease) in Cash and Cash Equivalents	348	119	(79)
Cash and Cash Equivalents, at Carrying Value	471	123	4	83
Subsidiary Issuer and Guarantor - KMP
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	4,980	6,824	3,810
Acquisitions of assets and investments	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	(189)
Distributions from equity investments in excess of cumulative earnings	298	0	440
Investment in KMP		0	0
Payments for (Proceeds from) Businesses and Interest in Affiliates			(875)
Funding to affiliates	(535)	(8,388)	(6,644)
Other, net	(73)	24	27
Net Cash Used in Investing Activities	(310)	(8,364)	(7,241)
Issuances of debt	0	0	13,979
Payments of debt	(500)	(675)	(12,171)
Debt issue costs	0	0	(15)
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0
Payments for repurchases of shares and warrants		0	0
Cash consideration of Merger Transactions			0
Issuances of common shares		0
Issuance of mandatory convertible preferred stock (Note 11)		0
Merger Transactions costs		0	0
Funding from (to) affiliates	1,116	6,989	4,129
Contributions from parents	0	156	1,912
Contributions from noncontrolling interests	0	0	0
Distributions to parents	(5,286)	(4,944)	(4,475)
Distributions to noncontrolling interests	0	0	0
Other, net		(1)	(1)
Net Cash (Used in) Provided by Financing Activities	(4,670)	1,525	3,358
Effect of exchange rate changes on cash and cash equivalents	0	0	0
Net increase (decrease) in Cash and Cash Equivalents	0	(15)	(73)
Cash and Cash Equivalents, at Carrying Value	0	0	15	88
Subsidiary Guarantors
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	11,641	11,039	6,059
Acquisitions of assets and investments	(331)	(236)	(1,370)
Capital expenditures	(2,258)	(3,555)	(2,911)
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	326	39	(9)
Contributions to investments	(54)	(70)	(389)
Distributions from equity investments in excess of cumulative earnings	190	143	183
Investment in KMP		0	0
Payments for (Proceeds from) Businesses and Interest in Affiliates			0
Funding to affiliates	(5,062)	(7,980)	(3,826)
Other, net	39	16	29
Net Cash Used in Investing Activities	(5,749)	(11,643)	(8,293)
Issuances of debt	374	0	0
Payments of debt	(2,227)	(383)	(142)
Debt issue costs	(2)	0	0
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0
Payments for repurchases of shares and warrants		0	0
Cash consideration of Merger Transactions			0
Issuances of common shares		0
Issuance of mandatory convertible preferred stock (Note 11)		0
Merger Transactions costs		0	0
Funding from (to) affiliates	1,959	7,112	7,241
Contributions from parents	117	3	533
Contributions from noncontrolling interests	0	0	0
Distributions to parents	(6,116)	(6,133)	(5,398)
Distributions to noncontrolling interests	0	0	0
Other, net		0	(2)
Net Cash (Used in) Provided by Financing Activities	(5,895)	599	2,232
Effect of exchange rate changes on cash and cash equivalents	0	0	1
Net increase (decrease) in Cash and Cash Equivalents	(3)	(5)	(1)
Cash and Cash Equivalents, at Carrying Value	9	12	17	18
Subsidiary Non-Guarantors
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	885	347	641
Acquisitions of assets and investments	0	0	(18)
Capital expenditures	(597)	(331)	(705)
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	(2)	0	14
Contributions to investments	(11)	(10)	0
Distributions from equity investments in excess of cumulative earnings	0	0	0
Investment in KMP		0	0
Payments for (Proceeds from) Businesses and Interest in Affiliates			0
Funding to affiliates	(727)	(779)	(784)
Other, net	(10)	58	(60)
Net Cash Used in Investing Activities	(1,347)	(1,062)	(1,553)
Issuances of debt	0	0	0
Payments of debt	(11)	(10)	(9)
Debt issue costs	(1)	0	0
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0
Payments for repurchases of shares and warrants		0	0
Cash consideration of Merger Transactions			0
Issuances of common shares		0
Issuance of mandatory convertible preferred stock (Note 11)		0
Merger Transactions costs		0	0
Funding from (to) affiliates	608	748	877
Contributions from parents	0	16	64
Contributions from noncontrolling interests	0	0	0
Distributions to parents	(73)	(166)	(138)
Distributions to noncontrolling interests	0	0	0
Other, net		0	0
Net Cash (Used in) Provided by Financing Activities	523	588	794
Effect of exchange rate changes on cash and cash equivalents	2	(10)	(12)
Net increase (decrease) in Cash and Cash Equivalents	63	(137)	(130)
Cash and Cash Equivalents, at Carrying Value	205	142	279	409
Consolidated KMI
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	4,787	5,303	4,467
Acquisitions of assets and investments	(333)	(2,079)	(1,388)
Capital expenditures	(2,882)	(3,896)	(3,617)
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	330	39	5
Contributions to investments	(408)	(96)	(389)
Distributions from equity investments in excess of cumulative earnings	231	228	182
Investment in KMP		0	0
Payments for (Proceeds from) Businesses and Interest in Affiliates			0
Funding to affiliates		0	0
Other, net	(44)	98	(3)
Net Cash Used in Investing Activities	(1,705)	(5,706)	(5,210)
Issuances of debt	8,629	14,316	24,573
Payments of debt	(10,060)	(15,116)	(17,801)
Debt issue costs	(19)	(24)	(89)
Cash dividends - common shares	(1,118)	(4,224)	(1,760)
Cash dividends - preferred shares	(154)
Payments for repurchases of shares and warrants		(12)	(192)
Cash consideration of Merger Transactions			3,937
Issuances of common shares		3,870
Issuance of mandatory convertible preferred stock (Note 11)		1,541
Merger Transactions costs		(2)	(74)
Funding from (to) affiliates	0	0	0
Contributions from parents	0	0	0
Contributions from noncontrolling interests	117	11	1,767
Distributions to parents	0	0	0
Distributions to noncontrolling interests	(24)	(34)	(2,013)
Other, net		1	(3)
Net Cash (Used in) Provided by Financing Activities	(2,629)	327	471
Effect of exchange rate changes on cash and cash equivalents	2	(10)	(11)
Net increase (decrease) in Cash and Cash Equivalents	455	(86)	(283)
Cash and Cash Equivalents, at Carrying Value	684	229	315	598
Consolidating Adjustments
Guarantor Obligations [Line Items]
Net cash (used in) provided by operating activities	(8,730)	(8,689)	(7,462)
Acquisitions of assets and investments	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	5	189
Distributions from equity investments in excess of cumulative earnings	(2,674)	(2,568)	(534)
Investment in KMP		159	550
Payments for (Proceeds from) Businesses and Interest in Affiliates			0
Funding to affiliates	9,144	20,351	13,203
Other, net	0	0	1
Net Cash Used in Investing Activities	6,470	17,947	13,409
Issuances of debt	0	0	0
Payments of debt	0	0	0
Debt issue costs	0	0	0
Cash dividends - common shares	0	0	0
Cash dividends - preferred shares	0
Payments for repurchases of shares and warrants		0	0
Cash consideration of Merger Transactions			0
Issuances of common shares		0
Issuance of mandatory convertible preferred stock (Note 11)		0
Merger Transactions costs		0	0
Funding from (to) affiliates	(9,144)	(20,351)	(13,203)
Contributions from parents	(117)	(175)	(2,509)
Contributions from noncontrolling interests	117	11	1,767
Distributions to parents	11,475	11,243	10,011
Distributions to noncontrolling interests	(24)	(34)	(2,013)
Other, net		0	0
Net Cash (Used in) Provided by Financing Activities	2,307	(9,306)	(5,947)
Effect of exchange rate changes on cash and cash equivalents	0	0	0
Net increase (decrease) in Cash and Cash Equivalents	47	(48)	0
Cash and Cash Equivalents, at Carrying Value	$ (1)	$ (48)	$ 0	$ 0