Kinder Morgan (KMI) 10-K 16 Feb 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 11, 2016	Jun. 30, 2015
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			$ 69,734,282,635
Entity Common Stock, Shares Outstanding		2,231,555,976
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues
Natural gas sales	$ 2,839,000,000	$ 4,115,000,000	$ 3,605,000,000
Services	8,290,000,000	7,650,000,000	6,677,000,000
Product sales and other	3,274,000,000	4,461,000,000	3,788,000,000
Total Revenues	14,403,000,000	16,226,000,000	14,070,000,000
Operating Costs, Expenses and Other
Costs of sales	4,115,000,000	6,278,000,000	5,253,000,000
Operations and maintenance	2,337,000,000	2,157,000,000	2,112,000,000
Depreciation, depletion and amortization	2,309,000,000	2,040,000,000	1,806,000,000
General and administrative	690,000,000	610,000,000	613,000,000
Taxes, other than income taxes	439,000,000	418,000,000	395,000,000
Loss on impairment of goodwill	1,150,000,000	0	0
Loss (gain) on impairments and disposals of long-lived assets, net	919,000,000	274,000,000	(98,000,000)
Other (income) expense, net	(3,000,000)	1,000,000	(1,000,000)
Total Operating Costs, Expenses and Other	11,956,000,000	11,778,000,000	10,080,000,000
Operating Income	2,447,000,000	4,448,000,000	3,990,000,000
Other Income (Expense)
Earnings from equity investments	414,000,000	406,000,000	392,000,000
Loss on impairments of equity investments	(30,000,000)	0	(65,000,000)
Amortization of excess cost of equity investments	(51,000,000)	(45,000,000)	(39,000,000)
Interest, net	(2,051,000,000)	(1,798,000,000)	(1,675,000,000)
Gain on remeasurement of previously held equity investments to fair value (Note 3)	0	0	558,000,000
Gain on sale of investments in Express pipeline system (Note 3)	0	0	224,000,000
Other, net	43,000,000	80,000,000	53,000,000
Total Other Expense	(1,675,000,000)	(1,357,000,000)	(552,000,000)
Income from Continuing Operations Before Income Taxes	772,000,000	3,091,000,000	3,438,000,000
Income Tax Expense	(564,000,000)	(648,000,000)	(742,000,000)
Income from Continuing Operations	208,000,000	2,443,000,000	2,696,000,000
Discontinued Operations
Loss on sale of the FTC Natural Gas Pipelines disposal group, net of tax	0	0	(4,000,000)
Net Income	208,000,000	2,443,000,000	2,692,000,000
Net Loss (Income) Attributable to Noncontrolling Interests	45,000,000	(1,417,000,000)	(1,499,000,000)
Net Income Attributable to Kinder Morgan, Inc.	253,000,000	1,026,000,000	1,193,000,000
Preferred Stock Dividends	(26,000,000)	0	0
Net Income Available to Common Stockholders	$ 227,000,000	$ 1,026,000,000	$ 1,193,000,000
Class P Shares
Basic Earnings Per Common Share	$ 0.10	$ 0.89	$ 1.15
Basic Weighted Average Common Shares Outstanding	2,187	1,137	1,036
Diluted Earnings Per Common Share	$ 0.10	$ 0.89	$ 1.15
Diluted Weighted Average Common Shares Outstanding	2,193	1,137	1,036
Dividends Per Common Share Declared for the Period	$ 1.605	$ 1.740	$ 1.600
Class P
Discontinued Operations
Net Income Available to Common Stockholders	$ 214,000,000	$ 1,015,000,000	$ 1,187,000,000
Class P Shares
Basic Weighted Average Common Shares Outstanding	2,187	1,137	1,036
Dividends Per Common Share Declared for the Period	$ 1.605	$ 1.740	$ 1.600

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Total
Net income	$ 208	$ 2,443	$ 2,692
Other comprehensive income (loss), net of tax
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(94), $(163) and $10, respectively)	164	409	(38)
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $156, $13 and $(3), respectively)	(272)	(25)	11
Foreign currency translation adjustments (net of tax benefit of $123, $48, and $31, respectively)	(214)	(138)	(103)
Benefit plan adjustments (net of tax benefit (expense) of $69, $126 and $(91), respectively)	(122)	(226)	170
Total other comprehensive (loss) income	(444)	20	40
Comprehensive (loss) income	(236)	2,463	2,732
Comprehensive loss (income) attributable to noncontrolling interests	45	(1,486)	(1,445)
Comprehensive (loss) income attributable to KMI	$ (191)	$ 977	$ 1,287

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME, TAX (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Total, Tax
Change in fair value of derivatives utilized for hedging purposes	$ (94)	$ (163)	$ 10
Reclassification of change in fair value of derivatives to net income	156	13	(3)
Foreign currency translation adjustments	123	48	31
Benefit plan adjustments	$ 69	$ 126	$ (91)

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 229	$ 315
Accounts receivable, net	1,315	1,641
Fair value of derivative contracts	507	535
Inventories	407	459
Deferred income taxes	0	56
Other current assets	366	746
Total current assets	2,824	3,752
Property, plant and equipment, net	40,547	38,564
Investments	6,040	6,036
Goodwill	23,790	24,654
Other intangibles, net	3,551	2,302
Deferred income taxes	5,323	5,651
Deferred charges and other assets	2,029	2,090
Total Assets	84,104	83,049
Current liabilities
Current portion of debt	821	2,717
Accounts payable	1,324	1,588
Accrued interest	695	637
Accrued contingencies	298	383
Other current liabilities	927	1,037
Total current liabilities	4,065	6,362
Long-term debt
Outstanding	40,632	38,212
Preferred interest in general partner of KMP	100	100
Debt fair value adjustments	1,674	1,785
Total long-term debt	42,406	40,097
Other long-term liabilities and deferred credits	2,230	2,164
Total long-term liabilities and deferred credits	44,636	42,261
Total Liabilities	$ 48,701	$ 48,623
Commitments and contingencies (Notes 9, 13 and 17)
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,229,223,864 and 2,125,147,116 shares, respectively, issued and outstanding	$ 22	$ 21
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	41,661	36,178
Retained deficit	(6,103)	(2,106)
Accumulated other comprehensive loss	(461)	(17)
Total Kinder Morgan, Inc.’s stockholders’ equity	35,119	34,076
Noncontrolling interests	284	350
Total Stockholders’ Equity	35,403	34,426
Total Liabilities and Stockholders’ Equity	$ 84,104	$ 83,049

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Stockholders’ Equity
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0
Preferred stock, shares authorized (in shares)	10,000,000	0
Preferred stock, shares issued (in shares)	1,600,000	0
Preferred stock, shares outstanding (in shares)	1,600,000	0
Preferred Stock, Liquidation Preference Per Share	$ 50
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)	2,229,223,864	2,125,147,116
Common stock, shares outstanding (in shares)	2,229,223,864	2,125,147,116
9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference
Stockholders’ Equity
Preferred Stock, Liquidation Preference Per Share	$ 1,000	$ 0
Preferred Stock, Dividend Rate, Percentage	9.75%	0.00%

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows From Operating Activities
Net income	$ 208	$ 2,443	$ 2,692
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	2,309	2,040	1,806
Deferred income taxes	692	615	640
Amortization of excess cost of equity investments	51	45	39
Loss on impairment of goodwill (Note 4)	1,150	0	0
Loss (gain) on impairments and disposals of long-lived assets and equity investments, net	949	274	(33)
Gain from the remeasurement of net assets to fair value and the sale of discontinued operations (net of cash selling expenses), net of tax (Note 3)	0	0	(556)
Gain from sale of investments in Express pipeline system (Note 3)	0	0	(224)
Earnings from equity investments	(414)	(406)	(392)
Distributions of equity investment earnings	391	381	398
Proceeds from termination of interest rate swap agreements	0	0	96
Pension contributions and noncash pension benefit credits	(85)	(88)	(120)
Changes in components of working capital, net of the effects of acquisitions
Accounts receivable	382	(84)	(131)
Income tax receivable	195	(195)	0
Inventories	34	(30)	(53)
Other current assets	113	(17)	(32)
Accounts payable	(156)	(1)	(36)
Accrued interest, net of interest rate swaps	37	61	50
Accrued contingencies and other current liabilities	(129)	108	(100)
Rate reparations, refunds and other litigation reserve adjustments	18	(280)	174
Other, net	(442)	(399)	(96)
Net Cash Provided by Operating Activities	5,303	4,467	4,122
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired	(2,079)	(1,388)	(292)
Proceeds from sales of assets and investments	0	0	490
Capital expenditures	(3,896)	(3,617)	(3,369)
Contributions to investments	(96)	(389)	(217)
Distributions from equity investments in excess of cumulative earnings	228	182	185
Other, net	137	2	81
Net Cash Used in Investing Activities	(5,706)	(5,210)	(3,122)
Cash Flows From Financing Activities
Issuances of debt	14,316	24,573	13,581
Payments of debt	(15,116)	(17,801)	(12,393)
Debt issue costs	(24)	(89)	(38)
Issuances of common shares (Note 11)	3,870	0	0
Issuance of mandatory convertible preferred stock (Note 11)	1,541	0	0
Cash dividends (Note 11)	(4,224)	(1,760)	(1,622)
Repurchases of shares and warrants	(12)	(192)	(637)
Cash consideration of Merger Transactions (Note 1)	0	(3,937)	0
Merger Transactions costs	(2)	(74)	0
Contributions from noncontrolling interests	11	1,767	1,706
Distributions to noncontrolling interests	(34)	(2,013)	(1,692)
Other, net	1	(3)	0
Net Cash Provided by (Used in) Financing Activities	327	471	(1,095)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	(10)	(11)	(21)
Net decrease in Cash and Cash Equivalents	(86)	(283)	(116)
Cash and Cash Equivalents, beginning of period	315	598	714
Cash and Cash Equivalents, end of period	229	315	598
Noncash Investing and Financing Activities
Assets acquired by the assumption or incurrence of liabilities	1,681	106	1,510
Net assets contributed to equity investment	46	0	0
Net assets and liabilities or noncontrolling interests acquired by the issuance of shares and warrants (Notes 1 and 3)	0	16,023	0
Assets acquired or liabilities settled by contributions from noncontrolling interests	0	0	3,733
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,985	1,718	1,652
Cash (refund) paid during the period for income taxes, net	$ (331)	$ 227	$ 67

CONSOLIDATED STATEMENT OF STOCK

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY - USD ($) shares in Millions, $ in Millions	Total	Class P	Preferred stock	Common stock	Preferred stock	Additional paid-in capital	Additional paid-in capitalClass P	Additional paid-in capitalPreferred stock	Retained deficit	Accumulated other comprehensive loss	Stockholders’ equity attributable to KMI	Stockholders’ equity attributable to KMIClass P	Stockholders’ equity attributable to KMIPreferred stock	Non-controlling interests	Impact from equity transactions of KMP, EPB and KMR	Impact from equity transactions of KMP, EPB and KMRAdditional paid-in capital	Impact from equity transactions of KMP, EPB and KMRStockholders’ equity attributable to KMI	Impact from equity transactions of KMP, EPB and KMRNon-controlling interests	KMP’s acquisition of Copano noncontrolling interests	KMP’s acquisition of Copano noncontrolling interestsStockholders’ equity attributable to KMI	KMP’s acquisition of Copano noncontrolling interestsNon-controlling interests	EP Trust I Preferred security conversionsClass P	EP Trust I Preferred security conversionsAdditional paid-in capital	EP Trust I Preferred security conversionsStockholders’ equity attributable to KMI
Issued shares		1,036	0
Stock and Warrants Repurchased and Retired During Period, Shares		(5)
Stockholders’ equity attributable to KMI at Dec. 31, 2012				$ 10	$ 0	$ 14,917			$ (943)	$ (118)	$ 13,866
Repurchases of shares and warrants	$ (637)					(637)					(637)
Non-controlling interests at Dec. 31, 2012														$ 10,234
Total at Dec. 31, 2012	24,100
KMP’s acquisition of Copano noncontrolling interests																			$ 17	$ 0	$ 17
EP Trust I Preferred security conversions	3																						$ 3	$ 3
Warrants exercised	1					1					1
Restricted shares	33					33					33
Impact from equity transactions of KMP, EPB and KMR															$ (93)	$ 161	$ 161	$ (254)
Net income	1,193								1,193		1,193
Net Loss (Income) Attributable to Noncontrolling Interests	(1,499)													1,499
Net income	2,692
Distributions	(1,692)										0			(1,692)
Contributions	5,439										0			5,439
Common stock dividends	(1,622)								(1,622)		(1,622)
Other	4					1					1			3
Other comprehensive (loss) income										94	94
Other comprehensive (loss) income														(54)
Total	40
Stockholders’ equity attributable to KMI at Dec. 31, 2013				10	0	14,479			(1,372)	(24)	13,093
Non-controlling interests at Dec. 31, 2013														15,192
Total at Dec. 31, 2013	28,285
Issued shares		1,031	0
Stock and Warrants Repurchased and Retired During Period, Shares		(3)
Repurchases of shares and warrants	(192)					(192)					(192)
Impact of Merger Transactions	5,955			11		21,880					21,891			(15,936)
Impact of Merger Transactions		1,097
Merger Transactions costs	(75)					(75)					(75)
Restricted shares	52					52					52
Impact from equity transactions of KMP, EPB and KMR															$ (19)	$ 36	$ 36	$ (55)
Net income	1,026								1,026		1,026
Net Loss (Income) Attributable to Noncontrolling Interests	(1,417)													1,417
Net income	2,443
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										(49)	(49)
Other comprehensive (loss) income														69
Total	20
Impact of Merger Transactions on Accumulated other comprehensive loss	(31)									56	56			(87)
Stockholders’ equity attributable to KMI at Dec. 31, 2014	34,076			21	0	36,178			(2,106)	(17)	34,076
Non-controlling interests at Dec. 31, 2014	350													350
Total at Dec. 31, 2014	34,426
Issued shares		2,125	0
Issuances of common shares		103	2
Issuances of common shares		$ 3,870	$ 1,541	1			$ 3,869	$ 1,541				$ 3,870	$ 1,541
Issuances of preferred shares		$ 3,870	$ 1,541	1			$ 3,869	$ 1,541				$ 3,870	$ 1,541
Repurchases of warrants	(12)					(12)					(12)
EP Trust I Preferred security conversions																						1
EP Trust I Preferred security conversions	23																						$ 23	$ 23
Warrants exercised	2					2					2
Restricted shares	57					57					57
Net income	253								253		253
Net Loss (Income) Attributable to Noncontrolling Interests	45													(45)
Net income	208
Distributions	(34)										0			(34)
Contributions	11										0			11
Preferred stock dividends	(26)								(26)		(26)
Common stock dividends	(4,224)								(4,224)		(4,224)
Other	5					3					3			2
Other comprehensive (loss) income										(444)	(444)
Total	(444)
Stockholders’ equity attributable to KMI at Dec. 31, 2015	35,119			$ 22	$ 0	$ 41,661			$ (6,103)	$ (461)	$ 35,119
Non-controlling interests at Dec. 31, 2015	284													$ 284
Total at Dec. 31, 2015	$ 35,403
Issued shares		2,229	2

General (Notes)

General (Notes)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	1. General We are the largest energy infrastructure company 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 coal, petroleum coke and steel. We are also the leading producer and transporter of CO 2 , which is utilized for enhanced oil recovery projects in North America. On November 26, 2014, we completed our acquisition, pursuant to three separate merger agreements, of all of the outstanding common units of Kinder Morgan Energy Partners, L.P. and El Paso Pipeline Partners, L.P. and all of the outstanding shares of Kinder Morgan Management, LLC that we did not already own. The transactions, valued at approximately $77 billion , 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 KMR Merger Transaction, 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 was 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 attributable to noncontrolling interests” in our accompanying consolidated statements of income. 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, 2015
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, except where 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. In addition, we believe that 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 cash of $60 million and $118 million as of December 31, 2015 and 2014 , respectively, is included in “Other current assets.” Accounts Receivable, net The amounts reported as “Accounts receivable, net” on our accompanying consolidated balance sheets as of December 31, 2015 and 2014 primarily consist of amounts due from customers. 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 $91 million and $10 million as of December 31, 2015 and 2014, respectively. The increase was primarily associated with reserves established related to certain coal customers. 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 these assets at the lower of weighted-average cost or market. 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, 2015 and 2014 , our gas imbalance receivables—including both trade and related party receivables—totaled $21 million and $103 million , respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2015 and 2014 , our gas imbalance payables—consisting of only trade payables—totaled $17 million and $36 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 0.9% 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. For the purpose of impairment testing, adjustments for the inclusion of risk-adjusted probable reserves, as well as forward curve pricing and estimates of future costs, will cause impairment calculation cash flows to differ from the amounts presented in our supplemental information on oil and gas producing activities disclosed in “Supplemental Information on Oil and Gas Producing Activities (Unaudited).” 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—by 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 $808 million and $870 million as of December 31, 2015 and 2014 , 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, 2015, this excess investment cost is being amortized over a weighted average life of approximately fifteen years. The second differential, representing equity method goodwill, totaled $138 million as of both December 31, 2015 and 2014 . This differential is not subject to amortization but rather to impairment testing as part of our periodic evaluation of the recoverability of our investment as compared to the fair value of net assets accounted for under the equity method. Our impairment test considers whether the fair value of the equity investment as a whole has declined and whether that decline is other than temporary. Goodwill Goodwill is the cost of an acquisition in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually. This test requires us to assign goodwill to an appropriate reporting unit and to determine if the implied fair value of the reporting unit’s goodwill is less than its carrying amount. We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have seven reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO 2 ; (vi) Terminals; and (vii) Kinder Morgan Canada. We also evaluate goodwill for impairment to the extent events or conditions indicate a risk of possible impairment during the interim periods subsequent to our annual impairment test. Generally, the evaluation of goodwill for impairment involves a two-step test, although under certain circumstance an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test. Step 1 involves comparing the estimated fair value of each respective reporting unit to its carrying value, including goodwill. If the estimated fair value exceeds the carrying value, the reporting unit’s goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, step 2 must be performed to determine whether goodwill is impaired and, if so, the amount of the impairment. Step 2 involves calculating an implied fair value of goodwill by performing a hypothetical allocation of the estimated fair value of the reporting unit determined in step 1 to the respective tangible and intangible net assets of the reporting unit. The remaining implied goodwill is then compared to the actual carrying amount of the goodwill for the reporting unit. To the extent the carrying amount of goodwill exceeds the implied goodwill, the difference is the amount of the goodwill impairment. A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit. Refer to Note 8 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, 2015 and 2014 , these intangible assets totaled $3,551 million and $2,302 million , respectively, and 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, coal, petroleum coke, fertilizer, 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, 2015 , 2014 and 2013 , the amortization expense on our intangibles totaled $221 million , $143 million and $125 million , respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2016 – 2020) is approximately $221 million , $218 million , $216 million , $214 million , and $211 million , respectively. As of December 31, 2015 , the weighted average amortization period for our intangible assets was approximately eighteen 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 soley 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. 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 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 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. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized. 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.” Comprehensive Income For each of the years ended December 31, 2015 , 2014 and 2013 , the difference between our net income and our comprehensive income resulted from (i) unrealized gains or losses on derivative contracts accounted for as cash flow hedges; (ii) foreign currency translation adjustments; and (iii) unrealized gains or losses related to changes in pension and other postretirement benefit plan liabilities. For more information on our risk management activities, see Note 14. 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. 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. As of December 31, 2015 , the recovery period for these regulatory assets was approximately one year to forty-one years . The following table summarizes our regulatory asset and liability balances as of December 31, 2015 and 2014 (in millions): December 31, 2015 2014 Current regulatory assets $ 55 $ 81 Non-current regulatory assets 378 406 Total regulatory assets $ 433 $ 487 Current regulatory liabilities $ 161 $ 189 Non-current regulatory liabilities 166 290 Total regulatory liabilities $ 327 $ 479 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 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 distributio

Acquisitions (Notes)

Acquisitions (Notes)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	Acquisitions and Divestitures Business Combinations During 2015 , 2014 and 2013 , we completed the following significant acquisitions accounted for in accordance with the “Business Combinations” Topic of the Codification. 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. Additionally, we adjust goodwill as a result of applying the look-through method of recording deferred taxes on the outside book tax basis differences in our investments without regard to non-tax deductible goodwill. The following table discloses our assignment of the purchase price for each of our significant acquisitions (in millions): Assignment of Purchase Price Ref. Date Acquisition Purchase price Current assets Property plant & equipment Deferred charges & other Goodwill Long-term debt Other liabilities Non-controlling interest Previously held equity interest (1) 2/15 Vopak Terminal Assets $ 158 $ 2 $ 155 $ — $ 7 $ — $ (6 ) $ — $ — (2) 2/15 Hiland 1,709 79 1,497 1,498 310 (1,411 ) (264 ) — — (3) 11/14 Pennsylvania and Florida Jones Act Tankers 270 — 270 8 25 — (33 ) — — (4) 1/14 American Petroleum Tankers and State Class Tankers 961 6 951 6 64 — (66 ) — — (5) 6/13 Goldsmith-Landreth Field Unit 280 — 298 — — — (18 ) — — (6) 5/13 Copano 3,733 218 2,788 1,973 963 (1,252 ) (236 ) (17 ) (704 ) (1) 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 the Terminals business segment. (2) Hiland On February 13, 2015, we acquired Hiland, a privately held Delaware limited partnership for aggregate consideration of approximately $3,120 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 of 16.8 years . (3) 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 the Terminals business segment. The acquired vessels will continue to be operated by Crowley. (4) 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 . APT’s vessels are operated by Crowley. 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 delivery dates in 2015 and 2016. The time charters for each vessel upon completion has 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 the Terminals business segment. (5) Goldsmith Landreth Field Unit On June 1, 2013, we acquired certain oil and gas properties, rights, and related assets in the Permian Basin of West Texas from Legado Resources LLC for an aggregate consideration of $298 million consisting of $280 million in cash and assumed liabilities of $18 million (including $12 million of long-term asset retirement obligations). The acquisition of the Goldsmith Landreth San Andres oil field unit includes more than 6,000 acres located in Ector County, Texas. The acquired oil field is in the early stages of CO 2 flood development and includes a residual oil zone along with a classic San Andres waterflood. As part of the transaction, we obtained a long-term supply contract for up to 150 MMcf/d of CO 2 . The acquisition complemented our existing oil and gas producing assets in the Permian Basin, and we included the acquired assets as part of the CO 2 business segment. (6) Copano Effective May 1, 2013, we acquired all of Copano’s outstanding units for a total purchase price of approximately $5.2 billion (including assumed debt and all other assumed liabilities). The transaction was a 100% unit for unit transaction with an exchange ratio of 0.4563 of KMP’s common units for each Copano common unit. Due to the fact that our acquisition included the remaining 50% interest in Eagle Ford that we did not already own, we remeasured the carrying value ( $146 million ) of our existing 50% equity investment in Eagle Ford to its fair value ( $704 million ) as of the May 1, 2013 acquisition date. As a result of this remeasurement, we recognized a $558 million non-cash gain and we reported this gain within “Gain on remeasurement of previously held equity investments to fair value” in our accompanying consolidated statement of income for the year ended December 31, 2013. Pro Forma Information Pro forma information regarding consolidated income statement information that assumes all of the business acquisitions we have made since January 1, 2014, including the ones listed above, had occurred as of January 1, 2014, is not materially different from the information presented in our accompanying Consolidated Statements of Income. 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 Kinder Morgan NGPL Holdings LLC. Investment Divestiture Effective March 14, 2013, we sold both our one-third ownership interest in the Express pipeline system and our subordinated debenture investment in Express to Spectra Energy Corp. With respect to this sale, during the year ended December 31, 2013, we reported within our accompanying consolidated statement of cash flows $402 million as “Proceeds from sales of assets and investments” and within the accompanying consolidated statement of income a combined $224 million pre-tax gain as “Gain on sale of investments in Express pipeline system” and $84 million of expense within “Income Tax Expense.” Subsequent Event of Terminal Acquisition From and Joint Venture With BP On February 1, 2016, we completed the acquisition of 15 products terminals and associated infrastructure from BP for $350 million . In conjunction with this transaction, we and BP formed a joint venture, with an equity ownership interest of 75% and 25% , respectively. We contributed 14 of the acquired terminals to the joint venture, which we will operate, and the remaining terminal is solely owned by us. Of the acquired assets, 10 terminals are included in our Terminals business segment and 5 terminals are included in our Products Pipelines business segment.

Impairments (Notes)

Impairments (Notes)	12 Months Ended
	Dec. 31, 2015
Impairments [Abstract]
Impairment of Goodwill, Long-lived assets and equity investments [Text Block]	Impairments and Disposals We recognized the following non-cash pre-tax impairment charges and losses (gains) on disposals of assets (in millions): Year Ended December 31, 2015 2014 2013 Natural Gas Pipelines Impairment of goodwill $ 1,150 $ — $ — Impairments of long-lived assets(a) 79 — — Losses (gains) on disposals of long-lived assets 43 5 (28 ) Impairment of equity investments(b) 26 — 65 CO 2 Impairments of long-lived assets(c) 606 243 — Impairment at equity investee(d) 26 — — Terminals Impairments of long-lived assets(e) 188 — — Losses (gains) on disposals of long-lived assets 3 29 (73 ) Impairment of equity investments(e) 4 — — Other (gains) losses on disposals of long-lived assets — (3 ) 3 Total losses (gains) on impairments and disposals $ 2,125 $ 274 $ (33 ) _______ (a) Represents $47 million and $32 million of project write-offs in our non-regulated midstream and regulated natural gas pipelines assets, respectively. (b) 2015 amount is primarily related to an investment in a gathering and processing asset in Oklahoma and the 2013 amount is related to an investment in our regulated natural gas pipelines. (c) 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. (d) 2015 amount is a loss on impairment recorded by an investee and included in “Earnings from equity investments” in our accompanying consolidated statement of income. (e) 2015 amount is primarily related to certain terminals with significant coal operations, including a $175 million impairment ( $84 million net after-tax impact to common stockholders) 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. Impairment of Goodwill Due to recent events and conditions, interim goodwill impairment testing was performed during December 2015, which resulted 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. Impairments of Long-lived Assets During 2015, the sustained deterioration in the long-term outlook for commodity prices was a triggering event requiring us to perform impairment testing of our assets that are sensitive to such commodity prices. The impairment testing of our long-lived assets was based upon a two-step process as prescribed in the accounting standards. Step one was performed on each of our oil and gas producing properties and involved a determination as to whether the property’s net book value is expected to be recovered from the estimated undiscounted future cash flows for each respective property. To compute estimated future cash flows, we used our independent reserve engineers’ estimates of proved reserves, along with our internally developed estimates of probable reserves to develop a long-range plan. Proved reserves are those reserves that our independent reserve engineers have determined are “reasonably certain” to be produced as defined by SEC guidance. Reasonable certainty implies a high degree of confidence, of at least a 90% probability that quantities will equal or exceed the estimate of proved reserves. Probable reserves are those quantities that we have identified in our long range plan that are in excess of our independent reserve engineers’ estimates of proved reserves and meet the SEC definition of probable reserves. Probable reserves are defined as reserves that are as “likely as not” to be recoverable with a probability of at least 50% or greater. These estimates of proved and probable reserves are based upon historical performance along with adjustments for expected oil and gas field development. In calculating future cash flows, management utilized estimates of commodity prices based on forward curves. We also included the impact of our existing oil and gas sales contracts to determine the applicable net crude oil and natural gas pricing for each property. Operating expenses were determined based on estimated future fixed and variable field production requirements, and capital expenditures were based on currently authorized projects or economically viable future projects that have been identified for each of our properties. Risk factors were applied to each property’s probable reserves based on its operational history or the success of similar properties. Based on the results of the step one test, we determined that certain properties’ estimated undiscounted future cash flows were less than their respective carrying values. For those properties that failed the impairment test’s first step, we then made a fair market value assessment using a discounted cash flow analysis as well as an estimate of fair value based upon recent sales prices of comparable properties. Our cash flow analysis was discounted utilizing an estimated weighted average cost of capital of 12% , representing our estimate of the risk-adjusted discount rate that would be used by market participants. We consider the inputs for our impairment calculations to be Level 3 inputs in the fair value hierarchy. Based on these results, we recognized $399 million of impairments on those properties where the carrying value exceeded its estimated fair market value in the period that such a determination was made. In addition, during 2015 we recorded a $207 million impairment in our CO 2 business segment for certain source and transportation assets. Since we expect CO 2 demand to remain flat for the foreseeable future under the current commodity price environment, we deferred certain source and transportation growth projects beyond our five-year capital expenditures backlog. The extended deferral period necessitated a review of the recoverability of the net book values of these growth projects, resulting in a full impairment of $207 million . During the year ended December 31, 2015, similar impairment analyses were performed in our other segments resulting in impairments of long-lived assets of $79 million and $188 million , respectively, in our Natural Gas Pipelines and Terminals business segments. These impairments resulted from certain capital projects that were canceled or postponed as well as in our Terminals segment for which certain facilities were impaired as a result of management’s re-evaluation of the estimated future cash flows expected to be generated at our coal handling assets. In the current commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill. Because certain of our oil and gas producing properties have been written down to fair value, any deterioration in fair value that exceeds the rate of depletion of the related asset would result in further impairments. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future cash flow estimates, future volume expectations, current and future commodity prices, management’s decisions to dispose of certain assets and estimates of the fair values of our reporting units, as well as general economic conditions and the related demand for products handled or transported by our assets. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of “Income from Continuing Operations Before Income Taxes” are as follows (in millions): Year Ended December 31, 2015 2014 2013 U.S. $ 611 $ 2,941 $ 3,107 Foreign 161 150 331 Total Income from Continuing Operations Before Income Taxes $ 772 $ 3,091 $ 3,438 Components of the income tax provision applicable to continuing operations for federal, foreign and state taxes are as follows (in millions): Year Ended December 31, 2015 2014 2013 Current tax expense (benefit) Federal $ (125 ) $ (16 ) $ 57 State (7 ) 36 36 Foreign 4 13 9 Total (128 ) 33 102 Deferred tax expense (benefit) Federal 653 572 612 State (4 ) 14 — Foreign 43 29 28 Total 692 615 640 Total tax provision $ 564 $ 648 $ 742 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, 2015 2014 2013 Federal income tax $ 271 35.0 % $ 1,082 35.0 % $ 1,203 35.0 % Increase (decrease) as a result of: State deferred tax rate change (24 ) (3.1 )% — — % (21 ) (0.6 )% Taxes on foreign earnings 26 3.5 % 40 1.3 % 112 3.3 % Net effects of consolidating KMP and EPB and other noncontrolling interests 15 2.0 % (433 ) (14.0 )% (488 ) (14.2 )% State income tax, net of federal benefit 12 1.5 % 37 1.2 % 45 1.3 % Dividend received deduction (51 ) (6.6 )% (50 ) (1.6 )% (54 ) (1.6 )% Adjustments to uncertain tax positions (14 ) (1.9 )% (5 ) (0.2 )% (87 ) (2.5 )% Valuation allowance on investment in NGPL — — % 61 2.0 % — — % Disposition of certain international holdings — — % (112 ) (3.6 )% — — % Nondeductible goodwill impairment 323 41.7 % — — % — — % Other 6 0.8 % 28 0.9 % 32 0.9 % Total $ 564 72.9 % $ 648 21.0 % $ 742 21.6 % Deferred tax assets and liabilities result from the following (in millions): December 31, 2015 2014 Deferred tax assets Employee benefits $ 394 $ 329 Accrued expenses 129 123 Net operating loss, capital loss, tax credit carryforwards 1,344 778 Derivative instruments and interest rate and currency swaps 45 43 Debt fair value adjustment 110 102 Investments 3,607 4,858 Other 3 31 Valuation allowances (152 ) (154 ) Total deferred tax assets 5,480 6,110 Deferred tax liabilities Property, plant and equipment 143 373 Other 14 30 Total deferred tax liabilities 157 403 Net deferred tax assets $ 5,323 $ 5,707 Current deferred tax asset $ — $ 56 Non-current deferred tax assets 5,323 5,651 Net deferred tax assets $ 5,323 $ 5,707 On November 20, 2015, the FASB issued Accounting Standards Update (ASU) 2015-17, “ Balance Sheet Classification of Deferred Taxes,” as part of the FASB’s simplification initiative to reduce complexity in accounting standards. The new guidance requires that all deferred tax assets and liabilities for each jurisdiction, along with any valuation allowance, be classified as noncurrent on the balance sheet. The new guidance is effective for public businesses in fiscal years beginning after December 15, 2016. However, as early adoption is permitted as of the beginning of an interim or annual reporting period in which the ASU 2015-17 was issued, we decided to apply the new standard for the December 31, 2015 period. As the guidance allows for prospective application of the new standard, prior period financial statements have not been retrospectively adjusted. 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 related to our investments (primarily in KMP) of $3.6 billion and $4.9 billion at December 31, 2015 and 2014, respectively. 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 have deferred tax assets of $1,005 million related to net operating loss carryovers, $339 million related to alternative minimum and foreign tax credits, and $91 million of valuation allowances related to deferred tax assets at December 31, 2015. As of December 31, 2014, we had deferred tax assets of $466 million related to net operating loss carryovers, $312 million related to alternative minimum and foreign tax credits, and valuation allowances related to deferred tax assets of $93 million . We expect to generate taxable income beginning in 2019 and utilize all federal net operating loss carryforwards and alternative minimum tax carryforwards by the end of 2023. Expiration Periods for Deferred Tax Assets: As of December 31, 2015, we have U.S. federal net operating loss carryforwards of $2.4 billion , which will expire from 2018 - 2035; state losses of $3.1 billion which will expire from 2015 - 2035; and foreign losses of $154 million , of which approximately $115 million carries over indefinitely and $39 million expires from 2028 - 2035. We also have $312 million of federal alternative minimum tax credits which do not expire; and approximately $26 million of foreign tax credits, the majority of which will expire from 2016 - 2025. Use 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. 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, 2015 2014 2013 Balance at beginning of period $ 189 $ 209 $ 269 Uncertain tax positions of EP — — 4 Subtotal 189 209 273 Additions based on current year tax positions 4 12 11 Additions based on prior year tax positions — — 26 Reductions based on prior year tax positions (6 ) (3 ) — Reductions based on settlements with taxing authority (25 ) (24 ) (86 ) Reductions due to lapse in statute of limitations (14 ) (5 ) (15 ) Balance at end of period $ 148 $ 189 $ 209 We recognize interest and/or penalties related to income tax matters in income tax expense. As of December 31, 2015 , 2014, and 2013, we had $24 million , $28 million and $29 million , respectively, of accrued interest and $2 million , $2 million and $2 million , respectively, in accrued penalties. All of the $148 million of unrecognized tax benefits, if recognized, would affect our effective tax rate in future periods. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by approximately $5 million during the next year to approximately $143 million . We are subject to taxation, and have tax years open to examination for the periods 2011-2014 in the U.S., 2002-2014 in various states and 2007-2014 in various foreign jurisdictions.

Property, Plant and Equipment (

Property, Plant and Equipment (Notes)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure [Text Block]	Property, Plant and Equipment, net Classes and Depreciation As of December 31, 2015 and 2014 , our property, plant and equipment, net consisted of the following (in millions): December 31, 2015 2014 Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 19,855 $ 18,119 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 22,979 21,233 Other(a) 4,719 4,484 Accumulated depreciation, depletion and amortization (10,851 ) (8,369 ) 36,702 35,467 Land and land rights-of-way 1,450 1,324 Construction work in process 2,395 1,773 Property, plant and equipment, net $ 40,547 $ 38,564 _______ (a) Includes buildings, computer and communication equipment, vessels, linefill and other. As of December 31, 2015 and 2014 , property, plant and equipment included $16,089 million and $15,026 million , respectively, of assets which were regulated by either the FERC or the NEB. Depreciation, depletion, and amortization expense charged against property, plant and equipment was $2,059 million , $1,862 million , and $1,663 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. Asset Retirement Obligations As of December 31, 2015 and 2014 , we recognized asset retirement obligations in the aggregate amount of $215 million and $192 million , respectively, of which $9 million and $7 million , respectively, were classified as current. The majority of our asset retirement obligations are associated with our CO 2 business segment, where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors.

Investments Investments (Notes)

Investments Investments (Notes)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 , our investments consisted of the following (in millions): December 31, 2015 2014 Citrus Corporation $ 1,719 $ 1,805 Ruby Pipeline Holding Company, L.L.C. 1,093 1,123 MEP 713 748 Gulf LNG Holdings Group, LLC 516 547 EagleHawk 348 337 Plantation Pipe Line Company 327 303 Watco Companies, LLC 201 103 Red Cedar Gathering Company 185 184 Double Eagle Pipeline LLC 158 150 Kinder Morgan NGPL Holdings LLC 153 — Parkway Pipeline LLC 131 144 FEP 116 130 Fort Union Gas Gathering L.L.C. 50 70 Sierrita Gas Pipeline LLC 60 63 Cortez Pipeline Company — 17 All others 262 304 Total equity investments 6,032 6,028 Bond investments 8 8 Total investments $ 6,040 $ 6,036 As shown in the table above, our significant equity investments, as of December 31, 2015 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 and owns the remaining 50% interest; • Ruby Pipeline Holding Company, L.L.C.—We operate and own a 50% interest in Ruby Pipeline Holding Company, L.L.C., the sole owner of Ruby Pipeline natural gas transmission system. The remaining 50% interest is owned by a subsidiary of Veresen Inc. as convertible preferred interests; • MEP—We operate 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.; • Gulf LNG Holdings Group, LLC—We operate 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% ownership interests are wholly and partially owned by subsidiaries of GE Financial Services and The Blackstone Group L.P.; • BHP Billiton Petroleum (Eagle Ford) LLC, f/k/a EagleHawk and referred to in this report as 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; • Plantation—We operate 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; • Watco Companies, LLC—We hold a preferred 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 0.5% . The Class A preferred shares have no conversion features and 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 26,000 common equity units, which represents a 7.2% ownership that is accounted for under the equity method of accounting; • 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; • 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; • Kinder Morgan NGPL Holdings LLC— We operate 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. Effective December 10, 2015 we and 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 and during December 2015 we made an additional contribution of $17 million . • Parkway Pipeline LLC —We operate and own 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; • 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; • 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; • Sierrita Gas Pipeline LLC — We operate 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% ; and • Cortez Pipeline Company—We operate and own a 50% interest in the Cortez Pipeline Company, the sole owner of the Cortez carbon dioxide pipeline system. A subsidiary of Exxon Mobil Corporation owns a 37% interest and Cortez Vickers Pipeline Company owns the remaining 13% interest. Our earnings (losses) from equity investments were as follows (in millions): Year Ended December 31, 2015 2014 2013 Citrus Corporation $ 96 $ 97 $ 84 FEP 55 55 55 Gulf LNG Holdings Group, LLC 49 48 47 MEP 45 45 40 Red Cedar Gathering Company 26 33 31 EagleHawk 24 (7 ) 9 Plantation Pipe Line Company 29 29 35 Ruby Pipeline Holding Company, L.L.C. 18 15 (6 ) Watco Companies, LLC 16 13 13 Sierrita Gas Pipeline LLC 9 3 — Parkway Pipeline LLC 5 8 1 Double Eagle Pipeline LLC(a) 3 (1 ) 1 Cortez Pipeline Company(b) (3 ) 25 24 Fort Union Gas Gathering L.L.C.(a)(c) (4 ) 16 11 NGPL Holdco LLC(d) — — (66 ) All others 16 27 48 Total $ 384 $ 406 $ 327 Amortization of excess costs $ (51 ) $ (45 ) $ (39 ) _______ (a) 2013 amounts are for the period from May 1, 2013 through December 31, 2013. (b) 2015 amount includes $26 million representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company. (c) 2015 amount includes a non-cash impairment charge of $20 million (pre-tax) related to our investment. (d) 2013 amount includes non-cash impairment charges of $65 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 2015 2014 2013 Revenues $ 3,857 $ 3,829 $ 3,615 Costs and expenses 3,408 3,063 2,803 Net income (loss) $ 449 $ 766 $ 812 December 31, Balance Sheet 2015 2014 Current assets $ 811 $ 943 Non-current assets 19,745 20,630 Current liabilities 1,009 1,643 Non-current liabilities 11,227 10,841 Partners’/owners’ equity 8,320 9,089

Goodwill Goodwill (Notes)

Goodwill Goodwill (Notes)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 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 $ 5,637 $ 1,528 $ 1,908 $ 221 $ 1,486 $ 610 $ 28,917 Accumulated impairment losses (1,643 ) (447 ) — (1,197 ) (70 ) (679 ) (377 ) (4,413 ) December 31, 2013 15,884 5,190 1,528 711 151 807 233 24,504 Acquisitions(a) — 82 — — — 89 — 171 Currency translation — — — — — — (19 ) (19 ) Divestiture — — — — — (2 ) — (2 ) December 31, 2014 15,884 5,272 1,528 711 151 894 214 24,654 Acquisitions(b) — 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 _______ (a) 2014 includes $82 million related to the May 2013 Copano acquisition in Natural Gas Pipelines Non-Regulated and $89 million related to Terminals’ acquisitions of APT tankers in January 2014 and Crowley tankers in November 2014, as discussed in Note 3. (b) 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. 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 determined the fair value of each reporting unit as of May 31, 2015, based primarily on a market approach utilizing a median dividend/distribution yield of comparable companies. The value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represented the price estimated to be received in a sale of the reporting unit in an orderly transaction between market participants at the measurement date. The results of our annual test during the second quarter indicated fair value in excess of carrying value for each of our reporting units. We noted no significant events or conditions during the third quarter of 2015 that would have affected the conclusions from our annual assessment in the prior quarter. During the month of December 2015, consistent with decreases in certain market indices which track the market sectors in which we operate, the Company’s market capitalization decreased by approximately 36% after experiencing declines earlier in the quarter. During the fourth quarter 2015, many energy companies also indicated their dividends/distributions may be impacted by the ongoing effect of commodity prices on market conditions in the energy sector. As discussed above, our step 1 test performed as of May 31, 2015, used market valuations primarily based on dividend/distribution yields. This indicated that our prior step 1 valuations required re-evaluation. Based on these indicators and related factors, we conducted an interim test of the recoverability of goodwill as of December 31, 2015. Our step 1 test as of December 31, 2015, utilized both a market approach and income approach to estimate the fair values of our reporting units. The market approach was based on enterprise value (EV) to estimated EBITDA multiples. We believe these multiples appropriately reflect fair value for purposes of our step 1 goodwill impairment test because EV/EBITDA is not dependent on dividend/distribution policy, capital structure or tax profile. For our Natural Gas Pipelines Regulated and Non-Regulated and our CO 2 reporting units, we also conducted 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. 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 3% for our Natural Gas Pipelines Regulated reporting unit to 104% for our Products Pipelines Terminals. If the fair value of the Natural Gas Pipelines Regulated reporting unit decreased by approximately 3% , it could indicate a possible failure of the step 1 test. The primary assumptions in our step 1 market approach test include the following: • We selected a peer group of midstream companies with large market capitalizations with comparable operations, economic characteristics, and assets which generally include significant holdings of interstate transmission pipelines, midstream gathering and processing systems, and/or terminal operations. We use this peer group for all of our reporting units with the exception of our CO 2 reporting unit. We estimated the median enterprise value to EBITDA multiple to be approximately 12.7 x, without consideration of any control premium. • For our CO 2 reporting unit, we utilized a group of large independent oil and gas exploration and production companies which generally have operations similar to ours and include assets in the Permian basin where we operate and may have enhanced oil recovery operations similar to ours. We estimated the median enterprise value to EBITDA multiple for this peer group to be approximately 7.9 x, without consideration of any control premium. • In calculating the market multiples, we used estimates of enterprise value as of December 31, 2015, and consensus estimates of the 2015 EBITDA for each company in the peer group obtained from a third party provider of financial data. Estimates of enterprise value were calculated based on market capitalization plus net debt utilizing the most recent data available as of December 31, 2015. EV/EBITDA multiples are sensitive to changes in the components that comprise the ratio, including EBITDA, market capitalizations, and debt of the peer group companies. • We assessed the reasonableness of the control premium implied by the above market valuations as the market multiples include equity values on a non-controlling basis. As such, we considered the implied control premium as part of our reconciliation of our total reporting unit estimated fair value to our market capitalization which indicated an implied control premium of 34% , which we considered to be reasonable. For our CO 2 reporting unit, the above market approach indicated a fair value of approximately 7.9 x EBITDA. Management concluded because of current commodity price conditions, the fair value based on the market approach should be given partial weighting with a discounted cash flow analysis. The discounted cash flow analysis indicated a fair value of approximately 4.1 x EBITDA. Based on a weighting of the market and income approaches, we determined a fair value of the CO 2 reporting unit of approximately 5.1 x EBITDA. If the fair value of the CO 2 reporting unit decreased by approximately 12% , this could indicate a possible impairment of goodwill requiring a step 2 analysis. Applying the market approach to our Natural Gas Pipeline Non-Regulated reporting unit indicated an 18% deficit of fair value as compared to carrying value. We also applied an income approach to this reporting unit, which indicated a deficit of fair value of approximately 4% as compared to the carrying value. The results of our step 1 test of our Natural Gas Pipelines Non-Regulated reporting unit indicated that our carrying value exceeded the fair value thereby requiring us to perform a step 2 evaluation. The primary assumptions in our step 1 income approach for this reporting unit include the following: • Based on the weighted-average cost of capital of the peer group, we determined the appropriate rate at which to discount the cash flows is 8% . Each 100 basis points change in the discount rate changes the estimated fair value by approximately 5% . • We used a five -year forward commodity price curve which assumed $38 crude and $2.50 natural gas in 2016 gradually increasing over the following five years to $65 and $3.50 , respectively, and then remaining flat. Management developed this price curve based on the year-end NYMEX price curve and a third party median consensus five year forward price curve. • We estimated cash flows based on 6 years of projections and applied exit multiples, ranging from 10x to 15x based on management’s expectations of those that would be applied by a market participant and market transactions for comparable assets, to year 6 cash flows. These cash flows have various assumptions on volumes and prices based on management’s expectations for each underlying component asset within the reporting unit. • We estimated ethane fractionation spreads based on the relationship between ethane and natural gas prices. Our estimates assumed $(0.01) for 2016-2017, increasing to $0.15 in 2018 through 2021 based on a trailing five -year average spreads as management expects demand to increase commensurate with expected petrochemical capacity and export facilities coming online around that time. • Consistent with how we evaluate potential acquisitions and we believe a market participant would do, we assumed a certain amount of capital expenditure, including for projects that are already in progress, and consistent with historical levels as adjusted for commodity prices assumptions and customer activity. We assumed an approximate 12% return on this invested capital beginning in the years the assets are expected to be placed in service. After considering the market and income approaches, we determined the $19.0 billion carrying value of this reporting unit exceeded the estimated fair value of $17.2 billion , and therefore conducted a step 2 analysis. The fair value was estimated based on a weighting of the market and income approaches for this reporting unit. This implies an EBITDA valuation of approximately 14.0 x. Management believes this is a reasonable estimate of fair value based on comparable sales transactions and the fact that it implies a reasonable control premium at the reporting unit level. Below is a hypothetical allocation of the fair value to the assets and liabilities of this reporting unit, including goodwill. The amount of implied goodwill is then compared to the carrying value of goodwill to determine the amount of impairment (in millions). Allocation of Fair Value: Working capital, net $ 232 Property, plant and equipment 9,627 Other intangible assets 3,121 Other liabilities, net (7 ) Goodwill 4,215 Estimated Reporting Unit Fair Value $ 17,188 Prior carrying amount of goodwill $ 5,365 Goodwill impairment $ 1,150 The key assumptions used in determining the fair value of the assets and liabilities of the reporting unit are as follows: • Working capital and other liabilities were assumed to have fair values that approximate carrying value as these generally relate to monetary assets and liabilities that settle in the short-term, derivative positions that are recorded at fair value, and inventory which has been subjected to lower of cost or market adjustments in a declining commodity price environment. • With respect to property, plant and equipment, and other intangibles, the company based its determination of fair values on previously completed fair value studies conducted for these assets as updated for developments subsequent to the date of the initial studies. • The fair value allocation assumed the reporting unit would be sold in a taxable transaction. The result of our step 2 analysis was a partial impairment of goodwill in our Natural Gas Pipelines Non-Regulated reporting unit of approximately $1,150 million . The above fair value estimates are based on Level 3 Inputs of the fair value hierarchy. The sustained decrease and the long-term outlook in commodity prices have adversely impacted our customers and their future capital and operating plans. A continued or prolonged period of lower 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 change to any one or combination of these factors would result in a change to the reporting unit fair values discussed above which could lead to further impairment charges. This would negatively impact our estimates of the fair values of our reporting units and could cause impairments of long-lived assets, equity method investments, and/or goodwill. Such non-cash impairments from one or both, or any, of these reportable units could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value exceeds fair value.

Debt (Notes)

Debt (Notes)	12 Months Ended
	Dec. 31, 2015
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. In 2015, we adopted Accounting Standards Updates (ASU) 2015-03, “ Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ” and ASU 2015-15, “ Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements—Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update). ” These ASUs are designed to simplify presentation of debt issuance costs. The standards require that debt issuance costs related to a recognized debt liability, except for line-of-credit debt issuance costs, be presented in the balance sheet as an offset to the carrying amount of that debt liability, consistent with debt discounts. The application of this new accounting guidance resulted in the reclassification of $149 million of debt issuance costs from “Deferred charges and other assets” to “Debt fair value adjustments” in our accompanying consolidated balance sheet as of December 31, 2014 . 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 and premiums (in millions): December 31, 2015 2014 KMI Senior notes 1.50% through 8.25%, due 2015 through 2098(a)(b)(c) $ 13,346 $ 11,438 Credit facility due November 26, 2019(d)(e) — 850 Commercial paper borrowings(d)(e) — 386 KMP Senior notes, 2.65% through 9.00%, due 2015 through 2044(b)(f) 19,985 20,660 TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(b)(h) 1,790 1,790 EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(b) 1,115 1,115 Copano senior notes, 7.125%, due April 1, 2021(b) 332 332 CIG senior notes, 5.95% through 6.85%, due 2015 through 2037(b) 100 475 SNG notes, 4.40% through 8.00%, due 2017 through 2032(b)(g) 1,211 1,211 Other Subsidiary Borrowings (as obligor) Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(b)(h) 1,636 1,636 Hiland Partners Holdings LLC, senior notes, 5.50% and 7.25%, due 2020 and 2022(b)(i) 974 — EPC Building, LLC, promissory note, 3.967%, due 2015 through 2035 443 453 Preferred securities, 4.75%, due March 31, 2028(j) 221 280 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(k) 100 100 Other miscellaneous debt(l) 300 303 Total debt – KMI and Subsidiaries 41,553 41,029 Less: Current portion of debt(m) 821 2,717 Total long-term debt – KMI and Subsidiaries(n) $ 40,732 $ 38,312 _______ (a) December 31, 2015 amount includes senior notes that are denominated in Euros and have been converted and are reported at the December 31, 2015 exchange rate of 1.0862 U.S. dollars per Euro. From the issuance date of these senior notes in March 2015 through December 31, 2015 , our debt increased by less than $1 million as a result of the change in the exchange rate of 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) Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. (c) Includes $6.0 billion of senior notes issued on November 26, 2014 as a result of the Merger Transactions (see “—Long-term Debt Issuances and Repayments” below). (d) As of December 31, 2014 , the weighted average interest rate on our credit facility borrowings, including commercial paper borrowings, was 1.54% . (e) On November 26, 2014, we entered into a $4 billion replacement credit facility and a commercial paper program of up to $4 billion of unsecured notes (see “—Credit Facilities and Restrictive Covenants” below). (f) On January 1, 2015, EPB and EPPOC merged with and into KMP. On that date, KMP succeeded EPPOC as the issuer of approximately $2.9 billion of EPPOC’s senior notes, which were guaranteed by EPB, and EPB and EPPOC ceased to be obligors for those senior notes. (g) Southern Natural Issuing Corporation is a wholly owned finance subsidiary of SNG and is the co-issuer of certain of SNG’s outstanding debt securities. (h) In January and February 2016, we refinanced $850 million of maturing Kinder Morgan Finance Company LLC senior notes and $150 million of maturing TGP senior notes using proceeds from a new three -year term loan facility (see “— Subsequent Event—Debt Issuances and Repayments” below). (i) Represents the remaining principal amount outstanding of senior notes assumed in the Hiland acquisition. (j) Capital Trust I (Trust I), is a 100% -owned business trust that as of December 31, 2015 , 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, 2015 , the outstanding balance of $221 million (of which $111 million is classified as current) was bifurcated between debt ( $197 million ) and equity ( $24 million ). During the years ended December 31, 2015 and 2014 , 1,176,015 and 3,923 Trust I Preferred Securities had been converted into (i) 846,369 and 2,820 shares of our Class P common stock; (ii) approximately $30 million and $99,000 in cash; and (iii) 1,293,615 and 4,315 in warrants, respectively. (k) As of December 31, 2015 and 2014, 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. (l) 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, 2015 , the principal amounts of the Totem and High Plains financing obligations were $72 million and $96 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. (m) Amounts include outstanding credit facility and commercial paper borrowings and other debt maturing within 12 months. See “ — Maturities of Debt” below. (n) Excludes our “Debt fair value adjustments” which, as of December 31, 2015 and December 31, 2014 , increased our combined debt balances by $1,674 million and $1,785 million , respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs (resulting from the implementation of ASU No. 2015-03 and 2015-15) 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 Note 15 “Fair Value— Debt Fair Value Adjustments. ” We and substantially all of our 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 September 19, 2014, we entered into a new five -year $4.0 billion revolving credit agreement with a syndicate of lenders, which can be increased to $5.0 billion if certain conditions are met (see “—Subsequent Event—Credit Facility Capacity” following). The new revolving credit agreement was effective upon the closing of the Merger Transactions on November 26, 2014 and replaced the prior KMI credit agreement, the KMP credit agreement and the EPB credit agreement. On November 26, 2014, we entered into 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, 2015 , we were in compliance with all required financial covenants. Our credit facility included the following restrictive covenants as of December 31, 2015 : • 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, 2015 , we had no borrowings outstanding under our five -year $4.0 billion revolving credit facility, no borrowings outstanding under our $4.0 billion commercial paper program and $115 million in letters of credit. Our availability under this facility as of December 31, 2015 was $3,885 million . On February 13, 2015, in connection with the Hiland acquisition, we entered into and made borrowings of $1,641 million under a new six -month bridge credit facility with UBS AG, Stamford Branch. Interest under this bridge credit facility was charged at the same rate as our $4.0 billion revolving credit facility. Prior to March 31, 2015, we repaid outstanding borrowings and the facility was terminated on April 6, 2015. Subsequent Event—Credit Facility Capacity On January 26, 2016, in accordance with the terms of our revolving credit agreement, we increased the capacity of our revolving credit agreement from $4.0 billion to $5.0 billion . The terms of the revolving credit agreement remain the same. Hiland Debt Acquired 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. Long-term Debt Issuances and Repayments Apart from the assumption of the Hiland debt discussed above, following are significant long-term debt issuances and repayments made during 2015 and 2014 : 2015 2014 Issuances $800 million 5.05% notes due 2046 $650 million senior term loan facility due 2017 $815 million 1.50% notes due 2022(a) $500 million 2.00% notes due 2017(b) $543 million 2.25% notes due 2027(a) $1,500 million 3.05% notes due 2019(b) $1,500 million 4.30% notes due 2025(b) $750 million 5.30% notes due 2034(b) $1,750 million 5.55% notes due 2045(b) $750 million 3.50% notes due 2021 $750 million 5.50% notes due 2044 $650 million 4.25% notes due 2024 $550 million 5.40% notes due 2044 $600 million 4.30% notes due 2024 Repayments $300 million 5.625% notes due 2015 $500 million 5.125% notes due 2014 $250 million 5.15% notes due 2015 $1,528 million senior term loan facility due 2015 $340 million 6.80% notes due 2015 $650 million senior term loan facility due 2017(b) $375 million 4.10% notes due 2015 $207 million 6.875% notes due 2014 ________ (a) Senior notes are denominated in Euros and are presented above in U.S. dollars at the exchange rate on the issuance date of 1.0860 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) Debt issued or repaid associated with the Merger Transactions. Subsequent Event—Debt Issuances and Repayments In January 2016, we entered into a $1.0 billion three -year unsecured term loan facility due in 2019 at 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 at December 31, 2015. Maturities of Debt The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2015 , are summarized as follows (in millions): Year Total 2016(a) $ 821 2017 3,060 2018 2,329 2019(a) 3,819 2020 2,953 Thereafter 28,571 Total $ 41,553 ________ (a) 2016 amount primarily includes $667 million of current maturities on senior notes and $111 million associated with our Trust I Preferred Securities that are classified as current obligations because these securities have rights to convert into consideration consistent with the EP merger, and excludes $1,000 million of current maturities on long-term debt that were refinanced with proceeds from the issuance of a January 2016 three -year term loan which is reflected in 2019. 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, 2015 , the weighted-average amortization period of the unamortized premium from the termination of the 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 2015 2014 Purchase accounting debt fair value adjustments $ 1,135 $ 1,221 Carrying value adjustment to hedged debt 380 347 Unamortized portion of proceeds received from the early termination of interest rate swap agreements 397 454 Unamortized debt discount/premiums (86 ) (88 ) Unamortized debt issuance costs (152 ) (149 ) Total debt fair value adjustments $ 1,674 $ 1,785 Interest Rates, Interest Rate Swaps and Contingent Debt The weighted average interest rate on all of our borrowings was 4.92% during 2015 and 5.02% during 2014 . 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, 2015
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 2015 , 2014 and 2013 , we made restricted Class P common stock grants to our non-employee directors of 9,580 , 6,210 and 5,710 , respectively. These grants were valued at time of issuance at $401,000 , $220,000 and $210,000 , 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 amounts): Year Ended Year Ended Year Ended December 31, 2013 Shares Weighted Average Grant Date Fair Value Shares Weighted Average Grant Date Fair Value Shares Weighted Average Grant Date Fair Value Outstanding at beginning of period 7,373,294 $ 277 6,382,885 $ 239 2,154,022 $ 69 Granted 1,488,467 57 1,694,668 61 4,563,495 181 Vested (817,797 ) (29 ) (460,032 ) (14 ) (83,444 ) (3 ) Forfeited (398,859 ) (15 ) (244,227 ) (9 ) (251,188 ) (8 ) Outstanding at end of period 7,645,105 $ 290 7,373,294 $ 277 6,382,885 $ 239 Intrinsic value of restricted stock awards vested during the period $ 31 $ 17 $ 3 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 2016 1,096,290 2017 1,563,549 2018 2,443,888 2019 1,688,831 2020 585,574 Thereafter 266,973 Total Outstanding 7,645,105 The related expense 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 2015 , 2014 and 2013 , we recorded $67 million , $57 million and $35 million , respectively, in expense related to restricted stock awards. At December 31, 2015 and 2014 , unrecognized restricted stock awards compensation expense, less estimated forfeitures, was approximately $154 million and $170 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 $46 million , $42 million , and $40 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Pension Plans Our 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. 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. Medical benefits for these closed groups of retirees 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 plan was 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, 2015 and 2014 (in millions): Pension Benefits OPEB 2015 2014 2015 2014 Change in benefit obligation: Benefit obligation at beginning of period $ 2,804 $ 2,563 $ 624 $ 631 Service cost 33 21 — — Interest cost 99 112 21 25 Actuarial (gain) loss (109 ) 294 (101 ) 15 Benefits paid (173 ) (186 ) (39 ) (52 ) Participant contributions — — 2 3 Medicare Part D subsidy receipts — — 2 2 Benefit obligation at end of period 2,654 2,804 509 624 Change in plan assets: Fair value of plan assets at beginning of period 2,377 2,333 389 380 Actual (loss) return on plan assets (204 ) 180 (45 ) 32 Employer contributions 50 50 16 25 Participant contributions — — 2 3 Medicare Part D subsidy receipts — — 2 1 Benefits paid (173 ) (186 ) (39 ) (52 ) Fair value of plan assets at end of period 2,050 2,377 325 389 Funded status - net liability at December 31, $ (604 ) $ (427 ) $ (184 ) $ (235 ) Components of Funded Status . The following table details the amounts recognized in our balance sheet at December 31, 2015 and 2014 related to our pension and OPEB plans (in millions): Pension Benefits OPEB 2015 2014 2015 2014 Non-current benefit asset $ — $ — $ 139 $ 173 Current benefit liability — — (16 ) (22 ) Non-current benefit liability (604 ) (427 ) (307 ) (386 ) Funded status - net liability at December 31, $ (604 ) $ (427 ) $ (184 ) $ (235 ) Components of Accumulated Other Comprehensive (Loss) Income . The following table details the amounts of pre-tax accumulated other comprehensive (loss) income at December 31, 2015 and 2014 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 2015 2014 2015 2014 Unrecognized net actuarial (loss) gain $ (558 ) $ (296 ) $ 23 $ (27 ) Unrecognized prior service (cost) credit (4 ) (4 ) 19 20 Accumulated other comprehensive (loss) income $ (562 ) $ (300 ) $ 42 $ (7 ) We anticipate that approximately $28 million of pre-tax accumulated other comprehensive loss will be recognized as part of our net periodic benefit cost in 2016 , including approximately $29 million of unrecognized net actuarial loss and approximately $1 million of unrecognized prior service credit. Our accumulated benefit obligation for our pension plans was $2,615 million and $2,719 million at December 31, 2015 and 2014 , respectively. Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $444 million and $553 million at December 31, 2015 and 2014 , respectively. The fair value of these plans’ assets was approximately $121 million and $145 million at December 31, 2015 and 2014 , respectively. Plan Assets. The investment policies and strategies for the assets of each of the pension and OPEB plans are established by the Fiduciary Committee (the “Committee”), which is responsible for investment decisions and management oversight of each plan. The stated philosophy of the Committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (1) meet or exceed plan actuarial earnings assumptions over the long term and (2) provide a reasonable return on assets within established risk tolerance guidelines and to maintain the liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the Committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the Committee has adopted a strategy of using multiple asset classes. As of December 31, 2015 , the allowable range for asset allocations in effect for the 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, 2015 , the allowable range for asset allocations in effect for the retiree medical and retiree life insurance plans were 15% to 56% equity, 15% to 47% fixed income, 0% to 19% cash and 13% to 38% master limited partnerships. In 2015, we adopted ASU No. 2015-07, “Fair Value Measurement (Topic 820) — Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent).” This ASU removes the requirement to include investments in the fair value hierarchy for which the fair value is measured at Net Asset Value (NAV) using the practical expedient under Topic 820. 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, common and preferred stock, exchange traded mutual funds and 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 money market funds and fixed income securities. Money market 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. • 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 insurance contracts and interest rate swaps. Insurance 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, equity trusts, mutual funds, limited partnerships, private equity 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, 2015 and 2014 (in millions): Pension Assets 2015 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Cash and money market funds $ 15 $ 110 $ — $ 125 $ 5 $ 91 $ — $ 96 Insurance contracts — — 15 15 — — 15 15 Mutual funds(a) 70 — — 70 71 — — 71 Common and preferred stocks(b) 271 — — 271 459 — — 459 Corporate bonds — 244 — 244 — 247 — 247 U.S. government securities — 171 — 171 — 190 — 190 Asset backed securities — 34 — 34 — 28 — 28 Other — — (14 ) (14 ) — — (15 ) (15 ) Subtotal $ 356 $ 559 $ 1 916 $ 535 $ 556 $ — 1,091 Measured at NAV(c) Common/collective trusts(d) 775 863 Equity trusts 187 199 Mutual funds(e) 160 198 Limited partnerships(f) 1 13 Private equity(g) 11 13 Subtotal 1,134 1,286 Total plan assets fair value $ 2,050 $ 2,377 _______ (a) For 2015 and 2014 , this category includes mutual funds which are invested in equity. (b) Plan assets include $91 million and $252 million of KMI Class P common stock for 2015 and 2014 , 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 45% fixed income and 55% equity in 2015 and 47% fixed income and 53% equity in 2014 . (e) Mutual funds were invested in fixed income for 2015 and 2014 . (f) Limited partnerships were invested in real estate partnerships for 2015 and 2014 . (g) Private equity was invested in limited partnerships that primarily invest in venture and buyout funds for 2015 and 2014 . OPEB Assets 2015 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Cash and money market funds $ — $ 16 $ — $ 16 $ (3 ) $ 26 $ — $ 23 Domestic equity securities 8 — — 8 14 — — 14 Limited partnerships 51 — — 51 87 — — 87 Insurance contracts — — 49 49 — — 51 51 Mutual funds 1 — — 1 1 — — 1 Subtotal $ 60 $ 16 $ 49 125 $ 99 $ 26 $ 51 176 Measured at NAV(a) Common/collective trusts(b) 71 71 Fixed income trusts 58 63 Limited partnerships(c) 71 79 Subtotal 200 213 Total plan assets fair value $ 325 $ 389 _______ (a) Plan assets for which fair value was measured using NAV as a practical expedient. (b) For 2015 and 2014 , this category includes common/collective trust funds which are invested in approximately 67% equity and 33% fixed income securities, respectively. (c) For 2015 and 2014 , 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, 2015 and 2014 (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 2015 Insurance contracts $ 15 $ — $ — $ — $ 15 Other (15 ) — (2 ) 3 (14 ) Total $ — $ — $ (2 ) $ 3 $ 1 2014 Insurance contracts $ 15 $ — $ — $ — $ 15 Other 11 — (18 ) (8 ) (15 ) Total $ 26 $ — $ (18 ) $ (8 ) $ — OPEB Assets Balance at Beginning of Period Transfers In (Out) Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period 2015 Insurance contracts $ 51 $ — $ (1 ) $ (1 ) $ 49 2014 Insurance contracts $ 50 $ — $ (4 ) $ 5 $ 51 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, 2015 and 2014 . Expected Payment of Future Benefits and Employer Contributions . As of December 31, 2015 , we expect to make the following benefit payments under our plans (in millions): Fiscal year Pension Benefits OPEB(a) 2016 $ 230 $ 39 2017 197 39 2018 196 39 2019 198 39 2020 197 38 2021-2025 962 182 _______ (a) Includes a reduction of approximately $3 million in each of the years 2016 - 2020 and approximately $18 million in aggregate for 2021 - 2025 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. We do not have any statutory funding requirements in 2016 for our pension plan; however, we may decide to make a contribution in 2016 depending on the market performance of our pension plan assets and other factors. In 2016 , we expect to contribute approximately $14 million , net of anticipated subsidies, to our 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 2015 , 2014 and 2013 : Pension Benefits OPEB 2015 2014 2013 2015 2014 2013 Assumptions related to benefit obligations: Discount rate 4.05 % 3.66 % 4.45 % 3.91 % 3.56 % 4.34 % Rate of compensation increase 3.50 % 4.50 % 3.50 % n/a n/a n/a Assumptions related to benefit costs: Discount rate(a) 3.66 % 4.45 % 3.40 % 3.56 % 4.34 % 3.62 % Expected return on plan assets(b) 7.50 % 7.50 % 8.00 % 7.08 % 7.43 % 7.35 % Rate of compensation increase 4.50 % 3.50 % 3.00 % n/a n/a n/a _______ (a) The discount rate related to other postretirement benefit cost was 3.34% for the period from January 1, 2013 to July 31, 2013 (the period prior to an OPEB plan amendment that resulted in a remeasurement) and 4.00% for the period from August 1, 2013 to December 31, 2013. (b) 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 both 2015 and 2014 and 24% for 2013. For 2015, 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 does not affect the measurement of our pension and postretirement benefit obligations and it is accounted for as a change in accounting estimate, which is applied prospectively. The change in the service and interest costs going forward will not be significant. 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 9.89% , 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, 2015 and 2014 (in millions): 2015 2014 One-percentage point increase: Aggregate of service cost and interest cost $ 2 $ 2 Accumulated postretirement benefit obligation 31 47 One-percentage point decrease: Aggregate of service cost and interest cost $ (1 ) $ (2 ) Accumulated postretirement benefit obligation (27 ) (40 ) 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 2015 2014 2013 2015 2014 2013 Components of net benefit cost: Service cost $ 33 $ 21 $ 25 $ — $ — $ — Interest cost 99 112 92 21 25 23 Expected return on assets (172 ) (171 ) (175 ) (23 ) (24 ) (22 ) Amortization of prior service credit — — — (3 ) (2 ) (1 ) Amortization of net actuarial loss (gain) 5 — — 1 (1 ) 3 Curtailment and settlement gain — — (3 ) — — — Net benefit (credit) cost (35 ) (38 ) (61 ) (4 ) (2 ) 3 Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 267 285 (211 ) (49 ) 10 (50 ) Prior service cost (credit) arising during period — — 25 — — (18 ) Amortization or settlement recognition of net actuarial (loss) gain (5 ) — 3 (1 ) — (3 ) Amortization of prior service credit — — — 1 1 1 Total recognized in total other comprehensive (income) loss 262 285 (183 ) (49 ) 11 (70 ) Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ 227 $ 247 $ (244 ) $ (53 ) $ 9 $ (67 ) Other Plans Plans Associated with Foreign Operations 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 Trans Mountain pipeline system 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. These subsidiaries also provide postretirement benefits other than pensions for retired employees. Our combined net periodic benefit costs for these Trans Mountain pension and other postretirement benefit plans for the years ended December 31, 2015 , 2014 and 2013 was $12 million , $10 million and $11 million , respectively, recognized ratably over each year. As of December 31, 2015 , we estimate the overall net periodic pension and other postretirement benefit costs for these plans for the year 2016 will be approximately $10 million , although this estimate could change if there is a significant event, such as a plan amendment or a plan curtailment, which would require a remeasurement of liabilities. Furthermore, we expect to contribute approximately $10 million to these benefit plans in 2016 . Multiemployer Plans As a result of acquiring several terminal operations, primarily the acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, 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 $10 million , $13 million and $11 million for the years ended December 31, 2015 , 2014 and 2013 , 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, 2015
Stockholders' Equity Note [Abstract]
Shareholders' Equity	Stockholders’ Equity Common Equity As of December 31, 2015, our common equity consisted of our Class P common stock. During the years 2013 through 2015, as authorized by our board of directors under various repurchase programs, we repurchased shares and warrants. As of December 31, 2015, we had $90 million of availability to repurchase warrants. During the years ended December 31, 2015 , 2014 and 2013 , we paid a total of $12 million , $98 million and $465 million , respectively, for the repurchase of warrants. During the years ended December 31, 2014 and 2013 , we repurchased $94 million and $172 million respectively, 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, 2015 2014 2013 Per common share cash dividend declared for the period $ 1.605 $ 1.740 $ 1.600 Per common share cash dividend paid in the period 1.93 1.70 1.56 On January 20, 2016, our board of directors declared a cash dividend of $0.125 per common share for the quarterly period ended December 31, 2015, which is payable on February 16, 2016 to shareholders of record as of February 1, 2016. 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 2015 2014 2013 Beginning balance 298,135,976 347,933,107 439,809,442 Warrants issued in acquisition of EP(a) — — 81 Warrants issued with conversions of EP Trust I Preferred securities(b) 1,293,615 4,315 118,377 Warrants exercised (71,268 ) (18,040 ) (21,208 ) Warrants repurchased and canceled (6,094,526 ) (49,783,406 ) (91,973,585 ) Ending balance 293,263,797 298,135,976 347,933,107 _______ (a) 2013 amount represents warrants issued upon the settlement of an EP dissenter. The settlement of the dissenter’s 128 EP shares was determined based on the same conversion of EP shares into cash, KMI Class P shares and KMI warrants that was received by other EP shareholders at the time of the acquisition. (b) 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 November 17, 2015, our board of directors declared a cash dividend of $23.291667 per share of our mandatory convertible preferred stock (equivalent of $1.164583 per depository share) for the period from and including October 30, 2015 through and including January 25, 2016, which was paid on January 26, 2016 to mandatory convertible preferred shareholders of record as of January 11, 2016. 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 periods ended November 26, 2014 and December 31, 2013, KMP, EPB and KMR made equity issuances of 30 million and 63 million units or shares, respectively, resulting in net proceeds of $1,695 million and $1,580 million , respectively. These equity issuances during the periods ended November 26, 2014 and December 31, 2013 had the associated effects of increasing our (i) noncontrolling interests by $1,640 million and $5,059 million , respectively; (ii) accumulated deferred income taxes by $19 million and $93 million , respectively; and (iii) additional paid-in capital by $36 million and $161 million , respectively. 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 2013 KMP(a) Per unit cash distribution declared for the period $ 4.17 $ 5.33 Per unit cash distribution paid in the period $ 5.53 $ 5.26 Cash distributions paid in the period to the public $ 1,654 $ 1,372 EPB(a) Per unit cash distribution declared for the period $ 1.95 $ 2.55 Per unit cash distribution paid in the period $ 2.60 $ 2.51 Cash distributions paid in the period to the public $ 347 $ 318 KMR(a)(b) Share distributions paid in the period to the public 7,794,183 6,588,477 _______ (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 and 976,723 of shares distributed in 2014 and 2013, respectively, on KMR shares we directly and indirectly owned.

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 Balance sheet location Accounts receivable, net $ 25 $ 31 Other current assets 36 3 Deferred charges and other assets — 46 $ 61 $ 80 Current portion of debt(a) $ 6 $ 6 Accounts payable 22 22 Other current liabilities 10 — Long-term debt(a) 167 172 $ 205 $ 200 _______ (a) Includes financing obligations payable to WYCO (See Note 9). Year Ended December 31, 2015 2014 2013 Income statement location Services $ 72 $ 29 $ 31 Product sales and other 71 86 36 $ 143 $ 115 $ 67 Cost of sales $ 60 $ 74 $ 17 General and administrative 55 57 57 Notes Receivable Plantation We and ExxonMobil Corporation have a term loan agreement covering a note receivable due from Plantation. We own a 51.17% equity interest in Plantation and our proportionate share of the outstanding principal amount of the note receivable was $35 million and $47 million as of December 31, 2015 and 2014 , respectively. The note bears interest at the rate of 4.25% per annum and provides for semiannual payments of principal and interest on December 31 and June 30 each year, with a final principal payment for our remaining portion of the note due on July 20, 2016. We included $35 million and $1 million of the note receivable balance within “Other current assets” on our accompanying balance sheets as of December 31, 2015 and 2014 , respectively, and we included $46 million as of December 31, 2014 within “ Deferred charges and other assets .” Subsequent Event MEP Loan Agreement On February 3, 2016 we renewed our 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. Each individual loan must be in an amount not less than $2 million , and the aggregate loan balance outstanding must not exceed $40 million . 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, 2015 and 2014 there was no amount outstanding pursuant to this loan agreement.

Commitments and Contingent Liab

Commitments and Contingent Liabilities (Notes)	12 Months Ended
	Dec. 31, 2015
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, 2015 (in millions): Year Commitment 2016 $ 103 2017 90 2018 83 2019 78 2020 69 Thereafter 406 Total minimum payments $ 829 The remaining terms on our operating leases, including probable elections to exercise renewal options, range from one to forty years. Total lease and rental expenses were $143 million , $114 million and $126 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. The amount of capital leases included within “Property, plant and equipment, net” in our accompanying consolidated balance sheets as of December 31, 2015 and 2014 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, 2015 and 2014, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $1,202 million and $1,069 million , respectively. Both December 31, 2015 and 2014 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 its percentage ownership share ( 50% ) of the Cortez Pipeline Company debt and 100% of the debt issued by one of its subsidiaries in the event of their non-performance) which has a $200 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 In August 2015, we entered into a definitive agreement with Philly Tankers LLC totaling $568 million for the construction of four new Tier II, LNG-conversion-ready tankers each with a capacity of 337 MBbl. The tankers are expected to be delivered between November 2016 and November 2017 and would increase our Jones Act tanker fleet to 16 ships by late 2017. Our obligation for payments due under the terms of this agreement total $170 million in 2016 and $384 million in 2017.

Risk Management (Notes)

Risk Management (Notes)	12 Months Ended
	Dec. 31, 2015
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, we have power forward and swap contracts related to legacy operations of acquired businesses for which we entered into positions that offset the price risks associated with these contracts. As of December 31, 2014, we discontinued hedge accounting on certain of our crude derivative contracts as we did not expect them to continue to be highly effective, for accounting purposes, in offsetting the variability in cash flows. This was caused primarily by volatility in basis differentials. As the forecasted transactions are still probable, accumulated gains and losses remain in other comprehensive income until earnings are impacted by the forecasted transactions. Changes in the derivative contracts’ fair value subsequent to the discontinuance of hedge accounting are reported in earnings. As of December 31, 2015, all of these hedging relationships had been re-designated as the effectiveness improved to required levels. Energy Commodity Price Risk Management As of December 31, 2015 , we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales: Net open position long/(short) Derivatives designated as hedging contracts Crude oil fixed price (21.7 ) MMBbl Crude oil basis (6.4 ) MMBbl Natural gas fixed price (37.6 ) Bcf Natural gas basis (30.1 ) Bcf Derivatives not designated as hedging contracts Crude oil fixed price (0.6 ) MMBbl Crude oil basis (1.3 ) MMBbl Natural gas fixed price (14.3 ) Bcf Natural gas basis (8.6 ) Bcf NGL and other fixed price (1.9 ) MMBbl As of December 31, 2015 , 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 2019. Interest Rate Risk Management 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. As of December 31, 2014 , we had a combined notional principal amount of $9,200 million of fixed-to-variable interest rate swap agreements, all of which were designated as fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of December 31, 2015 , 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. In December 2015, we entered into nine separate fixed-to-variable interest rate swap agreements having a combined notional principal amount of $1,300 million . These agreements effectively convert a portion of the interest expense associated with our 4.15% senior notes due February 2, 2024, 3.50% senior notes due September 1, 2023 and 4.30% senior notes due May 1, 2024, from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread. 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 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, 2015 2014 2015 2014 Location Fair value Fair value Derivatives designated as hedging contracts Natural gas and crude derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 359 $ 309 $ (13 ) $ (34 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 244 6 — — Subtotal 603 315 (13 ) (34 ) Interest rate swap agreements Fair value of derivative contracts/(Other current liabilities) 111 143 — — Deferred charges and other assets/(Other long-term liabilities and deferred credits) 273 260 (9 ) (53 ) Subtotal 384 403 (9 ) (53 ) Cross-currency swap agreements Fair value of derivative contracts/(Other current liabilities) — — (6 ) — Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (46 ) — Subtotal — — (52 ) — Total 987 718 (74 ) (87 ) Derivatives not designated as hedging contracts Natural gas, crude, NGL and other derivative contracts Fair value of derivative contracts/(Other current liabilities) 35 73 (1 ) (2 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — 196 — — Subtotal 35 269 (1 ) (2 ) 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 10 (17 ) (57 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — — (16 ) Subtotal 1 10 (17 ) (73 ) Total 37 279 (34 ) (75 ) Total derivatives $ 1,024 $ 997 $ (108 ) $ (162 ) 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, 2015 2014 2013 Interest rate swap agreements Interest, net $ 25 $ 207 $ (425 ) Hedged fixed rate debt Interest, net $ (33 ) $ (204 ) $ 425 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, 2015 2014 2013 2015 2014 2013 2015 2014 2013 Energy commodity derivative contracts $ 201 $ 424 $ (45 ) Revenues—Natural gas sales $ 54 $ (1 ) $ — Revenues—Natural gas sales $ — $ — $ — Revenues—Product sales and other 236 26 (13 ) Revenues—Product sales and other 2 11 3 Costs of sales (15 ) 4 — Costs of sales — — — Interest rate swap agreements(c) (4 ) (15 ) 7 Interest, net (3 ) (4 ) 2 Interest, net — — — Cross-currency swap (33 ) — — Other, net — — — Other, net — — — Total $ 164 $ 409 $ (38 ) Total $ 272 $ 25 $ (11 ) Total $ 2 $ 11 $ 3 _______ (a) We expect to reclassify an approximate $181 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of December 31, 2015 into earnings during the next twelve months (when the associated forecasted sales and purchases 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 income/(loss). Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives Year Ended December 31, 2015 2014 2013 Energy commodity derivative contracts Revenues—Natural gas sales $ 17 $ (7 ) $ — Revenues—Product sales and other 176 20 (10 ) Costs of sales (2 ) — 2 Other expense (income) — (2 ) (2 ) Interest rate swap agreements Interest, net (15 ) — — Total(a) $ 176 $ 11 $ (10 ) ________ (a) For the year ended December 31, 2015 , includes approximate gain of $31 million 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, 2015 and 2014 , we had $2 million and $20 million , respectively, of outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2015 and December 31, 2014 , we had no cash margin and $47 million posted by us with our counterparties as collateral and $37 million and $13 million , respectively, held by us as collateral from our counterparties. 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, 2015 , based on our current mark to market positions and posted collateral, we estimate that if our credit rating was downgraded one or two notches, we would be required to post $1 million and $4 million , respectively, of additional collateral. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions): Net unrealized gains/(losses) on cash flow hedge derivatives Foreign currency translation adjustments Pension and other postretirement liability adjustments Total Accumulated other comprehensive loss Balance as of December 31, 2012 $ 7 $ 51 $ (176 ) $ (118 ) Other comprehensive income before reclassifications (14 ) (49 ) 151 88 Amounts reclassified from accumulated other comprehensive loss 4 — 2 6 Net current-period other comprehensive income (10 ) (49 ) 153 94 Balance as of December 31, 2013 (3 ) 2 (23 ) (24 ) Other comprehensive loss before reclassifications 254 (68 ) (212 ) (26 ) Amounts 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 330 (110 ) (213 ) 7 Balance as of December 31, 2014 327 (108 ) (236 ) (17 ) Other comprehensive loss before reclassifications 164 (214 ) (122 ) (172 ) Amounts 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 )

Fair Value (Notes)

Fair Value (Notes)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value	Fair Value The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. The three broad levels of inputs defined by the fair value hierarchy are as follows: • Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date; • Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and • Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data). Fair Value of Derivative Contracts The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the Codification (in millions). The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements. Balance sheet asset fair value measurements by level Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral held(b) Net amount As of December 31, 2015 Energy commodity derivative contracts(a) $ 48 $ 589 $ 2 $ 639 $ (12 ) $ (37 ) $ 590 Interest rate swap agreements $ — $ 385 $ — $ 385 $ (8 ) $ — $ 377 Cross-currency swap agreements $ — $ — $ — $ — $ — $ — $ — As of December 31, 2014 Energy commodity derivative contracts(a) $ 49 $ 533 $ 12 $ 594 $ (46 ) $ (13 ) $ 535 Interest rate swap agreements $ — $ 403 $ — $ 403 $ (44 ) $ — $ 359 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, 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 ) As of December 31, 2014 Energy commodity derivative contracts(a) $ (25 ) $ (11 ) $ (73 ) $ (109 ) $ 46 $ 47 $ (16 ) Interest rate swap agreements $ — $ (53 ) $ — $ (53 ) $ 44 $ — $ (9 ) _______ (a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and options. 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 “Other current assets” 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, 2015 2014 Derivatives-net asset (liability) Beginning of period $ (61 ) $ (110 ) Transfers out(a) — (88 ) Total gains or (losses) Included in earnings (13 ) 22 Included in other comprehensive loss — 78 Settlements 59 37 End of period $ (15 ) $ (61 ) 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 $ — $ 1 _______ (a) On December 31, 2014, we transferred WTI options from Level 3 to Level 2 due to increased observability of significant inputs in their valuations. As of December 31, 2015 , our Level 3 derivative assets and liabilities consisted primarily of power derivative contracts, 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. Fair Value of Financial Instruments The estimated fair value of our outstanding debt balances is disclosed below (in millions): December 31, 2015 December 31, 2014 Carrying value Estimated fair value Carrying value Estimated fair value Total debt $ 43,227 $ 37,481 $ 42,814 $ 43,761 We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2015 and 2014 .

Reportable Segments (Notes)

Reportable Segments (Notes)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Reportable Segments	Reportable Segments We divide our operations into the following reportable business segments. These segments and their principal sources of revenues are as follows: • 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, condensate, and bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals and (ii) the ownership and operation of our Jones Act tankers; • Products Pipelines—the ownership and operation of refined petroleum products and crude oil and condensate pipelines that deliver refined petroleum products (gasoline, diesel fuel and jet fuel), NGL, crude oil, condensate and bio-fuels to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities; • 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; and • Other—primarily other miscellaneous assets and liabilities including (i) our corporate headquarters in Houston, Texas; (ii) several physical natural gas contracts with power plants associated with legacy trading activities; and (iii) other miscellaneous assets and liabilities. We evaluate performance principally based on each segment’s EBDA (including amortization of excess cost of equity investments), which excludes general and administrative expenses, third-party debt costs and interest expense, unallocable interest income, and unallocable income tax expense. Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision makers organize their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and marketing strategies. We consider each period’s earnings before all non-cash DD&A expenses to be an important measure of business segment performance for our reporting segments. We account for intersegment sales at market prices, while we account for asset transfers at either market value or, in some instances, book value. During 2015, 2014 and 2013, 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, 2015 2014 2013 Revenues Natural Gas Pipelines Revenues from external customers $ 8,704 $ 10,153 $ 8,613 Intersegment revenues 21 15 4 CO 2 1,699 1,960 1,857 Terminals Revenues from external customers 1,878 1,717 1,408 Intersegment revenues 1 1 2 Products Pipelines Revenues from external customers 1,828 2,068 1,853 Intersegment revenues 3 — — Kinder Morgan Canada 260 291 302 Other (3 ) 1 1 Total segment revenues 14,391 16,206 14,040 Other revenues(a) 37 36 36 Less: Total intersegment revenues (25 ) (16 ) (6 ) Total consolidated revenues $ 14,403 $ 16,226 $ 14,070 Year Ended December 31, 2015 2014 2013 Operating expenses(b) Natural Gas Pipelines $ 4,738 $ 6,241 $ 5,235 CO 2 432 494 439 Terminals 836 746 657 Products Pipelines 772 1,258 1,295 Kinder Morgan Canada 87 106 110 Other 51 24 30 Total segment operating expenses 6,916 8,869 7,766 Less: Total intersegment operating expenses (25 ) (16 ) (6 ) Total consolidated operating expenses $ 6,891 $ 8,853 $ 7,760 Year Ended December 31, 2015 2014 2013 Other expense (income)(c) Natural Gas Pipelines $ 1,269 $ 5 $ (24 ) CO 2 606 243 — Terminals 190 29 (74 ) Products Pipelines 2 (3 ) 6 Kinder Morgan Canada (1 ) — — Other — 1 (7 ) Total consolidated other expense (income) $ 2,066 $ 275 $ (99 ) Year Ended December 31, 2015 2014 2013 DD&A Natural Gas Pipelines $ 1,046 $ 897 $ 797 CO 2 556 570 533 Terminals 433 337 247 Products Pipelines 206 166 155 Kinder Morgan Canada 46 51 54 Other 22 19 20 Total consolidated DD&A $ 2,309 $ 2,040 $ 1,806 Year Ended December 31, 2015 2014 2013 Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments Natural Gas Pipelines $ 285 $ 279 $ 200 CO 2 (5 ) 26 22 Terminals 17 18 22 Products Pipelines 36 37 40 Kinder Morgan Canada — — 4 Other — 1 — Total consolidated equity earnings $ 333 $ 361 $ 288 Year Ended December 31, 2015 2014 2013 Interest income Natural Gas Pipelines $ — $ 1 $ — Products Pipelines 2 2 2 Kinder Morgan Canada — — 3 Other 2 6 8 Total segment interest income 4 9 13 Unallocated interest income — — 2 Total consolidated interest income $ 4 $ 9 $ 15 Year Ended December 31, 2015 2014 2013 Other, net-income (expense) Natural Gas Pipelines $ 24 $ 24 $ 578 CO 2 — — — Terminals 8 12 1 Products Pipelines 4 (1 ) 1 Kinder Morgan Canada 8 15 246 Other (1 ) 30 9 Total consolidated other, net-income (expense) $ 43 $ 80 $ 835 Year Ended December 31, 2015 2014 2013 Income tax benefit (expense) Natural Gas Pipelines $ (4 ) $ (6 ) $ (9 ) CO 2 (1 ) (8 ) (7 ) Terminals (29 ) (29 ) (14 ) Products Pipelines (8 ) (2 ) 2 Kinder Morgan Canada (19 ) (18 ) (21 ) Total segment income tax expense (61 ) (63 ) (49 ) Unallocated income tax expense (503 ) (585 ) (693 ) Total consolidated income tax expense $ (564 ) $ (648 ) $ (742 ) Year Ended December 31, 2015 2014 2013 Segment EBDA(d) Natural Gas Pipelines $ 3,063 $ 4,259 $ 4,207 CO 2 657 1,240 1,435 Terminals 849 944 836 Products Pipelines 1,100 856 602 Kinder Morgan Canada 163 182 424 Other (53 ) 13 (5 ) Total segment EBDA 5,779 7,494 7,499 Total segment DD&A (2,309 ) (2,040 ) (1,806 ) Total segment amortization of excess cost of equity investments (51 ) (45 ) (39 ) Other revenues 37 36 36 General and administrative expenses (690 ) (610 ) (613 ) Interest expense, net of unallocable interest income(e) (2,055 ) (1,807 ) (1,688 ) Unallocable income tax expense (503 ) (585 ) (693 ) Loss from discontinued operations, net of tax — — (4 ) Total consolidated net income $ 208 $ 2,443 $ 2,692 Year Ended December 31, 2015 2014 2013 Capital expenditures Natural Gas Pipelines $ 1,642 $ 935 $ 1,085 CO 2 725 792 667 Terminals 847 1,049 1,108 Products Pipelines 524 680 416 Kinder Morgan Canada 142 156 77 Other 16 5 16 Total consolidated capital expenditures $ 3,896 $ 3,617 $ 3,369 2015 2014 Investments at December 31 Natural Gas Pipelines $ 5,080 $ 5,174 CO 2 — 17 Terminals 306 219 Products Pipelines 641 624 Kinder Morgan Canada 10 1 Other 3 1 Total consolidated investments $ 6,040 $ 6,036 2015 2014 Assets at December 31 Natural Gas Pipelines $ 53,704 $ 52,532 CO 2 4,706 5,227 Terminals 9,083 8,850 Products Pipelines 8,464 7,179 Kinder Morgan Canada 1,434 1,593 Other 418 455 Total segment assets 77,809 75,836 Corporate assets(f) 6,276 7,157 Assets held for sale 19 56 Total consolidated assets $ 84,104 $ 83,049 _______ (a) Includes a management fee for services we perform for NGPL. (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 (gain) on impairments and disposals of long-lived assets, net and other expense (income), net. (d) Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income), net, loss on impairment of goodwill, and losses (gain) on impairments and disposals of long-lived assets, net and equity investments. (e) Includes (i) interest expense and (ii) miscellaneous other income and expenses not allocated to business segments. (f) Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, prepaid assets and deferred charges, risk management assets related to debt fair value adjustments and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual 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, 2015 2014 2013 Revenues from external customers U.S. $ 13,797 $ 15,605 $ 13,656 Canada 479 437 398 Mexico 127 184 16 Total consolidated revenues from external customers $ 14,403 $ 16,226 $ 14,070 December 31, 2015 2014 Long-term assets, excluding goodwill and other intangibles U.S. $ 51,679 $ 49,992 Canada 2,193 2,268 Mexico 67 81 Total consolidated long-lived assets $ 53,939 $ 52,341

Litigation, Environmental and O

Litigation, Environmental and Other Contingencies (Notes)	12 Months Ended
	Dec. 31, 2015
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 are successful in proving these claims or other of their claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing 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. 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 $160 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 several recent FERC decisions in SFPP cases, as applicable, to pending 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. 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. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528) on October 17, 2013. EPNG sought rehearing on certain issues in Opinion 528. As required by Opinion 528, EPNG filed revised pro forma recalculated rates consistent with the terms of Opinion 528. The FERC also required an Administrative Law Judge (ALJ) to conduct an additional hearing concerning one of the issues in Opinion 528. On September 17, 2014, the ALJ issued an initial decision finding certain shippers qualify for lower rates under a prior settlement. EPNG has sought FERC review of the ALJ decision. EPNG believes it has an appropriate reserve, which is classified as a current liability, related to the findings in Opinions 517-A and 528 for both rate cases. 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 liability, 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. 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 arises from the sale by TGP of the Cameron System in Louisiana to Kinetica Partners, LLC on September 1, 2013. Plains alleges 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 alleges 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 and disputed its indemnity obligation. We intend to vigorously defend the suit and pursue Kinetica, if necessary, for indemnity and costs of defense. 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 will file an appeal to the Delaware Supreme Court and execution on the judgment has been stayed until the appeal is decided. At the present time, we do not believe that an ultimate award, if any, will have a material financial impact on our Company. We continue to believe the transactions at issue were appropriate and in the best interests of EPB and we intend to continue to defend the 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 were 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. Although damages in excess of $140 million have been alleged in total against all defendants in one of the remaining lawsuits where a damage number is provided, there remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, that may be allocated to us. Therefore, our costs and legal exposure related to the remaining outstanding lawsuits and claims 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 the Merger Transactions, which the Court consolidated under the caption In re Kinder Morgan, Inc. Corporate Reorganization Litigation (Consolidated Case No. 10093-VCL). The plaintiffs originally sought to enjoin one or more of the proposed Merger Transactions, which relief the Court denied on November 5, 2014. On December 12, 2014, the plaintiffs filed a Verified Second Consolidated Amended Class Action Complaint, which purports 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 allege 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 seeks 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). The plaintiffs are only appealing the dismissal of claims brought against defendants KMGP, Ted A. Gardner, Gary L. Hultquist, and Perry M. Waughtal and not those asserted against KMI, P. Merger Sub LLC, Richard D. Kinder, Steven J. Kean, KMP and KMR. The Supreme Court will hear oral argument on March 9, 2016. The defendants believe the allegations against them lack merit, and they intend to vigorously defend the lawsuit. Kinder Morgan Energy Partners, L.P. Capex Litigation Putative class action and derivative complaints were filed in the Court of Chancery in the State of Delaware against defendants KMI, KMGP and nominal defendant KMEP on February 5, 2014 and March 27, 2014 captioned Slotoroff v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al (Case No. 9318) and Burns et al v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al (Case No. 9479) respectively. The cases were consolidated on April 8, 2014 (Consolidated Case No. 9318). The consolidated suit asserted claims both individually and on behalf of a putative class consisting of all public holders of KMEP units during the period of February 5, 2011 through the date of the filing of the complaints. The suit alleged direct and derivative causes of action for breach of the partnership agreement, breach of the duty of good faith and fair dealing, aiding and abetting, and tortious interference. Among other things, the suit alleged that defendants made a bad faith allocation of capital expenditures to expansion capital expenditures rather than maintenance capital expenditures for the alleged purpose of “artificially” inflating KMEP’s distributions and growth rate. The suit alleged that hundreds of millions of dollars were distributed improperly and sought disgorgement of any distributions to KMGP, KMI and any related entities, beyond amounts that would have been distributed in accordance with a “good faith” allocation of maintenance capital expenses, together with other unspecified monetary damages including punitive damages and attorney fees. On August 14, 2015, the parties entered into a Stipulation and Agreement of Settlement pursuant to which defendants paid $27.5 million (the “Settlement Fund”) to a class of former holders of KMEP common units, and all claims asserted in the consolidated suit are released. Following notice to the putative class members, on December 22, 2015, the Court approved the settlement which also includes a release of all claims asserted in the Walker litigation discussed below, and awarded attorneys’ fees and litigation expenses to Plaintiffs’ counsel to be paid from the Settlement Fund. All of the defendants believe they acted properly, in good faith, and in a manner consistent with any and all legal, contractual and equitable duties and obligations, including those contained in the Limited Partnership Agreement. We entered into this settlement solely to avoid the substantial burden, expense, inconvenience and distraction of continued litigation and to resolve each of the released claims. Walker v. Kinder Morgan, Inc., Kinder Morgan G.P., Inc. et al. On March 6, 2014, a putative class action and derivative complaint was filed in the District Court of Harris County, Texas (Case No. 2014-11872 in the 215th Judicial District) against KMI, KMGP, KMR, Richard D. Kinder, Steven J. Kean, Ted A. Gardner, Gary L. Hultquist, Perry M. Waughtal and nominal defendant KMEP. The suit was filed by Kenneth Walker, a purported unit holder of KMEP, and alleged derivative causes of action for alleged violation of duties owed under the partnership agreement, breach of the implied covenant of good faith and fair dealing, “abuse of control” and “gross mismanagement” in connection with the calculation of distributions and allocation of capital expenditures to expansion capital expenditures and maintenance capital expenditures. The suit sought unspecified money damages, interest, punitive damages, attorney and expert fees, costs and expenses, unspecified equitable relief, and demanded a trial by jury. On January 5, 2016, Plaintiffs filed a Notice of Nonsuit, with prejudice, which the Court subsequently granted, dismissing all claims in the action with prejudice. 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, 2015 and 2014 , our total reserve for legal matters was $463 million and $400 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. The overall increase in the reserve from December 31, 2014 is related to certain legal developments during the year ended December 31, 2015 on 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 law 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. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. We do not believe that these alleged violations will have a material adverse effect on our business, financial position, results of operations or dividends to our shareholders. 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. Once the EPA determines the cleanup remedy from the remedial investigations and feasibility studies conducted during the last decade at the site, it will issue a Record of Decision (ROD). Currently, 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. We expect the RI/FS process to conclude in 2016. We expect EPA will publish a Proposed Remedial Action Plan by April 2016 leading to a final ROD targeted for late 2016 or early 2017. The allocation process will follow the issuance of the ROD with an expected completion date of 2018. We anticipate that the cleanup activities will begin within two years after the ROD is issued. 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 against 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. 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 is 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 January 25, 2016, the District Court heard oral argument on motions we previously filed to exclude certain expert testimony offered by the City and for partial summary judgment on the City’s claims. By its Order dated February 2, 2016, the Court granted in part and denied in part our motion to exclude certain expert testimony, granted in part and denied in part our motion for partial summary judgment, found that the City is limited to seeking alleged damages relating to the three year period immediately preceding the filing of the lawsuit, found that the City lacks expert opinions or testimony to support its claim for water damages, including the alleged loss of use of the Mission Valley aquifer as a source of both supply and storage of potable water, and denied our motion for partial summary judgment on the City’s alleged real estate and restoration damages. As a result of the Court’s Order, the City’s alleged damages will be reduced from approximately $365 million to approximately $160 million . Trial is scheduled to begin April 5, 2016. We intend to continue to vigorously defend the case. This site remains under the regulatory oversight and order of the California Regional Water Quality Control Board (RWQCB). SFPP has 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. SFPP expects the RWQCB to issue a notice of no further action with respect to the stadium property site. SFPP’s remediation effort is now focused on its adjacent Mission Valley Terminal site. Uranium Mines in Vicinity of Cameron, Arizona In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately twenty uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EP

Recent Accounting Pronoucements

Recent Accounting Pronoucements (Notes)	12 Months Ended
	Dec. 31, 2015
Accounting Changes and Error Corrections [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Recent Accounting Pronouncements Accounting Standards Updates ASU No. 2014-09 On May 28, 2014, the FASB issued ASU No. 2014-09, “ Revenue from Contracts with Customers (Topic 606).” This ASU is designed to create greater comparability for financial statement users across industries and jurisdictions. The provisions of ASU No. 2014-09 include a five-step process by which entities will recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which an entity expects to be entitled in exchange for those goods or services. The standard also will require enhanced disclosures, provide more comprehensive guidance for transactions such as service revenue and contract modifications, and enhance guidance for multiple-element arrangements. ASU No. 2014-09 will be effective for us January 1, 2018. Early adoption is permitted for the interim periods within the adoption year. We are currently reviewing the effect of ASU No. 2014-09 on our revenue recognition and assessing the timing of our adoption. 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. ASU No. 2015-02 was effective January 1, 2016. We do not expect the effect of ASU No. 2015-02 to have a material impact on 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 will be effective for us January 1, 2017. We are currently reviewing the effect of ASU No. 2015-11.

Guarantee of Securities of Subs

Guarantee of Securities of Subsidiaries (Notes)	12 Months Ended
	Dec. 31, 2015
Guarantee of Securities of Subsidiaries [Abstract]
Guarantees [Text Block]	Guarantee of Securities of Subsidiaries KMI, along with its direct and indirect subsidiaries KMP, and Copano, are issuers of certain public debt securities. After the completion of the Merger Transactions, KMI, KMP, Copano and substantially all of KMI’s wholly owned domestic subsidiaries, entered into 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 issuers 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, KMP, or Copano are in the same position with respect to the net assets, income and cash flows of KMI and the Subsidiary Issuers 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 each 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 issuers in separate columns in this single set of condensed consolidating financial statements. Excluding fair value adjustments, as of December 31, 2015, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, Subsidiary Issuer and Guarantor-Copano, and Subsidiary Guarantors had $13,346 million , $19,985 million , $332 million , and $6,882 million of Guaranteed Notes outstanding, respectively. Included in the Subsidiary Guarantors debt balance as presented in the accompanying December 31, 2015 condensed consolidating balance sheets are approximately $177 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 Issuer and Guarantor-Copano, 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 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. Effective December 31, 2015, Kinder Morgan (Delaware), Inc. and Kinder Morgan Services LLC merged into KMI. As a result of such merger, both entities are no longer Subsidiary Guarantors, and for all periods presented, financial statement balances and activities for Kinder Morgan (Delaware), Inc. and Kinder Morgan Services LLC are reflected within the Parent Issuer and Guarantor column. On January 1, 2015, EPB and its subsidiary, EPPOC merged with and into KMP with KMP surviving the merger. As a result of such merger, all of the wholly owned subsidiaries of EPB became wholly owned subsidiaries of KMP and effective January 1, 2015, EPB is no longer a Subsidiary Issuer and Guarantor. The condensed consolidating financial information reflects this transaction for all periods presented below.

Summary of Significant Accoun28

Summary of Significant Accounting Policies Accounting Policy (Policies)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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.
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 soley 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.
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.
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.
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 0.9% 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.
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 these assets at the lower of weighted-average cost or market. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.
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, 2015 and 2014 primarily consist of amounts due from customers. 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.
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, except where 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. In addition, we believe that 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 cash of $60 million and $118 million as of December 31, 2015 and 2014 , respectively, is included in “Other current assets.”
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, 2015 and 2014 , our gas imbalance receivables—including both trade and related party receivables—totaled $21 million and $103 million , respectively, and we included these amounts within “Other current assets” on our accompanying consolidated balance sheets. As of December 31, 2015 and 2014 , our gas imbalance payables—consisting of only trade payables—totaled $17 million and $36 million , respectively, and we included these amounts within “Other current liabilities” on our accompanying consolidated balance sheets.
Equity Method Investments, 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. For the purpose of impairment testing, adjustments for the inclusion of risk-adjusted probable reserves, as well as forward curve pricing and estimates of future costs, will cause impairment calculation cash flows to differ from the amounts presented in our supplemental information on oil and gas producing activities disclosed in “Supplemental Information on Oil and Gas Producing Activities (Unaudited).” 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—by 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.
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 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 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. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit we do not expect to be realized.
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.”
Comprehensive Income, Policy [Policy Text Block]	Comprehensive Income For each of the years ended December 31, 2015 , 2014 and 2013 , the difference between our net income and our comprehensive income resulted from (i) unrealized gains or losses on derivative contracts accounted for as cash flow hedges; (ii) foreign currency translation adjustments; and (iii) unrealized gains or losses related to changes in pension and other postretirement benefit plan liabilities. For more information on our risk management activities, see Note 14.
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. 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. As of December 31, 2015 , the recovery period for these regulatory assets was approximately one year to forty-one years . The following table summarizes our regulatory asset and liability balances as of December 31, 2015 and 2014 (in millions): December 31, 2015 2014 Current regulatory assets $ 55 $ 81 Non-current regulatory assets 378 406 Total regulatory assets $ 433 $ 487 Current regulatory liabilities $ 161 $ 189 Non-current regulatory liabilities 166 290 Total regulatory liabilities $ 327 $ 479
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, 2015
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, 2015
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, 2015 and 2014 (in millions): December 31, 2015 2014 Current regulatory assets $ 55 $ 81 Non-current regulatory assets 378 406 Total regulatory assets $ 433 $ 487 Current regulatory liabilities $ 161 $ 189 Non-current regulatory liabilities 166 290 Total regulatory liabilities $ 327 $ 479
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, 2015 2014 2013 Class P $ 214 $ 1,015 $ 1,187 Participating securities: Restricted stock awards(a) 13 11 6 Net Income Available to Common Stockholders $ 227 $ 1,026 $ 1,193 Year Ended December 31, 2015 2014 2013 Basic Weighted Average Common Shares Outstanding 2,187 1,137 1,036 Effect of dilutive securities: Warrants(b) 6 — — Diluted Weighted Average Common Shares Outstanding 2,193 1,137 1,036 ________ (a) As of December 31, 2015 , there were approximately 8 million such restricted stock awards. (b) 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. T
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	following 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, 2015 2014 2013 Unvested restricted stock awards 7 7 4 Warrants to purchase our Class P shares 291 312 401 Convertible trust preferred securities 8 10 10 Mandatory convertible preferred stock 10 n/a n/a _______ n/a - not applicable

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	The following table discloses our assignment of the purchase price for each of our significant acquisitions (in millions): Assignment of Purchase Price Ref. Date Acquisition Purchase price Current assets Property plant & equipment Deferred charges & other Goodwill Long-term debt Other liabilities Non-controlling interest Previously held equity interest (1) 2/15 Vopak Terminal Assets $ 158 $ 2 $ 155 $ — $ 7 $ — $ (6 ) $ — $ — (2) 2/15 Hiland 1,709 79 1,497 1,498 310 (1,411 ) (264 ) — — (3) 11/14 Pennsylvania and Florida Jones Act Tankers 270 — 270 8 25 — (33 ) — — (4) 1/14 American Petroleum Tankers and State Class Tankers 961 6 951 6 64 — (66 ) — — (5) 6/13 Goldsmith-Landreth Field Unit 280 — 298 — — — (18 ) — — (6) 5/13 Copano 3,733 218 2,788 1,973 963 (1,252 ) (236 ) (17 ) (704 )

Impairments (Tables)

Impairments (Tables)	12 Months Ended
	Dec. 31, 2015
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 disposals of assets (in millions): Year Ended December 31, 2015 2014 2013 Natural Gas Pipelines Impairment of goodwill $ 1,150 $ — $ — Impairments of long-lived assets(a) 79 — — Losses (gains) on disposals of long-lived assets 43 5 (28 ) Impairment of equity investments(b) 26 — 65 CO 2 Impairments of long-lived assets(c) 606 243 — Impairment at equity investee(d) 26 — — Terminals Impairments of long-lived assets(e) 188 — — Losses (gains) on disposals of long-lived assets 3 29 (73 ) Impairment of equity investments(e) 4 — — Other (gains) losses on disposals of long-lived assets — (3 ) 3 Total losses (gains) on impairments and disposals $ 2,125 $ 274 $ (33 ) _______ (a) Represents $47 million and $32 million of project write-offs in our non-regulated midstream and regulated natural gas pipelines assets, respectively. (b) 2015 amount is primarily related to an investment in a gathering and processing asset in Oklahoma and the 2013 amount is related to an investment in our regulated natural gas pipelines. (c) 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. (d) 2015 amount is a loss on impairment recorded by an investee and included in “Earnings from equity investments” in our accompanying consolidated statement of income. (e) 2015 amount is primarily related to certain terminals with significant coal operations

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Schedule of Income before Income Tax, Domestic and Foreign [Table Text Block]	The components of “Income from Continuing Operations Before Income Taxes” are as follows (in millions): Year Ended December 31, 2015 2014 2013 U.S. $ 611 $ 2,941 $ 3,107 Foreign 161 150 331 Total Income from Continuing Operations Before Income Taxes $ 772 $ 3,091 $ 3,438
Schedule of Components of Income Tax Expense (Benefit)	Components of the income tax provision applicable to continuing operations for federal, foreign and state taxes are as follows (in millions): Year Ended December 31, 2015 2014 2013 Current tax expense (benefit) Federal $ (125 ) $ (16 ) $ 57 State (7 ) 36 36 Foreign 4 13 9 Total (128 ) 33 102 Deferred tax expense (benefit) Federal 653 572 612 State (4 ) 14 — Foreign 43 29 28 Total 692 615 640 Total tax provision $ 564 $ 648 $ 742
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, 2015 2014 2013 Federal income tax $ 271 35.0 % $ 1,082 35.0 % $ 1,203 35.0 % Increase (decrease) as a result of: State deferred tax rate change (24 ) (3.1 )% — — % (21 ) (0.6 )% Taxes on foreign earnings 26 3.5 % 40 1.3 % 112 3.3 % Net effects of consolidating KMP and EPB and other noncontrolling interests 15 2.0 % (433 ) (14.0 )% (488 ) (14.2 )% State income tax, net of federal benefit 12 1.5 % 37 1.2 % 45 1.3 % Dividend received deduction (51 ) (6.6 )% (50 ) (1.6 )% (54 ) (1.6 )% Adjustments to uncertain tax positions (14 ) (1.9 )% (5 ) (0.2 )% (87 ) (2.5 )% Valuation allowance on investment in NGPL — — % 61 2.0 % — — % Disposition of certain international holdings — — % (112 ) (3.6 )% — — % Nondeductible goodwill impairment 323 41.7 % — — % — — % Other 6 0.8 % 28 0.9 % 32 0.9 % Total $ 564 72.9 % $ 648 21.0 % $ 742 21.6 %
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Deferred tax assets and liabilities result from the following (in millions): December 31, 2015 2014 Deferred tax assets Employee benefits $ 394 $ 329 Accrued expenses 129 123 Net operating loss, capital loss, tax credit carryforwards 1,344 778 Derivative instruments and interest rate and currency swaps 45 43 Debt fair value adjustment 110 102 Investments 3,607 4,858 Other 3 31 Valuation allowances (152 ) (154 ) Total deferred tax assets 5,480 6,110 Deferred tax liabilities Property, plant and equipment 143 373 Other 14 30 Total deferred tax liabilities 157 403 Net deferred tax assets $ 5,323 $ 5,707 Current deferred tax asset $ — $ 56 Non-current deferred tax assets 5,323 5,651 Net deferred tax assets $ 5,323 $ 5,707
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, 2015 2014 2013 Balance at beginning of period $ 189 $ 209 $ 269 Uncertain tax positions of EP — — 4 Subtotal 189 209 273 Additions based on current year tax positions 4 12 11 Additions based on prior year tax positions — — 26 Reductions based on prior year tax positions (6 ) (3 ) — Reductions based on settlements with taxing authority (25 ) (24 ) (86 ) Reductions due to lapse in statute of limitations (14 ) (5 ) (15 ) Balance at end of period $ 148 $ 189 $ 209

Property, Plant and Equipment34

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	As of December 31, 2015 and 2014 , our property, plant and equipment, net consisted of the following (in millions): December 31, 2015 2014 Pipelines (Natural gas, liquids, crude oil and CO 2 ) $ 19,855 $ 18,119 Equipment (Natural gas, liquids, crude oil, CO 2 , and terminals) 22,979 21,233 Other(a) 4,719 4,484 Accumulated depreciation, depletion and amortization (10,851 ) (8,369 ) 36,702 35,467 Land and land rights-of-way 1,450 1,324 Construction work in process 2,395 1,773 Property, plant and equipment, net $ 40,547 $ 38,564

Investments Investments (Tables

Investments Investments (Tables)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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, 2015 2014 2013 Citrus Corporation $ 96 $ 97 $ 84 FEP 55 55 55 Gulf LNG Holdings Group, LLC 49 48 47 MEP 45 45 40 Red Cedar Gathering Company 26 33 31 EagleHawk 24 (7 ) 9 Plantation Pipe Line Company 29 29 35 Ruby Pipeline Holding Company, L.L.C. 18 15 (6 ) Watco Companies, LLC 16 13 13 Sierrita Gas Pipeline LLC 9 3 — Parkway Pipeline LLC 5 8 1 Double Eagle Pipeline LLC(a) 3 (1 ) 1 Cortez Pipeline Company(b) (3 ) 25 24 Fort Union Gas Gathering L.L.C.(a)(c) (4 ) 16 11 NGPL Holdco LLC(d) — — (66 ) All others 16 27 48 Total $ 384 $ 406 $ 327 Amortization of excess costs $ (51 ) $ (45 ) $ (39 ) _______ (a) 2013 amounts are for the period from May 1, 2013 through December 31, 2013. (b) 2015 amount includes $26 million representing our share of a non-cash impairment charge (pre-tax) recorded by Cortez Pipeline Company. (c) 2015 amount includes a non-cash impairment charge of $20 million (pre-tax) related to our investment. (d) 2013 amount includes non-cash impairment charges of $65 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, 2015 and 2014 , our investments consisted of the following (in millions): December 31, 2015 2014 Citrus Corporation $ 1,719 $ 1,805 Ruby Pipeline Holding Company, L.L.C. 1,093 1,123 MEP 713 748 Gulf LNG Holdings Group, LLC 516 547 EagleHawk 348 337 Plantation Pipe Line Company 327 303 Watco Companies, LLC 201 103 Red Cedar Gathering Company 185 184 Double Eagle Pipeline LLC 158 150 Kinder Morgan NGPL Holdings LLC 153 — Parkway Pipeline LLC 131 144 FEP 116 130 Fort Union Gas Gathering L.L.C. 50 70 Sierrita Gas Pipeline LLC 60 63 Cortez Pipeline Company — 17 All others 262 304 Total equity investments 6,032 6,028 Bond investments 8 8 Total investments $ 6,040 $ 6,036
Summarized financial info of significant equity investment [Table Text Block]		Summarized combined financial information for our significant equity investments (listed or described above) is reported below (in millions; amounts represent 100% of investee financial information): Year Ended December 31, Income Statement 2015 2014 2013 Revenues $ 3,857 $ 3,829 $ 3,615 Costs and expenses 3,408 3,063 2,803 Net income (loss) $ 449 $ 766 $ 812 December 31, Balance Sheet 2015 2014 Current assets $ 811 $ 943 Non-current assets 19,745 20,630 Current liabilities 1,009 1,643 Non-current liabilities 11,227 10,841 Partners’/owners’ equity 8,320 9,089

Goodwill Goodwill (Tables)

Goodwill Goodwill (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 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 $ 5,637 $ 1,528 $ 1,908 $ 221 $ 1,486 $ 610 $ 28,917 Accumulated impairment losses (1,643 ) (447 ) — (1,197 ) (70 ) (679 ) (377 ) (4,413 ) December 31, 2013 15,884 5,190 1,528 711 151 807 233 24,504 Acquisitions(a) — 82 — — — 89 — 171 Currency translation — — — — — — (19 ) (19 ) Divestiture — — — — — (2 ) — (2 ) December 31, 2014 15,884 5,272 1,528 711 151 894 214 24,654 Acquisitions(b) — 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 _______ (a) 2014 includes $82 million related to the May 2013 Copano acquisition in Natural Gas Pipelines Non-Regulated and $89 million related to Terminals’ acquisitions of APT tankers in January 2014 and Crowley tankers in November 2014, as discussed in Note 3. (b) 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.
Goodwill allocation [Table Text Block]	Below is a hypothetical allocation of the fair value to the assets and liabilities of this reporting unit, including goodwill. The amount of implied goodwill is then compared to the carrying value of goodwill to determine the amount of impairment (in millions). Allocation of Fair Value: Working capital, net $ 232 Property, plant and equipment 9,627 Other intangible assets 3,121 Other liabilities, net (7 ) Goodwill 4,215 Estimated Reporting Unit Fair Value $ 17,188 Prior carrying amount of goodwill $ 5,365 Goodwill impairment $ 1,150

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Instrument [Line Items]
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. In 2015, we adopted Accounting Standards Updates (ASU) 2015-03, “ Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ” and ASU 2015-15, “ Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements—Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update). ” These ASUs are designed to simplify presentation of debt issuance costs. The standards require that debt issuance costs related to a recognized debt liability, except for line-of-credit debt issuance costs, be presented in the balance sheet as an offset to the carrying amount of that debt liability, consistent with debt discounts. The application of this new accounting guidance resulted in the reclassification of $149 million of debt issuance costs from “Deferred charges and other assets” to “Debt fair value adjustments” in our accompanying consolidated balance sheet as of December 31, 2014 . 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 and premiums (in millions): December 31, 2015 2014 KMI Senior notes 1.50% through 8.25%, due 2015 through 2098(a)(b)(c) $ 13,346 $ 11,438 Credit facility due November 26, 2019(d)(e) — 850 Commercial paper borrowings(d)(e) — 386 KMP Senior notes, 2.65% through 9.00%, due 2015 through 2044(b)(f) 19,985 20,660 TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(b)(h) 1,790 1,790 EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(b) 1,115 1,115 Copano senior notes, 7.125%, due April 1, 2021(b) 332 332 CIG senior notes, 5.95% through 6.85%, due 2015 through 2037(b) 100 475 SNG notes, 4.40% through 8.00%, due 2017 through 2032(b)(g) 1,211 1,211 Other Subsidiary Borrowings (as obligor) Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(b)(h) 1,636 1,636 Hiland Partners Holdings LLC, senior notes, 5.50% and 7.25%, due 2020 and 2022(b)(i) 974 — EPC Building, LLC, promissory note, 3.967%, due 2015 through 2035 443 453 Preferred securities, 4.75%, due March 31, 2028(j) 221 280 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(k) 100 100 Other miscellaneous debt(l) 300 303 Total debt – KMI and Subsidiaries 41,553 41,029 Less: Current portion of debt(m) 821 2,717 Total long-term debt – KMI and Subsidiaries(n) $ 40,732 $ 38,312 _______ (a) December 31, 2015 amount includes senior notes that are denominated in Euros and have been converted and are reported at the December 31, 2015 exchange rate of 1.0862 U.S. dollars per Euro. From the issuance date of these senior notes in March 2015 through December 31, 2015 , our debt increased by less than $1 million as a result of the change in the exchange rate of 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) Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. (c) Includes $6.0 billion of senior notes issued on November 26, 2014 as a result of the Merger Transactions (see “—Long-term Debt Issuances and Repayments” below). (d) As of December 31, 2014 , the weighted average interest rate on our credit facility borrowings, including commercial paper borrowings, was 1.54% . (e) On November 26, 2014, we entered into a $4 billion replacement credit facility and a commercial paper program of up to $4 billion of unsecured notes (see “—Credit Facilities and Restrictive Covenants” below). (f) On January 1, 2015, EPB and EPPOC merged with and into KMP. On that date, KMP succeeded EPPOC as the issuer of approximately $2.9 billion of EPPOC’s senior notes, which were guaranteed by EPB, and EPB and EPPOC ceased to be obligors for those senior notes. (g) Southern Natural Issuing Corporation is a wholly owned finance subsidiary of SNG and is the co-issuer of certain of SNG’s outstanding debt securities. (h) In January and February 2016, we refinanced $850 million of maturing Kinder Morgan Finance Company LLC senior notes and $150 million of maturing TGP senior notes using proceeds from a new three -year term loan facility (see “— Subsequent Event—Debt Issuances and Repayments” below). (i) Represents the remaining principal amount outstanding of senior notes assumed in the Hiland acquisition. (j) Capital Trust I (Trust I), is a 100% -owned business trust that as of December 31, 2015 , 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, 2015 , the outstanding balance of $221 million (of which $111 million is classified as current) was bifurcated between debt ( $197 million ) and equity ( $24 million ). During the years ended December 31, 2015 and 2014 , 1,176,015 and 3,923 Trust I Preferred Securities had been converted into (i) 846,369 and 2,820 shares of our Class P common stock; (ii) approximately $30 million and $99,000 in cash; and (iii) 1,293,615 and 4,315 in warrants, respectively. (k) As of December 31, 2015 and 2014, 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. (l) 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, 2015 , the principal amounts of the Totem and High Plains financing obligations were $72 million and $96 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. (m) Amounts include outstanding credit facility and commercial paper borrowings and other debt maturing within 12 months. See “ — Maturities of Debt” below. (n) Excludes our “Debt fair value adjustments” which, as of December 31, 2015 and December 31, 2014 , increased our combined debt balances by $1,674 million and $1,785 million , respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs (resulting from the implementation of ASU No. 2015-03 and 2015-15) 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 Note 15 “Fair Value— Debt Fair Value Adjustments. ” We and substantially all of our 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 September 19, 2014, we entered into a new five -year $4.0 billion revolving credit agreement with a syndicate of lenders, which can be increased to $5.0 billion if certain conditions are met (see “—Subsequent Event—Credit Facility Capacity” following). The new revolving credit agreement was effective upon the closing of the Merger Transactions on November 26, 2014 and replaced the prior KMI credit agreement, the KMP credit agreement and the EPB credit agreement. On November 26, 2014, we entered into 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, 2015 , we were in compliance with all required financial covenants. Our credit facility included the following restrictive covenants as of December 31, 2015 : • 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, 2015 , we had no borrowings outstanding under our five -year $4.0 billion revolving credit facility, no borrowings outstanding under our $4.0 billion commercial paper program and $115 million in letters of credit. Our availability under this facility as of December 31, 2015 was $3,885 million . On February 13, 2015, in connection with the Hiland acquisition, we entered into and made borrowings of $1,641 million under a new six -month bridge credit facility with UBS AG, Stamford Branch. Interest under this bridge credit facility was charged at the same rate as our $4.0 billion revolving credit facility. Prior to March 31, 2015, we repaid outstanding borrowings and the facility was terminated on April 6, 2015. Subsequent Event—Credit Facility Capacity On January 26, 2016, in accordance with the terms of our revolving credit agreement, we increased the capacity of our revolving credit agreement from $4.0 billion to $5.0 billion . The terms of the revolving credit agreement remain the same. Hiland Debt Acquired 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. Long-term Debt Issuances and Repayments Apart from the assumption of the Hiland debt discussed above, following are significant long-term debt issuances and repayments made during 2015 and 2014 : 2015 2014 Issuances $800 million 5.05% notes due 2046 $650 million senior term loan facility due 2017 $815 million 1.50% notes due 2022(a) $500 million 2.00% notes due 2017(b) $543 million 2.25% notes due 2027(a) $1,500 million 3.05% notes due 2019(b) $1,500 million 4.30% notes due 2025(b) $750 million 5.30% notes due 2034(b) $1,750 million 5.55% notes due 2045(b) $750 million 3.50% notes due 2021 $750 million 5.50% notes due 2044 $650 million 4.25% notes due 2024 $550 million 5.40% notes due 2044 $600 million 4.30% notes due 2024 Repayments $300 million 5.625% notes due 2015 $500 million 5.125% notes due 2014 $250 million 5.15% notes due 2015 $1,528 million senior term loan facility due 2015 $340 million 6.80% notes due 2015 $650 million senior term loan facility due 2017(b) $375 million 4.10% notes due 2015 $207 million 6.875% notes due 2014 ________ (a) Senior notes are denominated in Euros and are presented above in U.S. dollars at the exchange rate on the issuance date of 1.0860 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) Debt issued or repaid associated with the Merger Transactions. Subsequent Event—Debt Issuances and Repayments In January 2016, we entered into a $1.0 billion three -year unsecured term loan facility due in 2019 at 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 at December 31, 2015. Maturities of Debt The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2015 , are summarized as follows (in millions): Year Total 2016(a) $ 821 2017 3,060 2018 2,329 2019(a) 3,819 2020 2,953 Thereafter 28,571 Total $ 41,553 ________ (a) 2016 amount primarily includes $667 million of current maturities on senior notes and $111 million associated with our Trust I Preferred Securities that are classified as current obligations because these securities have rights to convert into consideration consistent with the EP merger, and excludes $1,000 million of current maturities on long-term debt that were refinanced with proceeds from the issuance of a January 2016 three -year term loan which is reflected in 2019. 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, 2015 , the weighted-average amortization period of the unamortized premium from the termination of the 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 2015 2014 Purchase accounting debt fair value adjustments $ 1,135 $ 1,221 Carrying value adjustment to hedged debt 380 347 Unamortized portion of proceeds received from the early termination of interest rate swap agreements 397 454 Unamortized debt discount/premiums (86 ) (88 ) Unamortized debt issuance costs (152 ) (149 ) Total debt fair value adjustments $ 1,674 $ 1,785 Interest Rates, Interest Rate Swaps and Contingent Debt The weighted average interest rate on all of our borrowings was 4.92% during 2015 and 5.02% during 2014 . 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 ”).
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 2015 2014 Purchase accounting debt fair value adjustments $ 1,135 $ 1,221 Carrying value adjustment to hedged debt 380 347 Unamortized portion of proceeds received from the early termination of interest rate swap agreements 397 454 Unamortized debt discount/premiums (86 ) (88 ) Unamortized debt issuance costs (152 ) (149 ) Total debt fair value adjustments $ 1,674 $ 1,785
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 and premiums (in millions): December 31, 2015 2014 KMI Senior notes 1.50% through 8.25%, due 2015 through 2098(a)(b)(c) $ 13,346 $ 11,438 Credit facility due November 26, 2019(d)(e) — 850 Commercial paper borrowings(d)(e) — 386 KMP Senior notes, 2.65% through 9.00%, due 2015 through 2044(b)(f) 19,985 20,660 TGP senior notes, 7.00% through 8.375%, due 2016 through 2037(b)(h) 1,790 1,790 EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(b) 1,115 1,115 Copano senior notes, 7.125%, due April 1, 2021(b) 332 332 CIG senior notes, 5.95% through 6.85%, due 2015 through 2037(b) 100 475 SNG notes, 4.40% through 8.00%, due 2017 through 2032(b)(g) 1,211 1,211 Other Subsidiary Borrowings (as obligor) Kinder Morgan Finance Company, LLC, senior notes, 5.70% through 6.40%, due 2016 through 2036(b)(h) 1,636 1,636 Hiland Partners Holdings LLC, senior notes, 5.50% and 7.25%, due 2020 and 2022(b)(i) 974 — EPC Building, LLC, promissory note, 3.967%, due 2015 through 2035 443 453 Preferred securities, 4.75%, due March 31, 2028(j) 221 280 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock(k) 100 100 Other miscellaneous debt(l) 300 303 Total debt – KMI and Subsidiaries 41,553 41,029 Less: Current portion of debt(m) 821 2,717 Total long-term debt – KMI and Subsidiaries(n) $ 40,732 $ 38,312 _______ (a) December 31, 2015 amount includes senior notes that are denominated in Euros and have been converted and are reported at the December 31, 2015 exchange rate of 1.0862 U.S. dollars per Euro. From the issuance date of these senior notes in March 2015 through December 31, 2015 , our debt increased by less than $1 million as a result of the change in the exchange rate of 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) Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. (c) Includes $6.0 billion of senior notes issued on November 26, 2014 as a result of the Merger Transactions (see “—Long-term Debt Issuances and Repayments” below). (d) As of December 31, 2014 , the weighted average interest rate on our credit facility borrowings, including commercial paper borrowings, was 1.54% . (e) On November 26, 2014, we entered into a $4 billion replacement credit facility and a commercial paper program of up to $4 billion of unsecured notes (see “—Credit Facilities and Restrictive Covenants” below). (f) On January 1, 2015, EPB and EPPOC merged with and into KMP. On that date, KMP succeeded EPPOC as the issuer of approximately $2.9 billion of EPPOC’s senior notes, which were guaranteed by EPB, and EPB and EPPOC ceased to be obligors for those senior notes. (g) Southern Natural Issuing Corporation is a wholly owned finance subsidiary of SNG and is the co-issuer of certain of SNG’s outstanding debt securities. (h) In January and February 2016, we refinanced $850 million of maturing Kinder Morgan Finance Company LLC senior notes and $150 million of maturing TGP senior notes using proceeds from a new three -year term loan facility (see “— Subsequent Event—Debt Issuances and Repayments” below). (i) Represents the remaining principal amount outstanding of senior notes assumed in the Hiland acquisition. (j) Capital Trust I (Trust I), is a 100% -owned business trust that as of December 31, 2015 , 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, 2015 , the outstanding balance of $221 million (of which $111 million is classified as current) was bifurcated between debt ( $197 million ) and equity ( $24 million ). During the years ended December 31, 2015 and 2014 , 1,176,015 and 3,923 Trust I Preferred Securities had been converted into (i) 846,369 and 2,820 shares of our Class P common stock; (ii) approximately $30 million and $99,000 in cash; and (iii) 1,293,615 and 4,315 in warrants, respectively. (k) As of December 31, 2015 and 2014, 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. (l) 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, 2015 , the principal amounts of the Totem and High Plains financing obligations were $72 million and $96 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. (m) Amounts include outstanding credit facility and commercial paper borrowings and other debt maturing within 12 months. See “ — Maturities of Debt” below. (n) Excludes our “Debt fair value adjustments” which, as of December 31, 2015 and December 31, 2014 , increased our combined debt balances by $1,674 million and $1,785 million , respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs (resulting from the implementation of ASU No. 2015-03 and 2015-15) 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 Note 15 “Fair Value— Debt Fair Value Adjustments. ”
Schedule of Significant Long-Term Debt Issuances and Payments [Table Text Block]	Apart from the assumption of the Hiland debt discussed above, following are significant long-term debt issuances and repayments made during 2015 and 2014 : 2015 2014 Issuances $800 million 5.05% notes due 2046 $650 million senior term loan facility due 2017 $815 million 1.50% notes due 2022(a) $500 million 2.00% notes due 2017(b) $543 million 2.25% notes due 2027(a) $1,500 million 3.05% notes due 2019(b) $1,500 million 4.30% notes due 2025(b) $750 million 5.30% notes due 2034(b) $1,750 million 5.55% notes due 2045(b) $750 million 3.50% notes due 2021 $750 million 5.50% notes due 2044 $650 million 4.25% notes due 2024 $550 million 5.40% notes due 2044 $600 million 4.30% notes due 2024 Repayments $300 million 5.625% notes due 2015 $500 million 5.125% notes due 2014 $250 million 5.15% notes due 2015 $1,528 million senior term loan facility due 2015 $340 million 6.80% notes due 2015 $650 million senior term loan facility due 2017(b) $375 million 4.10% notes due 2015 $207 million 6.875% notes due 2014 ________ (a) Senior notes are denominated in Euros and are presented above in U.S. dollars at the exchange rate on the issuance date of 1.0860 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) Debt issued or repaid associated with the Merger Transactions.
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, 2015 , are summarized as follows (in millions): Year Total 2016(a) $ 821 2017 3,060 2018 2,329 2019(a) 3,819 2020 2,953 Thereafter 28,571 Total $ 41,553 ________ (a) 2016 amount primarily includes $667 million of current maturities on senior notes and $111 million associated with our Trust I Preferred Securities that are classified as current obligations because these securities have rights to convert into consideration consistent with the EP merger, and excludes $1,000 million of current maturities on long-term debt that were refinanced with proceeds from the issuance of a January 2016 three -year term loan which is reflected in 2019.

Share-based Compensation and 38

Share-based Compensation and Employee Benefits Share-based Compensation and Employee Benefits (Tables)	12 Months Ended
	Dec. 31, 2015
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 amounts): Year Ended Year Ended Year Ended December 31, 2013 Shares Weighted Average Grant Date Fair Value Shares Weighted Average Grant Date Fair Value Shares Weighted Average Grant Date Fair Value Outstanding at beginning of period 7,373,294 $ 277 6,382,885 $ 239 2,154,022 $ 69 Granted 1,488,467 57 1,694,668 61 4,563,495 181 Vested (817,797 ) (29 ) (460,032 ) (14 ) (83,444 ) (3 ) Forfeited (398,859 ) (15 ) (244,227 ) (9 ) (251,188 ) (8 ) Outstanding at end of period 7,645,105 $ 290 7,373,294 $ 277 6,382,885 $ 239 Intrinsic value of restricted stock awards vested during the period $ 31 $ 17 $ 3
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 2016 1,096,290 2017 1,563,549 2018 2,443,888 2019 1,688,831 2020 585,574 Thereafter 266,973 Total Outstanding 7,645,105
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, 2015 and 2014 (in millions): Pension Benefits OPEB 2015 2014 2015 2014 Change in benefit obligation: Benefit obligation at beginning of period $ 2,804 $ 2,563 $ 624 $ 631 Service cost 33 21 — — Interest cost 99 112 21 25 Actuarial (gain) loss (109 ) 294 (101 ) 15 Benefits paid (173 ) (186 ) (39 ) (52 ) Participant contributions — — 2 3 Medicare Part D subsidy receipts — — 2 2 Benefit obligation at end of period 2,654 2,804 509 624 Change in plan assets: Fair value of plan assets at beginning of period 2,377 2,333 389 380 Actual (loss) return on plan assets (204 ) 180 (45 ) 32 Employer contributions 50 50 16 25 Participant contributions — — 2 3 Medicare Part D subsidy receipts — — 2 1 Benefits paid (173 ) (186 ) (39 ) (52 ) Fair value of plan assets at end of period 2,050 2,377 325 389 Funded status - net liability at December 31, $ (604 ) $ (427 ) $ (184 ) $ (235 )
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, 2015 and 2014 related to our pension and OPEB plans (in millions): Pension Benefits OPEB 2015 2014 2015 2014 Non-current benefit asset $ — $ — $ 139 $ 173 Current benefit liability — — (16 ) (22 ) Non-current benefit liability (604 ) (427 ) (307 ) (386 ) Funded status - net liability at December 31, $ (604 ) $ (427 ) $ (184 ) $ (235 )
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, 2015 and 2014 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 2015 2014 2015 2014 Unrecognized net actuarial (loss) gain $ (558 ) $ (296 ) $ 23 $ (27 ) Unrecognized prior service (cost) credit (4 ) (4 ) 19 20 Accumulated other comprehensive (loss) income $ (562 ) $ (300 ) $ 42 $ (7 )
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, 2015 and 2014 (in millions): Pension Assets 2015 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Cash and money market funds $ 15 $ 110 $ — $ 125 $ 5 $ 91 $ — $ 96 Insurance contracts — — 15 15 — — 15 15 Mutual funds(a) 70 — — 70 71 — — 71 Common and preferred stocks(b) 271 — — 271 459 — — 459 Corporate bonds — 244 — 244 — 247 — 247 U.S. government securities — 171 — 171 — 190 — 190 Asset backed securities — 34 — 34 — 28 — 28 Other — — (14 ) (14 ) — — (15 ) (15 ) Subtotal $ 356 $ 559 $ 1 916 $ 535 $ 556 $ — 1,091 Measured at NAV(c) Common/collective trusts(d) 775 863 Equity trusts 187 199 Mutual funds(e) 160 198 Limited partnerships(f) 1 13 Private equity(g) 11 13 Subtotal 1,134 1,286 Total plan assets fair value $ 2,050 $ 2,377 _______ (a) For 2015 and 2014 , this category includes mutual funds which are invested in equity. (b) Plan assets include $91 million and $252 million of KMI Class P common stock for 2015 and 2014 , 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 45% fixed income and 55% equity in 2015 and 47% fixed income and 53% equity in 2014 . (e) Mutual funds were invested in fixed income for 2015 and 2014 . (f) Limited partnerships were invested in real estate partnerships for 2015 and 2014 . (g) Private equity was invested in limited partnerships that primarily invest in venture and buyout funds for 2015 and 2014 . OPEB Assets 2015 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Measured within fair value hierarchy Cash and money market funds $ — $ 16 $ — $ 16 $ (3 ) $ 26 $ — $ 23 Domestic equity securities 8 — — 8 14 — — 14 Limited partnerships 51 — — 51 87 — — 87 Insurance contracts — — 49 49 — — 51 51 Mutual funds 1 — — 1 1 — — 1 Subtotal $ 60 $ 16 $ 49 125 $ 99 $ 26 $ 51 176 Measured at NAV(a) Common/collective trusts(b) 71 71 Fixed income trusts 58 63 Limited partnerships(c) 71 79 Subtotal 200 213 Total plan assets fair value $ 325 $ 389 _______ (a) Plan assets for which fair value was measured using NAV as a practical expedient. (b) For 2015 and 2014 , this category includes common/collective trust funds which are invested in approximately 67% equity and 33% fixed income securities, respectively. (c) For 2015 and 2014 , 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, 2015 and 2014 (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 2015 Insurance contracts $ 15 $ — $ — $ — $ 15 Other (15 ) — (2 ) 3 (14 ) Total $ — $ — $ (2 ) $ 3 $ 1 2014 Insurance contracts $ 15 $ — $ — $ — $ 15 Other 11 — (18 ) (8 ) (15 ) Total $ 26 $ — $ (18 ) $ (8 ) $ — OPEB Assets Balance at Beginning of Period Transfers In (Out) Realized and Unrealized Gains (Losses), net Purchases (Sales), net Balance at End of Period 2015 Insurance contracts $ 51 $ — $ (1 ) $ (1 ) $ 49 2014 Insurance contracts $ 50 $ — $ (4 ) $ 5 $ 51
Schedule of Expected Benefit Payments [Table Text Block]	Expected Payment of Future Benefits and Employer Contributions . As of December 31, 2015 , we expect to make the following benefit payments under our plans (in millions): Fiscal year Pension Benefits OPEB(a) 2016 $ 230 $ 39 2017 197 39 2018 196 39 2019 198 39 2020 197 38 2021-2025 962 182 _______ (a) Includes a reduction of approximately $3 million in each of the years 2016 - 2020 and approximately $18 million in aggregate for 2021 - 2025 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 2015 , 2014 and 2013 : Pension Benefits OPEB 2015 2014 2013 2015 2014 2013 Assumptions related to benefit obligations: Discount rate 4.05 % 3.66 % 4.45 % 3.91 % 3.56 % 4.34 % Rate of compensation increase 3.50 % 4.50 % 3.50 % n/a n/a n/a Assumptions related to benefit costs: Discount rate(a) 3.66 % 4.45 % 3.40 % 3.56 % 4.34 % 3.62 % Expected return on plan assets(b) 7.50 % 7.50 % 8.00 % 7.08 % 7.43 % 7.35 % Rate of compensation increase 4.50 % 3.50 % 3.00 % n/a n/a n/a _______ (a) The discount rate related to other postretirement benefit cost was 3.34% for the period from January 1, 2013 to July 31, 2013 (the period prior to an OPEB plan amendment that resulted in a remeasurement) and 4.00% for the period from August 1, 2013 to December 31, 2013. (b) 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 both 2015 and 2014 and 24% for 2013.
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, 2015 and 2014 (in millions): 2015 2014 One-percentage point increase: Aggregate of service cost and interest cost $ 2 $ 2 Accumulated postretirement benefit obligation 31 47 One-percentage point decrease: Aggregate of service cost and interest cost $ (1 ) $ (2 ) Accumulated postretirement benefit obligation (27 ) (40 )
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 2015 2014 2013 2015 2014 2013 Components of net benefit cost: Service cost $ 33 $ 21 $ 25 $ — $ — $ — Interest cost 99 112 92 21 25 23 Expected return on assets (172 ) (171 ) (175 ) (23 ) (24 ) (22 ) Amortization of prior service credit — — — (3 ) (2 ) (1 ) Amortization of net actuarial loss (gain) 5 — — 1 (1 ) 3 Curtailment and settlement gain — — (3 ) — — — Net benefit (credit) cost (35 ) (38 ) (61 ) (4 ) (2 ) 3 Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: Net loss (gain) arising during period 267 285 (211 ) (49 ) 10 (50 ) Prior service cost (credit) arising during period — — 25 — — (18 ) Amortization or settlement recognition of net actuarial (loss) gain (5 ) — 3 (1 ) — (3 ) Amortization of prior service credit — — — 1 1 1 Total recognized in total other comprehensive (income) loss 262 285 (183 ) (49 ) 11 (70 ) Total recognized in net benefit cost (credit) and other comprehensive (income) loss $ 227 $ 247 $ (244 ) $ (53 ) $ 9 $ (67 )

Stockholders Equity (Tables)

Stockholders Equity (Tables)	12 Months Ended
	Dec. 31, 2015
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 2013 KMP(a) Per unit cash distribution declared for the period $ 4.17 $ 5.33 Per unit cash distribution paid in the period $ 5.53 $ 5.26 Cash distributions paid in the period to the public $ 1,654 $ 1,372 EPB(a) Per unit cash distribution declared for the period $ 1.95 $ 2.55 Per unit cash distribution paid in the period $ 2.60 $ 2.51 Cash distributions paid in the period to the public $ 347 $ 318 KMR(a)(b) Share distributions paid in the period to the public 7,794,183 6,588,477 _______ (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 and 976,723 of shares distributed in 2014 and 2013, respectively, 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, 2015 2014 2013 Per common share cash dividend declared for the period $ 1.605 $ 1.740 $ 1.600 Per common share cash dividend paid in the period 1.93 1.70 1.56
Schedule of Warrants Outstanding Roll Forward [Table Text Block]	The table below sets forth the changes in our outstanding warrants: Warrants 2015 2014 2013 Beginning balance 298,135,976 347,933,107 439,809,442 Warrants issued in acquisition of EP(a) — — 81 Warrants issued with conversions of EP Trust I Preferred securities(b) 1,293,615 4,315 118,377 Warrants exercised (71,268 ) (18,040 ) (21,208 ) Warrants repurchased and canceled (6,094,526 ) (49,783,406 ) (91,973,585 ) Ending balance 293,263,797 298,135,976 347,933,107 _______ (a) 2013 amount represents warrants issued upon the settlement of an EP dissenter. The settlement of the dissenter’s 128 EP shares was determined based on the same conversion of EP shares into cash, KMI Class P shares and KMI warrants that was received by other EP shareholders at the time of the acquisition. (b) See Note 9.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 Balance sheet location Accounts receivable, net $ 25 $ 31 Other current assets 36 3 Deferred charges and other assets — 46 $ 61 $ 80 Current portion of debt(a) $ 6 $ 6 Accounts payable 22 22 Other current liabilities 10 — Long-term debt(a) 167 172 $ 205 $ 200 _______ (a) Includes financing obligations payable to WYCO (See Note 9). Year Ended December 31, 2015 2014 2013 Income statement location Services $ 72 $ 29 $ 31 Product sales and other 71 86 36 $ 143 $ 115 $ 67 Cost of sales $ 60 $ 74 $ 17 General and administrative 55 57 57

Commitments and Contingent Li41

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 (in millions): Year Commitment 2016 $ 103 2017 90 2018 83 2019 78 2020 69 Thereafter 406 Total minimum payments $ 829

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments [Table Text Block]	As of December 31, 2015 , we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales: Net open position long/(short) Derivatives designated as hedging contracts Crude oil fixed price (21.7 ) MMBbl Crude oil basis (6.4 ) MMBbl Natural gas fixed price (37.6 ) Bcf Natural gas basis (30.1 ) Bcf Derivatives not designated as hedging contracts Crude oil fixed price (0.6 ) MMBbl Crude oil basis (1.3 ) MMBbl Natural gas fixed price (14.3 ) Bcf Natural gas basis (8.6 ) Bcf NGL and other fixed price (1.9 ) 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, 2015 2014 2015 2014 Location Fair value Fair value Derivatives designated as hedging contracts Natural gas and crude derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 359 $ 309 $ (13 ) $ (34 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 244 6 — — Subtotal 603 315 (13 ) (34 ) Interest rate swap agreements Fair value of derivative contracts/(Other current liabilities) 111 143 — — Deferred charges and other assets/(Other long-term liabilities and deferred credits) 273 260 (9 ) (53 ) Subtotal 384 403 (9 ) (53 ) Cross-currency swap agreements Fair value of derivative contracts/(Other current liabilities) — — (6 ) — Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (46 ) — Subtotal — — (52 ) — Total 987 718 (74 ) (87 ) Derivatives not designated as hedging contracts Natural gas, crude, NGL and other derivative contracts Fair value of derivative contracts/(Other current liabilities) 35 73 (1 ) (2 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — 196 — — Subtotal 35 269 (1 ) (2 ) 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 10 (17 ) (57 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — — (16 ) Subtotal 1 10 (17 ) (73 ) Total 37 279 (34 ) (75 ) Total derivatives $ 1,024 $ 997 $ (108 ) $ (162 )
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, 2015 2014 2013 Interest rate swap agreements Interest, net $ 25 $ 207 $ (425 ) Hedged fixed rate debt Interest, net $ (33 ) $ (204 ) $ 425 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, 2015 2014 2013 2015 2014 2013 2015 2014 2013 Energy commodity derivative contracts $ 201 $ 424 $ (45 ) Revenues—Natural gas sales $ 54 $ (1 ) $ — Revenues—Natural gas sales $ — $ — $ — Revenues—Product sales and other 236 26 (13 ) Revenues—Product sales and other 2 11 3 Costs of sales (15 ) 4 — Costs of sales — — — Interest rate swap agreements(c) (4 ) (15 ) 7 Interest, net (3 ) (4 ) 2 Interest, net — — — Cross-currency swap (33 ) — — Other, net — — — Other, net — — — Total $ 164 $ 409 $ (38 ) Total $ 272 $ 25 $ (11 ) Total $ 2 $ 11 $ 3 _______ (a) We expect to reclassify an approximate $181 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of December 31, 2015 into earnings during the next twelve months (when the associated forecasted sales and purchases 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 income/(loss). Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives Year Ended December 31, 2015 2014 2013 Energy commodity derivative contracts Revenues—Natural gas sales $ 17 $ (7 ) $ — Revenues—Product sales and other 176 20 (10 ) Costs of sales (2 ) — 2 Other expense (income) — (2 ) (2 ) Interest rate swap agreements Interest, net (15 ) — — Total(a) $ 176 $ 11 $ (10 ) ________ (a) For the year ended December 31, 2015 , includes approximate gain of $31 million 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, 2012 $ 7 $ 51 $ (176 ) $ (118 ) Other comprehensive income before reclassifications (14 ) (49 ) 151 88 Amounts reclassified from accumulated other comprehensive loss 4 — 2 6 Net current-period other comprehensive income (10 ) (49 ) 153 94 Balance as of December 31, 2013 (3 ) 2 (23 ) (24 ) Other comprehensive loss before reclassifications 254 (68 ) (212 ) (26 ) Amounts 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 330 (110 ) (213 ) 7 Balance as of December 31, 2014 327 (108 ) (236 ) (17 ) Other comprehensive loss before reclassifications 164 (214 ) (122 ) (172 ) Amounts 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 )

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value, by Balance Sheet Grouping	The estimated fair value of our outstanding debt balances is disclosed below (in millions): December 31, 2015 December 31, 2014 Carrying value Estimated fair value Carrying value Estimated fair value Total debt $ 43,227 $ 37,481 $ 42,814 $ 43,761
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, 2015 2014 Derivatives-net asset (liability) Beginning of period $ (61 ) $ (110 ) Transfers out(a) — (88 ) Total gains or (losses) Included in earnings (13 ) 22 Included in other comprehensive loss — 78 Settlements 59 37 End of period $ (15 ) $ (61 ) 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 $ — $ 1 _______ (a) On December 31, 2014, we transferred WTI options from Level 3 to Level 2 due to increased observability of significant inputs in their valuations.
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, 2015 Energy commodity derivative contracts(a) $ 48 $ 589 $ 2 $ 639 $ (12 ) $ (37 ) $ 590 Interest rate swap agreements $ — $ 385 $ — $ 385 $ (8 ) $ — $ 377 Cross-currency swap agreements $ — $ — $ — $ — $ — $ — $ — As of December 31, 2014 Energy commodity derivative contracts(a) $ 49 $ 533 $ 12 $ 594 $ (46 ) $ (13 ) $ 535 Interest rate swap agreements $ — $ 403 $ — $ 403 $ (44 ) $ — $ 359 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, 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 ) As of December 31, 2014 Energy commodity derivative contracts(a) $ (25 ) $ (11 ) $ (73 ) $ (109 ) $ 46 $ 47 $ (16 ) Interest rate swap agreements $ — $ (53 ) $ — $ (53 ) $ 44 $ — $ (9 ) _______ (a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps and options. 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 “Other current assets” on our accompanying consolidated balance sheets.

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Schedule of Revenue from External Customers Attributed to Foreign Countries by Geographic Area [Table Text Block]	is geographic information regarding the revenues and long-lived assets of our business segments (in millions): Year Ended December 31, 2015 2014 2013 Revenues from external customers U.S. $ 13,797 $ 15,605 $ 13,656 Canada 479 437 398 Mexico 127 184 16 Total consolidated revenues from external customers $ 14,403 $ 16,226 $ 14,070 December 31, 2015 2014 Long-term assets, excluding goodwill and other intangibles U.S. $ 51,679 $ 49,992 Canada 2,193 2,268 Mexico 67 81 Total consolidated long-lived assets $ 53,939 $ 52,341
Schedule of Segment Reporting Information, by Segment	Financial information by segment follows (in millions): Year Ended December 31, 2015 2014 2013 Revenues Natural Gas Pipelines Revenues from external customers $ 8,704 $ 10,153 $ 8,613 Intersegment revenues 21 15 4 CO 2 1,699 1,960 1,857 Terminals Revenues from external customers 1,878 1,717 1,408 Intersegment revenues 1 1 2 Products Pipelines Revenues from external customers 1,828 2,068 1,853 Intersegment revenues 3 — — Kinder Morgan Canada 260 291 302 Other (3 ) 1 1 Total segment revenues 14,391 16,206 14,040 Other revenues(a) 37 36 36 Less: Total intersegment revenues (25 ) (16 ) (6 ) Total consolidated revenues $ 14,403 $ 16,226 $ 14,070 Year Ended December 31, 2015 2014 2013 Operating expenses(b) Natural Gas Pipelines $ 4,738 $ 6,241 $ 5,235 CO 2 432 494 439 Terminals 836 746 657 Products Pipelines 772 1,258 1,295 Kinder Morgan Canada 87 106 110 Other 51 24 30 Total segment operating expenses 6,916 8,869 7,766 Less: Total intersegment operating expenses (25 ) (16 ) (6 ) Total consolidated operating expenses $ 6,891 $ 8,853 $ 7,760 Year Ended December 31, 2015 2014 2013 Other expense (income)(c) Natural Gas Pipelines $ 1,269 $ 5 $ (24 ) CO 2 606 243 — Terminals 190 29 (74 ) Products Pipelines 2 (3 ) 6 Kinder Morgan Canada (1 ) — — Other — 1 (7 ) Total consolidated other expense (income) $ 2,066 $ 275 $ (99 ) Year Ended December 31, 2015 2014 2013 DD&A Natural Gas Pipelines $ 1,046 $ 897 $ 797 CO 2 556 570 533 Terminals 433 337 247 Products Pipelines 206 166 155 Kinder Morgan Canada 46 51 54 Other 22 19 20 Total consolidated DD&A $ 2,309 $ 2,040 $ 1,806 Year Ended December 31, 2015 2014 2013 Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments Natural Gas Pipelines $ 285 $ 279 $ 200 CO 2 (5 ) 26 22 Terminals 17 18 22 Products Pipelines 36 37 40 Kinder Morgan Canada — — 4 Other — 1 — Total consolidated equity earnings $ 333 $ 361 $ 288 Year Ended December 31, 2015 2014 2013 Interest income Natural Gas Pipelines $ — $ 1 $ — Products Pipelines 2 2 2 Kinder Morgan Canada — — 3 Other 2 6 8 Total segment interest income 4 9 13 Unallocated interest income — — 2 Total consolidated interest income $ 4 $ 9 $ 15 Year Ended December 31, 2015 2014 2013 Other, net-income (expense) Natural Gas Pipelines $ 24 $ 24 $ 578 CO 2 — — — Terminals 8 12 1 Products Pipelines 4 (1 ) 1 Kinder Morgan Canada 8 15 246 Other (1 ) 30 9 Total consolidated other, net-income (expense) $ 43 $ 80 $ 835 Year Ended December 31, 2015 2014 2013 Income tax benefit (expense) Natural Gas Pipelines $ (4 ) $ (6 ) $ (9 ) CO 2 (1 ) (8 ) (7 ) Terminals (29 ) (29 ) (14 ) Products Pipelines (8 ) (2 ) 2 Kinder Morgan Canada (19 ) (18 ) (21 ) Total segment income tax expense (61 ) (63 ) (49 ) Unallocated income tax expense (503 ) (585 ) (693 ) Total consolidated income tax expense $ (564 ) $ (648 ) $ (742 ) Year Ended December 31, 2015 2014 2013 Segment EBDA(d) Natural Gas Pipelines $ 3,063 $ 4,259 $ 4,207 CO 2 657 1,240 1,435 Terminals 849 944 836 Products Pipelines 1,100 856 602 Kinder Morgan Canada 163 182 424 Other (53 ) 13 (5 ) Total segment EBDA 5,779 7,494 7,499 Total segment DD&A (2,309 ) (2,040 ) (1,806 ) Total segment amortization of excess cost of equity investments (51 ) (45 ) (39 ) Other revenues 37 36 36 General and administrative expenses (690 ) (610 ) (613 ) Interest expense, net of unallocable interest income(e) (2,055 ) (1,807 ) (1,688 ) Unallocable income tax expense (503 ) (585 ) (693 ) Loss from discontinued operations, net of tax — — (4 ) Total consolidated net income $ 208 $ 2,443 $ 2,692 Year Ended December 31, 2015 2014 2013 Capital expenditures Natural Gas Pipelines $ 1,642 $ 935 $ 1,085 CO 2 725 792 667 Terminals 847 1,049 1,108 Products Pipelines 524 680 416 Kinder Morgan Canada 142 156 77 Other 16 5 16 Total consolidated capital expenditures $ 3,896 $ 3,617 $ 3,369 2015 2014 Investments at December 31 Natural Gas Pipelines $ 5,080 $ 5,174 CO 2 — 17 Terminals 306 219 Products Pipelines 641 624 Kinder Morgan Canada 10 1 Other 3 1 Total consolidated investments $ 6,040 $ 6,036 2015 2014 Assets at December 31 Natural Gas Pipelines $ 53,704 $ 52,532 CO 2 4,706 5,227 Terminals 9,083 8,850 Products Pipelines 8,464 7,179 Kinder Morgan Canada 1,434 1,593 Other 418 455 Total segment assets 77,809 75,836 Corporate assets(f) 6,276 7,157 Assets held for sale 19 56 Total consolidated assets $ 84,104 $ 83,049 _______ (a) Includes a management fee for services we perform for NGPL. (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 (gain) on impairments and disposals of long-lived assets, net and other expense (income), net. (d) Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income), net, loss on impairment of goodwill, and losses (gain) on impairments and disposals of long-lived assets, net and equity investments. (e) Includes (i) interest expense and (ii) miscellaneous other income and expenses not allocated to business segments. (f) Includes cash and cash equivalents, margin and restricted deposits, unallocable interest receivable, prepaid assets and deferred charges, risk management assets related to debt fair value adjustments and miscellaneous corporate assets (such as information technology and telecommunications equipment) not allocated to individual segments. We do no

General (Details)

General (Details) - USD ($) $ in Billions	Nov. 25, 2014	Nov. 25, 2014
Subsidiary Issuer and Guarantor - KMP
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%
Merger Transactions [Member]
Entity Information [Line Items]
Other Significant Noncash Transaction, Value of Consideration Given	$ 77

Summary of Significant Accoun46

Summary of Significant Accounting Policies Cash Equivalents and Restricted Deposits (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Restricted Cash and Cash Equivalents, Current	$ 60	$ 118

Summary of Significant Accoun47

Summary of Significant Accounting Policies Accounts Receivable, Net (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Allowance for Doubtful Accounts Receivable	$ 91	$ 10

Summary of Significant Accoun48

Summary of Significant Accounting Policies Gas Imbalances (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Gas imbalance receivable	$ 21	$ 103
Gas imbalance payable	$ 17	$ 36

Summary of Significant Accoun49

Summary of Significant Accounting Policies Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Composite depreciation rate, low	0.90%
Composite depreciation rate, high	23.00%

Summary of Significant Accoun50

Summary of Significant Accounting Policies Equity investment and excess costs (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Amortized [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method of Accounting and Excess Investment Cost	$ 808	$ 870
Unamortization [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method of Accounting and Excess Investment Cost	$ 138	$ 138

Summary of Significant Accoun51

Summary of Significant Accounting Policies Goodwill (Details)	12 Months Ended
	Dec. 31, 2015
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, 2015	Dec. 31, 2014	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Intangible Assets, Gross (Excluding Goodwill)	$ 3,551	$ 2,302
Amortization of Intangible Assets	221	$ 143	$ 125
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	221
Finite-Lived Intangible Assets, Amortization Expense, Year Two	218
Finite-Lived Intangible Assets, Amortization Expense, Year Three	216
Finite-Lived Intangible Assets, Amortization Expense, Year Four	214
Finite-Lived Intangible Assets, Amortization Expense, after Year Five	$ 211
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	18 years

Summary of Significant Accoun53

Summary of Significant Accounting Policies Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets and Liabilities [Line Items]
Current regulatory assets	$ 55	$ 81
Non-current regulatory assets	378	406
Total regulatory assets	433	487
Current regulatory liabilities	161	189
Non-current regulatory liabilities	166	290
Total regulatory liabilities	$ 327	$ 479
Minimum [Member]
Regulatory Assets and Liabilities [Line Items]
Current regulatory assets	1 year
Maximum [Member]
Regulatory Assets and Liabilities [Line Items]
Current regulatory assets	41 years

Summary of Significant Accoun54

Summary of Significant Accounting Policies Earnings per share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ 227	$ 1,026	$ 1,193
Basic Weighted Average Common Shares Outstanding	2,187	1,137	1,036
Warrants(b)	6	0	0
Diluted Weighted Average Common Shares Outstanding	2,193	1,137	1,036
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	7	7	4
Warrants to purchase our Class P shares
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	291	312	401
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	10	10
Mandatory convertible preferred stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	10
Class P
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ 214	$ 1,015	$ 1,187
Basic Weighted Average Common Shares Outstanding	2,187	1,137	1,036
Restricted stock awards(a)
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income Available to Common Stockholders	$ 13	$ 11	$ 6
Unvested Restricted Stock Awards, Issued and Non Issued	8

Acquisitions and Divestitures B

Acquisitions and Divestitures Business Combinations and Acquisitions of Investments (Details) - USD ($) $ in Millions	Feb. 27, 2015	Feb. 13, 2015	Nov. 05, 2014	Jan. 17, 2014	Jun. 03, 2013	May. 03, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	May. 31, 2013	Apr. 30, 2013
Business Acquisition [Line Items]
Goodwill							$ 23,790	$ 24,654	$ 24,504
Vopak Terminal Assets [Member]
Business Acquisition [Line Items]
Purchase price	$ 158
Current assets	2
Property, plant, and equipment	155
Deferred charges & other	0
Goodwill	7
Long-term debt	0
Other liabilities	(6)
Noncontrolling interest	0
Previously held equity interest	$ 0
Hiland Partners, LP [Member]
Business Acquisition [Line Items]
Purchase price		$ 1,709
Current assets		79
Property, plant, and equipment		1,497
Deferred charges & other		1,498
Goodwill		310
Long-term debt		(1,411)
Other liabilities		(264)
Noncontrolling interest		0
Previously held equity interest		$ 0
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
Long-term debt			0
Other liabilities			(33)
Noncontrolling interest			0
Previously held equity interest			$ 0
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
Long-term debt				0
Other liabilities				(66)
Noncontrolling interest				0
Previously held equity interest				$ 0
Goldsmith-Landreth Field Unit [Member]
Business Acquisition [Line Items]
Purchase price										$ 280
Current assets										0
Property, plant, and equipment										298
Deferred charges & other										0
Goodwill										0
Long-term debt										0
Other liabilities										(18)
Noncontrolling interest										$ 0
Previously held equity interest					$ 0
Copano Energy, L.L.C.
Business Acquisition [Line Items]
Purchase price											$ 3,733
Current assets											218
Property, plant, and equipment											2,788
Deferred charges & other											1,973
Goodwill											963
Long-term debt											(1,252)
Other liabilities											(236)
Noncontrolling interest											$ (17)
Previously held equity interest						$ (704)

Acquisitions and Divestitures (

Acquisitions and Divestitures (1) Vopak Terminal Assets (Details) - Vopak Terminal Assets [Member] $ in Millions	Feb. 27, 2015USD ($)abbl
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 Divestitures57

Acquisitions and Divestitures (2) Hiland (Details) - USD ($) $ in Millions	Feb. 13, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Repayments of Debt Assumed		$ 15,116	$ 17,801	$ 12,393
Hiland Partners, LP [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 3,120
Repayments of Debt Assumed	$ 368
Finite-Lived Intangible Asset, Useful Life		16 years 10 months

Acquisitions and Divestitures58

Acquisitions and Divestitures (3) 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 | MBbls	330

Acquisitions and Divestitures59

Acquisitions and Divestitures (4) American Petroleum Tankers and State Class Tankers (Details) $ in Millions	Feb. 02, 2016USD ($)	Jan. 17, 2014USD ($)MBbls	Feb. 01, 2016
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 | MBbls		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 | MBbls		330
Vessel Time Charter, Operating Remaining contract term		5 years
Vessel Time Charter, Operating Renewal Term (up to)		3 years
Subsequent Event [Member] | BP Terminal Assets [Member]
Business Acquisition [Line Items]
Number of terminals wholly owned			1
Payments to Acquire Businesses, Gross | $	$ 350

Acquisitions and Divestitures60

Acquisitions and Divestitures (5) Goldsmith Landreth Field Unit (Details) - Legado Resources [Member] - Goldsmith-Landreth Field Unit [Member] $ in Millions	Jun. 01, 2013USD ($)MMcf	May. 31, 2013USD ($)a
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 298
Payments to Acquire Businesses, Gross	$ 280
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities		$ 18
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Long-Term Asset Retirement Obligations		$ 12
Maximum [Member]
Business Acquisition [Line Items]
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume Per Day | MMcf	150
Ector County, Texas [Member]
Business Acquisition [Line Items]
Area of Land | a		6,000

Acquisitions and Divestitures61

Acquisitions and Divestitures (6) Copano (Details) - USD ($) $ in Millions	May. 03, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	May. 01, 2013
Business Acquisition [Line Items]
Equity Method Investments		$ 6,032	$ 6,028
Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain (Loss), Net		$ 0	$ 0	$ 558
Copano Energy, L.L.C.
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 5,200
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable, Percent of Transaction Unit for Unit					100.00%
Business Combination, Step Acquisition, Equity Interest in Acquiree, Fair Value	704
KMP Common Units [Member] | Copano Energy, L.L.C.
Business Acquisition [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable,Unit for Unit Exchange Ratio					0.4563
Eagle Ford Gathering LLC [Member] | Copano Energy, L.L.C.
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired					50.00%
Equity Method Investments					$ 146
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage					50.00%
Business Combination, Step Acquisition, Equity Interest in Acquiree, Fair Value	$ 704
Gain on remeasurement of previously held equity investments to fair value [Member] | Eagle Ford Gathering LLC [Member] | Copano Energy, L.L.C.
Business Acquisition [Line Items]
Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain (Loss), Net				$ 558

Acquisitions and Divestitures A

Acquisitions and Divestitures Asset Purchase (Details) - USD ($) $ in Millions	Jul. 16, 2015	Jul. 15, 2015
Shell US Gas & Power LLC [Member] | Elba Liquification Company LLC [Member]
Property, Plant and Equipment [Line Items]
Equity Method Investment, Ownership Percentage		49.00%
Shell US Gas & Power LLC [Member] | Elba Liquification Company LLC [Member]
Property, Plant and Equipment [Line Items]
Payments to Acquire Assets, Investing Activities	$ 185
Shell US Gas & Power LLC [Member] | Elba Liquification Company LLC [Member]
Property, Plant and Equipment [Line Items]
Capacity Subscribed, Percent		100.00%

Acquisitions and Divestitures I

Acquisitions and Divestitures Investment Acquisition (Details) - USD ($) $ in Millions	Dec. 11, 2015	Dec. 31, 2015	Dec. 10, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Equity Method Investments		$ 6,032		$ 6,028
NGPL Holdings, LLC [Member]
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] | NGPL Holdings, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Incremental Ownership Percentage Acquired			53.00%
Brookfield Infrastructure Partners L.P. [Member] | NGPL Holdings, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			50.00%

Acquisitions and Divestitures64

Acquisitions and Divestitures Investment Divestiture (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 14, 2013
Business Acquisition [Line Items]
Proceeds from sales of assets and investments	$ 0	$ 0	$ 490
Income Tax Expense	(564)	(648)	(742)
Equity Method Investments	$ 6,032	$ 6,028
Express Pipeline System and Subordinated Debenture Investments [Member] | Spectra Energy Corp. [Member]
Business Acquisition [Line Items]
Proceeds from sales of assets and investments			402
Equity Method Investment, Realized Gain (Loss) on Disposal			224
Income Tax Expense			$ (84)
Kinder Morgan Energy Partners, L.P. [Member] | Express Pipeline System [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage				33.33%

Acquisitions and Divestitures S

Acquisitions and Divestitures Subsequent Event of Terminal Acquisition From and Joint Venture With BP (Details) $ in Millions	Feb. 02, 2016USD ($)	Feb. 01, 2016	Jan. 31, 2016	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Equity Method Investments				$ 6,032	$ 6,028
Subsequent Event [Member] | BP Terminal Assets [Member]
Business Acquisition [Line Items]
Number of terminals		15
Payments to Acquire Businesses, Gross	$ 350
New Joint Venture with BP [Member] | Subsequent Event [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
Terminals | New Joint Venture with BP [Member] | Subsequent Event [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] | Subsequent Event [Member] | BP Terminal Assets [Member]
Business Acquisition [Line Items]
Number of terminals contributed to equity investment		5
BP [Member] | New Joint Venture with BP [Member] | Subsequent Event [Member] | BP Terminal Assets [Member]
Business Acquisition [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share			25.00%

Impairments (Details)

Impairments (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairment of goodwill		$ 1,150	$ 0	$ 0
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		0	(3)	3
Loss / Gain on impairments and disposals of long-lived assets, equity investments and goodwill, net		2,125	274	(33)
Equity Method Investment, Other than Temporary Impairment		$ 30	0	65
Degree of confidence		90.00%
Probable reserves		50.00%
Weighted Average Discount Rate, Percent	8.00%
Natural Gas Pipelines
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairment of goodwill		$ 1,150	0	0
Loss on impairments of long-lived assets		79	0	0
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		43	5	(28)
Equity Method Investment, Other than Temporary Impairment		26	0	65
CO2
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairments of long-lived assets		606	243	0
Equity Method Investment, Other than Temporary Impairment		26	0	0
Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairments of long-lived assets		188	0	0
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		3	29	(73)
Equity Method Investment, Other than Temporary Impairment		4	$ 0	$ 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
Weighted Average Discount Rate, Percent	12.00%
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
After income tax [Member] | Terminals
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairments of long-lived assets		84
Long-lived assets [Member] | 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
Natural Gas Pipelines Non-Regulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairment of goodwill		1,150
Loss on impairments of long-lived assets		47
Natural Gas Pipelines Regulated
Impairment of Goodwill, Long-lived assets and equity investments [Line Items]
Loss on impairment of goodwill		0
Loss on impairments of long-lived assets		$ 32

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income from Continuing Operations Before Income Taxes
U.S.	$ 611	$ 2,941	$ 3,107
Foreign	161	150	331
Income from Continuing Operations Before Income Taxes	772	3,091	3,438
Current tax expense (benefit) [Abstract]
Federal (Benefit)	(125)	(16)	57
State	(7)	36	36
Foreign	4	13	9
Total	(128)	33	102
Deferred tax expense (benefit) [Abstract]
Federal	653	572	612
State	(4)	14	0
Foreign	43	29	28
Total	692	615	640
Total tax provision	564	648	742
Effective Income Tax Rate Reconciliation [Abstract]
Federal income tax	$ 271	$ 1,082	$ 1,203
Federal income tax	35.00%	35.00%	35.00%
State deferred tax rate change	$ (24)	$ 0	$ (21)
State deferred tax rate change	(3.10%)	0.00%	(0.60%)
Taxes on foreign earnings	$ 26	$ 40	$ 112
Taxes on foreign earnings	3.50%	1.30%	3.30%
Net effects of consolidating subsidiary's income tax provisions	$ 15	$ (433)	$ (488)
Net effects of consolidating subsidiary's income tax provision, percent	2.00%	(14.00%)	(14.20%)
State income tax, net of federal benefit	$ 12	$ 37	$ 45
State income tax, net of federal benefit	1.50%	1.20%	1.30%
Dividend received deduction	$ (51)	$ (50)	$ (54)
Dividend received deduction	(6.60%)	(1.60%)	(1.60%)
Adjustments to uncertain tax positions	$ (14)	$ (5)	$ (87)
Adjustments to uncertain tax prositions, percent	(1.90%)	(0.20%)	(2.50%)
Disposition of certain international holdings	$ 0	$ (112)	$ 0
Disposition of certain international holdings	0.00%	(3.60%)	0.00%
Nondeductible goodwill impairment	$ 323	$ 0	$ 0
Nondeductible goodwill impairment	41.70%	0.00%	0.00%
Other	$ 6	$ 28	$ 32
Other	0.80%	0.90%	0.90%
Total	$ 564	$ 648	$ 742
Total	72.90%	21.00%	21.60%
Components of Deferred Tax Assets and Liabilities [Abstract]
Employee benefits	$ 394	$ 329
Accrued expenses	129	123
Net operating loss, capital loss, tax credit carryforwards	1,344	778
Derivative instruments and interest rate and currency swaps	45	43
Debt fair value adjustments	110	102
Investments	3,607	4,858
Other	3	31
Valuation allowances	152	154
Total deferred tax assets	5,480	6,110
Property, plant and equipment	143	373
Other	14	30
Deferred tax liabilities	157	403
Net deferred tax assets	5,323	5,707
Deferred Tax Assets, Net, Classification [Abstract]
Current deferred tax asset	0	56
Non-current deferred tax assets	5,323	5,651
Net deferred tax assets	5,323	5,707
Deferred Tax Assets,Valuation Allowances	152	154
Deferred Tax Assets, Operating Loss Carryforwards	1,005	466
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	$ 339	312
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	$ 189	209	$ 269
Unrecognized Tax Benefits, Subtotal	189	209	273
Additions based on current year tax positions	4	12	11
Additions based on prior year tax positions	0	0	26
Reductions based on prior year tax positions	(6)	(3)	0
Reductions based on settlements with taxing authority	(25)	(24)	(86)
Reductions due to lapse in statute of limitations	(14)	(5)	(15)
Unrecognized Tax Benefits, Ending	148	189	209
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	24	28	29
Unrecognized Tax Benefits, Income Tax Penalties Accrued	2	2	2
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	148
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	5
Unrecognized tax benefits, income tax penalties and interest accruing next year	143
General Business Tax Credit Carryforward [Member] | Foreign Tax Authority [Member]
Deferred Tax Assets, Net, Classification [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Foreign	154
2018 - 2035 [Member] | General Business Tax Credit Carryforward [Member] | Domestic Tax Authority [Member]
Deferred Tax Assets, Net, Classification [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	2,400
Does Not Expire [Member] | General Business Tax Credit Carryforward [Member]
Deferred Tax Assets, Net, Classification [Abstract]
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	312
Does Not Expire [Member] | General Business Tax Credit Carryforward [Member] | Foreign Tax Authority [Member]
Deferred Tax Assets, Net, Classification [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Not Subject to Expiration	115
Expires from 2028 - 2035 [Member] | General Business Tax Credit Carryforward [Member] | Foreign Tax Authority [Member]
Deferred Tax Assets, Net, Classification [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	39
Majority expire from 2016 - 2025 [Member] | General Business Tax Credit Carryforward [Member]
Deferred Tax Assets, Net, Classification [Abstract]
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	26
Natural Gas Pipelines
Effective Income Tax Rate Reconciliation [Abstract]
Valuation allowance on investment in NGPL	$ 0	$ 61	$ 0
Valuation allowance on investment in NGPL	0.00%	2.00%	0.00%
Components of Deferred Tax Assets and Liabilities [Abstract]
Valuation allowances		$ 61
Deferred Tax Assets, Net, Classification [Abstract]
Deferred Tax Assets,Valuation Allowances		61
Merger Transactions [Member]
Components of Deferred Tax Assets and Liabilities [Abstract]
Valuation allowances	$ 3,600	4,900
Deferred Tax Assets, Net, Classification [Abstract]
Deferred Tax Assets,Valuation Allowances	3,600	4,900
KMI's Acquisition of EP [Member] | El Paso LLC [Member]
Reconciliation of Gross Unrecognized Tax Benefits, Excluding Interest and Penalties
Uncertain tax positions of EP	0	0	$ 4
State and Local Jurisdiction [Member] | Expires from 2015 - 2035 [Member] | General Business Tax Credit Carryforward [Member] | Domestic Tax Authority [Member]
Deferred Tax Assets, Net, Classification [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	3,100
Valuation Allowance, Operating Loss Carryforwards [Member]
Components of Deferred Tax Assets and Liabilities [Abstract]
Valuation allowances	91	93
Deferred Tax Assets, Net, Classification [Abstract]
Deferred Tax Assets,Valuation Allowances	$ 91	$ 93

Property, Plant and Equipment C

Property, Plant and Equipment Classes and Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Accumulated depreciation, depletion and amortization	$ (10,851)	$ (8,369)
Public Utilities, Property, Plant and Equipment, Equipment	36,702	35,467
Land and land rights-of-way	1,450	1,324
Construction work in process	2,395	1,773
Property, plant and equipment, net	40,547	38,564
Public Utilities, Property, Plant and Equipment, Common	16,089	15,026
Depreciation, depletion and amortization	2,309	2,040	$ 1,806
Charged against PPE [Member]
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Depreciation, depletion and amortization	2,059	1,862	$ 1,663
Gas Transmission Equipment [Member]
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Pipelines (Natural gas, liquids, crude oil and CO2)	19,855	18,119
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)	22,979	21,233
Property, Plant and Equipment, Other Types [Member]
Public Utilities, Property, Plant and Equipment, Transmission and Distribution [Abstract]
Other(a)	$ 4,719	$ 4,484

Property, Plant and Equipment A

Property, Plant and Equipment Asset Retirement Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Asset Retirement Obligation	$ 215	$ 192
Asset Retirement Obligation, Current	$ 9	$ 7

Investments Equity investments

Investments Equity investments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Investment [Line Items]
Total equity investments	$ 6,032	$ 6,028
Held-to-maturity Securities	8	8
Long-term Investments	6,040	6,036
Citrus Corporation [Member]
Investment [Line Items]
Total equity investments	1,719	1,805
Ruby Pipeline Holding Company LLC [Member]
Investment [Line Items]
Total equity investments	1,093	1,123
Midcontinent Express Pipeline LLC [Member]
Investment [Line Items]
Total equity investments	713	748
Gulf LNG Holdings Group LLC [Member]
Investment [Line Items]
Total equity investments	516	547
EagleHawk Field Services [Member]
Investment [Line Items]
Total equity investments	348	337
Plantation Pipeline Company [Member]
Investment [Line Items]
Total equity investments	327	303
Watco Companies LLC [Member]
Investment [Line Items]
Total equity investments	201	103
Red Cedar Gathering company
Investment [Line Items]
Total equity investments	185	184
Double Eagle Pipeline LLC
Investment [Line Items]
Total equity investments	158	150
Kinder Morgan NGPL Holding LLC [Member]
Investment [Line Items]
Total equity investments	153	0
Parkway Pipeline LLC [Member]
Investment [Line Items]
Total equity investments	131	144
Fayetteville Express [Member]
Investment [Line Items]
Total equity investments	116	130
Fort Union Pipeline
Investment [Line Items]
Total equity investments	50	70
Sierrita Pipeline LLC [Member]
Investment [Line Items]
Total equity investments	60	63
Cortez Pipeline Company
Investment [Line Items]
Total equity investments	0	17
All Other Legal Entities [Member]
Investment [Line Items]
Total equity investments	$ 262	$ 304
Preferred stock | Watco Companies LLC [Member]
Investment [Line Items]
Quarterly preferred distribution rate	3.25%
Preferred Class B [Member] | Watco Companies LLC [Member]
Investment [Line Items]
Quarterly preferred distribution rate	3.00%

Investments Equity Earnings (De

Investments Equity Earnings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net Investment Income [Line Items]
Equity Method Investment, Other than Temporary Impairment	$ 30	$ 0	$ 65
Income (Loss) from Equity Method Investments	414	406	392
Income (loss) from Equity Method Investments, Net of Impairments	384	406	327
Amortization of excess costs	51	45	39
Citrus Corporation [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	96	97	84
Fayetteville Express [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	55	55	55
Gulf LNG Holdings Group LLC [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	49	48	47
Midcontinent Express Pipeline LLC [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	45	45	40
Red Cedar Gathering company
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	26	33	31
EagleHawk Field Services [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	24	(7)	9
Plantation Pipeline Company [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	29	29	35
Ruby Pipeline Holding Company LLC [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	18	15	(6)
Watco Companies LLC [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	16	13	13
Sierrita Pipeline LLC [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	9	3	0
Parkway Pipeline LLC [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	5	8	1
Double Eagle [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	3	(1)	1
Cortez Pipeline Company
Net Investment Income [Line Items]
Equity Method Investment, Other than Temporary Impairment	26
Income (Loss) from Equity Method Investments	(3)	25	24
Fort Union Pipeline
Net Investment Income [Line Items]
Equity Method Investment, Other than Temporary Impairment	20
Income (Loss) from Equity Method Investments	(4)	16	11
NGPL Holdco LLC(d)
Net Investment Income [Line Items]
Equity Method Investment, Other than Temporary Impairment		65
Income (Loss) from Equity Method Investments	0	0	(66)
All Other Legal Entities [Member]
Net Investment Income [Line Items]
Income (Loss) from Equity Method Investments	$ 16	$ 27	$ 48

Investments Investments (Detail

Investments Investments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)shares	Dec. 31, 2014shares
Schedule of Equity Method Investments [Line Items]
Preferred Stock, Value, Issued (Share)	1,600,000	0
Citrus Corporation
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Miles Of Pipeline	5,300
Ruby Pipeline Holding Company, L.L.C.
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
MEP
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%
EagleHawk
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	25.00%
Plantation Pipe Line Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	51.17%
Watco Companies, LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	7.20%
Profit participation rate	0.50%
common equity units	26,000
Red Cedar Gathering Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	49.00%
Double Eagle Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Kinder Morgan NGPL Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest | $	$ (136)
Payments to Acquire Other Investments | $	$ 17
Parkway Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
FEP
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%
Sierrita Gas Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	35.00%
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. | FEP
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Veresen Inc. [Member] | Ruby Pipeline Holding Company, L.L.C.
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%
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%
Myria Holdings, Inc. [Member] | Kinder Morgan NGPL Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	53.00%
Brookfield [Member] | Kinder Morgan NGPL Holdings 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. [Member] | Sierrita Gas Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	30.00%
Exxon Mobil Corporation [Member] | Cortez Pipeline Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	37.00%
Cortez Vickers Pipeline Company [Member] | Cortez Pipeline Company
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	13.00%
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%
Additional interest [Member] | Kinder Morgan NGPL Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	30.00%

Investments Summary of Signific

Investments Summary of Significant Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summarized Financial Information for Significant Equity Investments [Line Items]
Percent of investee information represented	100.00%
Equity Method Investment, Summarized Financial Information, Revenue	$ 3,857	$ 3,829	$ 3,615
Equity Method Investment, Summarized Financial Information, Cost of Sales	3,408	3,063	2,803
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	449	766	$ 812
Equity Method Investment, Summarized Financial Information, Current Assets	811	943
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	19,745	20,630
Equity Method Investment, Summarized Financial Information, Current Liabilities	1,009	1,643
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	11,227	10,841
Equity Method Investment, Summarized Financial Information, Equity Excluding Noncontrolling Interests	$ 8,320	$ 9,089

Goodwill Goodwill - Rollforward

Goodwill Goodwill - Rollforward (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 27, 2015
Goodwill [Line Items]
Historical Goodwill			$ 28,917,000,000
Accumulated impairment losses			4,413,000,000
Goodwill	$ 23,790,000,000	$ 24,654,000,000	24,504,000,000
Acquisitions(a)	321,000,000	171,000,000
Divestiture		2,000,000
Currency translation	35,000,000	19,000,000
Loss on impairment of goodwill	1,150,000,000	0	0
Natural Gas Pipelines Regulated
Goodwill [Line Items]
Historical Goodwill			17,527,000,000
Accumulated impairment losses			1,643,000,000
Goodwill	15,884,000,000	15,884,000,000	15,884,000,000
Acquisitions(a)	0	0
Divestiture		0
Currency translation	0	0
Loss on impairment of goodwill	0
Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Historical Goodwill			5,637,000,000
Accumulated impairment losses			447,000,000
Goodwill	4,215,000,000	5,272,000,000	5,190,000,000
Acquisitions(a)	93,000,000	82,000,000
Divestiture		0
Currency translation	0	0
Loss on impairment of goodwill	1,150,000,000
CO2
Goodwill [Line Items]
Historical Goodwill			1,528,000,000
Accumulated impairment losses			0
Goodwill	1,528,000,000	1,528,000,000	1,528,000,000
Acquisitions(a)	0	0
Divestiture		0
Currency translation	0	0
Loss on impairment of goodwill	0
Products Pipelines
Goodwill [Line Items]
Historical Goodwill			1,908,000,000
Accumulated impairment losses			1,197,000,000
Goodwill	928,000,000	711,000,000	711,000,000
Acquisitions(a)	217,000,000	0
Divestiture		0
Currency translation	0	0
Loss on impairment of goodwill	0
Products Pipelines Terminals
Goodwill [Line Items]
Historical Goodwill			221,000,000
Accumulated impairment losses			70,000,000
Goodwill	151,000,000	151,000,000	151,000,000
Acquisitions(a)	0	0
Divestiture		0
Currency translation	0	0
Loss on impairment of goodwill	0
Terminals
Goodwill [Line Items]
Historical Goodwill			1,486,000,000
Accumulated impairment losses			679,000,000
Goodwill	905,000,000	894,000,000	807,000,000
Acquisitions(a)	11,000,000	89,000,000
Divestiture		2,000,000
Currency translation	0	0
Loss on impairment of goodwill	0
Kinder Morgan Canada
Goodwill [Line Items]
Historical Goodwill			610,000,000
Accumulated impairment losses			377,000,000
Goodwill	179,000,000	214,000,000	$ 233,000,000
Acquisitions(a)	0	0
Divestiture		0
Currency translation	35,000,000	19,000,000
Loss on impairment of goodwill	0
KMP’s acquisition of Copano noncontrolling interests | Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Acquisitions(a)		82,000,000
APT and SCT [Member] | Terminals
Goodwill [Line Items]
Acquisitions(a)		$ 89,000,000
KMI Acquisition of Hiland Partners Holding LLC [Member] | Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Acquisitions(a)	93,000,000
KMI Acquisition of Hiland Partners Holding LLC [Member] | Products Pipelines
Goodwill [Line Items]
Acquisitions(a)	217,000,000
Vopak Terminal Assets [Member]
Goodwill [Line Items]
Goodwill				$ 7,000,000
Vopak Terminal Assets [Member] | Terminals
Goodwill [Line Items]
Acquisitions(a)	$ 7,000,000

Goodwill Goodwill (Details)

Goodwill Goodwill (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2015USD ($)Multiple	Jan. 01, 2021$ / MMBbls	Jan. 01, 2021$ / Bcf	Jan. 01, 2018$ / Unit	Jan. 01, 2016$ / MMBbls	Jan. 01, 2016$ / Bcf	Jan. 01, 2016$ / Unit
Goodwill [Line Items]
Marketable Securities | $		$ 0.36
Implied Control Premium		34.00%
Goodwill, Fair Value Disclosure | $		$ 0.12
Weighted Average Discount Rate, Percent	8.00%
Derivative, Basis Spread on Variable Rate		10000.00%
Fair Value Inputs, Discount Rate		5.00%
Forward commodity price curve		5 years
Term of projection		6 years
Derivative, Forward Price						38	2.50	0
Average spread		5 years
Rate of return		0.00%
Natural Gas Pipelines Regulated
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount		3.00%
Products Pipelines Terminals
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount		104.00%
CO2
Goodwill [Line Items]
EBITDA multiple | Multiple		7.9
Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
EBITDA multiple | Multiple		14
Goodwill, Fair Value Disclosure | $		$ 4,215,000,000
Carrying value of reporting unit | $		$ 19,000,000,000
Median enterprise value [Member] | CO2
Goodwill [Line Items]
EBITDA multiple | Multiple		12.7
Discounted cash flow analysis [Member] | CO2
Goodwill [Line Items]
EBITDA multiple | Multiple		4.1
Weighted Average [Member] | CO2
Goodwill [Line Items]
EBITDA multiple | Multiple		5.1
Market Approach Valuation Technique [Member] | Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount		18.00%
Income Approach Valuation Technique [Member] | Natural Gas Pipelines Non-Regulated
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount		4.00%
Goodwill, Fair Value Disclosure | $		$ 17,200,000,000
Subsequent Event [Member]
Goodwill [Line Items]
Derivative, Forward Price			65	3.50	0

Goodwill Allocation of Fair Val

Goodwill Allocation of Fair Value (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Fair Value [Line Items]
Goodwill	$ 0.12
Loss on impairment of goodwill	1,150,000,000	$ 0	$ 0
Natural Gas Pipelines Non-Regulated
Schedule of Fair Value [Line Items]
Working capital, net	232,000,000
Property, plant and equipment	9,627,000,000
Other intangible assets	3,121,000,000
Other liabilities, net	7,000,000
Goodwill	4,215,000,000
Estimated Reporting Unit Fair Value	17,188,000,000
Prior carrying amount of goodwill	5,365,000,000
Loss on impairment of goodwill	$ 1,150,000,000

Debt (Details)

Debt (Details) $ / shares in Units, $ in Millions	1 Months Ended		12 Months Ended
	Feb. 29, 2016USD ($)	Jan. 31, 2016USD ($)	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)	Sep. 30, 2015$ / shares	Feb. 13, 2015USD ($)	Jan. 01, 2015USD ($)	Nov. 26, 2014USD ($)
Debt Instrument [Line Items]
Reclassification of Debt Issuance Costs from Deferred Charges and Other Assets to Debt Fair Value Adjustments				$ 149
Preferred interest in general partner of KMP			$ 100	100
Debt, Current			821	2,717
Long-term debt			42,406	40,097
Long-term Debt, Current Maturities			1,000
Repayments of Debt			$ 15,116	$ 17,801	$ 12,393
Debt, Weighted Average Interest Rate			4.92%	5.02%
Preferred Stock, Liquidation Preference Per Share | $ / shares			$ 50
Value of preferred securities value assigned to debt			$ 197
Value of preferred securities value assigned to equity			$ 24
Preferred stock, shares outstanding (in shares) | shares			1,600,000	0
Debt fair value adjustments			$ 1,674	$ 1,785
Kinder Morgan, Inc. [Member]
Debt Instrument [Line Items]
Senior Notes									$ 6,000
Redemption price of debt as a percentage of face amount			100.00%
Line of Credit Facility, Current Borrowing Capacity			$ 4,000						4,000
Debt Instrument, Term			5 years
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | shares			1.100
Kinder Morgan, Inc. [Member] | Senior unsecured revolving credit facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding			$ 0	850
Kinder Morgan, Inc. [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial Paper			0	386
Commercial Paper, Current Borrowing Capacity			4,000						$ 4,000
Subsidiary Issuer and Guarantor - Copano
Debt Instrument [Line Items]
Long-term Debt			332
Long-term debt			378	386
Long-term Debt, Current Maturities			0	0
Repayments of Debt			$ 0	0	$ 854
Colorado Interstate Gas Company, L.L.C. [Member]
Debt Instrument [Line Items]
Construction Costs Funded			50.00%
Capital Trust I [Member]
Debt Instrument [Line Items]
Trust Convertible Preferred Securities Outstanding | shares			4,400,000
Kinder Morgan G.P., Inc. [Member]
Debt Instrument [Line Items]
Preferred stock, shares outstanding (in shares) | shares			100,000
Preferred Stock, Dividend Rate, Percentage			3.8975%
Kinder Morgan, Inc and Subsidiaries [Member]
Debt Instrument [Line Items]
Long-term Debt			$ 41,553	41,029
Long-term debt			$ 40,732	38,312
Capital Trust [Member]
Debt Instrument [Line Items]
Equity Method Investment, Ownership Percentage			100.00%
KMI Senior Notes,1.50% through 8.25%, due 2015 through 2098 [Member] [Member] | Kinder Morgan, Inc. [Member]
Debt Instrument [Line Items]
Senior Notes			$ 13,346	11,438
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum			1.50%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum			8.25%
KMP Senior notes, 2.65% through 9.00%, due 2014 through 2044 [Member] | Kinder Morgan Energy Partners, L.P. [Member]
Debt Instrument [Line Items]
Senior Notes			$ 19,985	20,660
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum			2.65%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum			9.00%
KMP Senior notes, 7.00% through 8.375%, due 2016 through 2037 [Member] | TGP [Member]
Debt Instrument [Line Items]
Senior Notes			$ 1,790	1,790
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum			7.00%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum			8.375%
KMP 5.95% through 8.625%, due 2017 through 2032 [Member] [Member] | EPNG [Member]
Debt Instrument [Line Items]
Senior Notes			$ 1,115	1,115
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum			5.95%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum			8.625%
KMP 7.125% Senior Notes due April 1, 2021 (Copano) [Member] | Subsidiary Issuer and Guarantor - Copano
Debt Instrument [Line Items]
Senior Notes			$ 332	332
Interest rate, stated percentage			7.125%
EPB Notes, 5.95% through 6.85%, due 2015 through 2037 [Member] | Colorado Interstate Gas Company, L.L.C. [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum			5.95%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum			6.85%
EPB Notes, 6.85%, due 2037 [Member] | Colorado Interstate Gas Company, L.L.C. [Member]
Debt Instrument [Line Items]
Senior Notes			$ 100	475
KMP Notes, 4.40% through 8.00%, due 2017 through 2032 [Member] | SNG [Member]
Debt Instrument [Line Items]
Notes Payable			$ 1,211	1,211
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum			4.40%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum			8.00%
KMI 5.70% through 6.40% series, due 2016 through 2036 [Member] | Kinder Morgan Finance Company, LLC [Member]
Debt Instrument [Line Items]
Senior Notes			$ 1,636	1,636
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum			5.70%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum			6.40%
KMI Senior Notes, 5.50% and 7.25%, due 2020 and 2022 [Member] | Hiland Partners Holding LLC [Member]
Debt Instrument [Line Items]
Senior Notes			$ 974	0			$ 975
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum			5.50%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum			7.25%
KMI Promissory note 3.967%, due 2015 through 2035 [Member] [Member] | EPC Building LLC [Member]
Debt Instrument [Line Items]
Notes Payable			$ 443	453
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			$ 0	0
KMI EP Capital Trust I 4.75%, due 2028 [Member] | Capital Trust I [Member]
Debt Instrument [Line Items]
Senior Notes			221	280
Long-term Debt, Current Maturities			$ 111
Interest rate, stated percentage			4.75%
KMI $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock [Member] | Kinder Morgan G.P., Inc. [Member]
Debt Instrument [Line Items]
Preferred interest in general partner of KMP			$ 100	100
Preferred stock, par value (in dollars per share) | $ / shares			$ 1,000			$ 1,000
Other Miscellaneous Subsidiary Debt [Member] | KMI, KMP and EPB [Member]
Debt Instrument [Line Items]
Notes Payable			$ 300	$ 303
KMI Credit Facility [Member] | Kinder Morgan, Inc. [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				1.541%
5.70% Senior Notes due January 5, 2016 [Member] | Kinder Morgan Finance Company, LLC [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage			5.70%
TGP 8.00% Senior Notes due February 1, 2016 [Member] | TGP [Member]
Debt Instrument [Line Items]
Interest rate, stated percentage			8.00%
Senior unsecured term loan facility, variable, due 2019 [Member] | Kinder Morgan, Inc. [Member]
Debt Instrument [Line Items]
Debt Instrument, Term			3 years
Capital Trust [Member]
Debt Instrument [Line Items]
Conversion of Stock, Shares Converted | shares			1,176,015	3,923
Totem [Member] | El Paso Pipeline Partners, L.P. [Member]
Debt Instrument [Line Items]
Capital Lease Obligations			$ 72
High Plains [Member] | El Paso Pipeline Partners, L.P. [Member]
Debt Instrument [Line Items]
Capital Lease Obligations			$ 96
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 | $ / shares			$ 25.18
Class P | Capital Trust [Member]
Debt Instrument [Line Items]
EP Trust I Preferred security conversions | shares			846,369	2,820
Warrant [Member] | Capital Trust [Member]
Debt Instrument [Line Items]
Debt Conversion, Converted Instrument, Warrants or Options Issued | shares			1,293,615	4,315
Financial Guarantee [Member] | Kinder Morgan Energy Partners, L.P. [Member]
Debt Instrument [Line Items]
Indemnified by parent of subsidiary debt								$ 2,900
Euro Member Countries, Euro | Senior Notes [Member]
Debt Instrument [Line Items]
Foreign Currency Exchange Rate, Translation			1.0862				1.086
Translation Adjustment Functional to Reporting Currency, Increase (Decrease), Gross of Tax			$ 1
Repayments of debt [Member] | 5.70% Senior Notes due January 5, 2016 [Member] | Kinder Morgan Finance Company, LLC [Member]
Debt Instrument [Line Items]
Repayments of Debt		$ 850
Repayments of debt [Member] | TGP 8.00% Senior Notes due February 1, 2016 [Member] | TGP [Member]
Debt Instrument [Line Items]
Repayments of Debt	$ 250
Refinance of Debt [Member] | 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
Refinance of Debt [Member] | TGP 8.00% Senior Notes due February 1, 2016 [Member] | TGP [Member]
Debt Instrument [Line Items]
Short-term Debt, Refinanced, Amount		$ 150

Credit Facilities and Restricti

Credit Facilities and Restrictive Covenants (Details) - Kinder Morgan, Inc. [Member] $ in Millions	Feb. 13, 2015USD ($)	Dec. 31, 2015USD ($)	Jan. 26, 2016USD ($)	Dec. 31, 2014USD ($)	Nov. 26, 2014USD ($)
Line of Credit Facility [Line Items]
Debt Instrument, Term		5 years
Line of Credit Facility, Current Borrowing Capacity		$ 4,000			$ 4,000
Line of Credit Facility, Maximum Borrowing Capacity Increase					5,000
Letters of Credit Outstanding, Amount		115
Remaining borrowing capacity		3,885
Senior unsecured revolving credit facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Amount Outstanding		0		$ 850
Commercial Paper [Member]
Line of Credit Facility [Line Items]
Commercial Paper, Current Borrowing Capacity		4,000			$ 4,000
Commercial Paper		$ 0		$ 386
Bridge Loan [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Term	6 months
Line of Credit Facility, Maximum Amount Outstanding During Period	$ 1,641
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%
LIBOR Alternate Base Rate [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.00%
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
Federal Funds Rate [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.50%
Increase in Credit Facility Capacity [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity Increase			$ 5,000

Debt Hiland Debt Acquired (Deta

Debt Hiland Debt Acquired (Details) - USD ($) $ in Millions	Feb. 13, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Repayments of Debt		$ 15,116	$ 17,801	$ 12,393
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	$ 974	$ 0
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
Hiland Partners, LP [Member]
Debt Instrument [Line Items]
Repayments of Debt	$ 368

Debt Long-term Debt Issuances a

Debt Long-term Debt Issuances and Repayments (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Feb. 29, 2016	Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt, Current Maturities			$ 1,000
Repayments of Debt			$ 15,116	$ 17,801	$ 12,393
EPB 4.30% Senior Notes due May 1, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.30%
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%
TGP [Member] | TGP 8.00% Senior Notes due February 1, 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			8.00%
Kinder Morgan, Inc. [Member] | Senior unsecured term loan facility, variable, due May 6, 2017 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt				650
Repayments of Debt				$ 650
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] | 2% Senior Notes Due 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				2.00%
Proceeds from Issuance of Long-term Debt				$ 500
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] | 3.05% Senior Notes due December 1, 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				3.05%
Proceeds from Issuance of Long-term Debt				$ 1,500
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] | 4.30% Senior Notes due June1, 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.30%
Proceeds from Issuance of Long-term Debt				$ 1,500
Kinder Morgan, Inc. [Member] | 5.30% Senior Notes due December 1, 2034 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				5.30%
Proceeds from Issuance of Long-term Debt				$ 750
Kinder Morgan, Inc. [Member] | 5.55% Senior Notes due June 1, 2045 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				5.55%
Proceeds from Issuance of Long-term Debt				$ 1,750
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
Kinder Morgan, Inc. [Member] | 6.875% Senior Notes due June 15,2014 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				6.875%
Repayments of Debt				$ 207
Kinder Morgan Energy Partners, L.P. [Member] | KMP 3.50% Senior Notes due March 1, 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				3.50%
Proceeds from Issuance of Long-term Debt				$ 750
Kinder Morgan Energy Partners, L.P. [Member] | KMP 5.50% Senior Notes due March 1, 2044 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				5.50%
Proceeds from Issuance of Long-term Debt				$ 750
Kinder Morgan Energy Partners, L.P. [Member] | KMP 4.25% Senior Notes due September 1, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.25%
Proceeds from Issuance of Long-term Debt				$ 650
Kinder Morgan Energy Partners, L.P. [Member] | KMP 5.40% Senior Notes due September 1, 2044 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				5.40%
Proceeds from Issuance of Long-term Debt				$ 550
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
Kinder Morgan Energy Partners, L.P. [Member] | 5.125% senior notes due November 15, 2014 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				5.125%
Repayments of Debt				$ 500
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
El Paso Pipeline Partners Operating Company, L.L.C. [Member] | EPB 4.30% Senior Notes due May 1, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.30%
Proceeds from Issuance of Long-term Debt				$ 600
Subsidiary Issuer and Guarantor - Copano
Debt Instrument [Line Items]
Long-term Debt, Current Maturities			0	0
Repayments of Debt			$ 0	0	$ 854
Subsidiary Issuer and Guarantor - Copano | KMP 7.125% Senior Notes due April 1, 2021 (Copano) [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			7.125%
Senior secured term loan credit facility, due May 24, 2015 [Member] | Kinder Morgan, Inc. [Member]
Debt Instrument [Line Items]
Repayments of Debt				$ 1,528
Increase in long term debt [Member] | Senior unsecured term loan facility, variable, due May 6, 2017 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt		$ 1,000
Repayments of debt [Member] | Kinder Morgan Finance Company, LLC [Member] | 5.70% Senior Notes due January 5, 2016 [Member]
Debt Instrument [Line Items]
Repayments of Debt		$ 850
Repayments of debt [Member] | TGP [Member] | TGP 8.00% Senior Notes due February 1, 2016 [Member]
Debt Instrument [Line Items]
Repayments of Debt	$ 250

Debt Maturities of Debt (Detail

Debt Maturities of Debt (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Senior Notes, Current	$ 667
Long-term Debt, Current Maturities	1,000
Kinder Morgan, Inc. [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	821
Long-term Debt, Maturities, Repayments of Principal in Year Two	3,060
Long-term Debt, Maturities, Repayments of Principal in Year Three	2,329
Long-term Debt, Maturities, Repayments of Principal in Year Four	3,819
Long-term Debt, Maturities, Repayments of Principal in Year Five	2,953
Long-term Debt, Maturities, Repayments of Principal after Year Five	28,571
Total debt outstanding	$ 41,553
Debt Instrument, Term	5 years
Senior unsecured term loan facility, variable, due 2019 [Member] | Kinder Morgan, Inc. [Member]
Debt Instrument [Line Items]
Debt Instrument, Term	3 years
KMI EP Capital Trust I 4.75%, due 2028 [Member] | Capital Trust I [Member]
Debt Instrument [Line Items]
Long-term Debt, Current Maturities	$ 111

Debt Debt Fair Value Adjustment

Debt Debt Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Amortization Period of Deferred Gain (Loss) on Discontinuation of Fair Value Hedge	16 years
Debt Fair Value Adjustments	$ 1,674	$ 1,785
Amount the adjustment to fair value of debt was increased by related to the fair value of interest rate swaps	380	347
Deferred Gain (Loss) on Discontinuation of Interest Rate Fair Value Hedge	397	454
Unamortized Debt Issuance Costs [Member]
Debt Instrument [Line Items]
Debt Fair Value Adjustments	(152)	(149)
Unamortized Debt Discount Amounts [Member]
Debt Instrument [Line Items]
Debt Fair Value Adjustments	(86)	(88)
Purchase Accounting [Member]
Debt Instrument [Line Items]
Debt Fair Value Adjustments	$ 1,135	$ 1,221

Debt Interest Rates, Interest R

Debt Interest Rates, Interest Rate Swaps and Contingent Debt (Details)	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt, Weighted Average Interest Rate	4.92%	5.02%

Share-based Compensation and 84

Share-based Compensation and Employee Benefits Share-based Compensation (Details) - Restricted Stock [Member] - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014
Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors [Member] | Six Month Vesting Period [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock vested, percent				100.00%
Stock Compensation Plan for Non-Employee Directors [Member] | Class P
Stock Compensation Plan for Non-Employee Directors [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized				250,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	6 months
Stock Compensation Plan for Non-Employee Directors [Member] | Class P | Six Month Vesting Period [Member]
Stock Compensation Plan for Non-Employee Directors [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures	9,580	6,210	5,710
Stock Issued During Period, Value, Share-based Compensation, Net of Forfeitures	$ 401,000	$ 220,000	$ 210,000
Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at beginning of year (shares)	7,373,294	6,382,885	2,154,022
Outstanding at beginning of year	$ 277,000,000	$ 239,000,000	$ 69,000,000
Granted (shares)	1,488,467	1,694,668	4,563,495
Granted	$ 57,000,000	$ 61,000,000	$ 181,000,000
Vested (shares)	(817,797)	(460,032)	(83,444)
Vested	$ (29,000,000)	$ (14,000,000)	$ (3,000,000)
Forfeited (shares)	(398,859)	(244,227)	(251,188)
Forfeited	$ (15,000,000)	$ (9,000,000)	$ (8,000,000)
Outstanding at end of year (shares)	7,645,105	7,373,294	6,382,885
Outstanding at beginning of year	$ 290,000,000	$ 277,000,000	$ 239,000,000
Intrinsic value of restricted stock vested during the period	$ 31,000,000	$ 17,000,000	$ 3,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	7,373,294	6,382,885	2,154,022	7,645,105	7,373,294
Restricted Stock or Unit Expense	$ 67,000,000	$ 57,000,000	$ 35,000,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options				$ 154,000,000	$ 170,000,000
Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan [Member] | Year 2016 [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (shares)	1,096,290
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	1,096,290			1,096,290
Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan [Member] | Year 2017 [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (shares)	1,563,549
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	1,563,549			1,563,549
Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan [Member] | Year 2018 [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (shares)	2,443,888
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	2,443,888			2,443,888
Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan [Member] | Year 2019 [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (shares)	1,688,831
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	1,688,831			1,688,831
Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan [Member] | Year 2020 [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (shares)	585,574
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	585,574			585,574
Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan [Member] | Thereafter [Member]
Restricted Stock and Long-term Incentive Retention Award Plan [Abstract]
Outstanding at end of year (shares)	266,973
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Restricted stock future vesting schedule (shares)	266,973			266,973
Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [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] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [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	5 Months Ended	7 Months Ended	12 Months Ended
	Dec. 31, 2013USD ($)	Jul. 31, 2013	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	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			$ 28
Defined Benefit Plan, Future Amortization of Gain (Loss)			(29)
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			$ 46	$ 42	$ 40
Pension Plan [Member]
Pension Plans [Abstract]
Defined Benefit Plan,Vesting Period			3 years
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			$ 2,804	2,563
Defined Benefit Plan, Service Cost			33	21	25
Defined Benefit Plan, Interest Cost			99	112	92
Defined Benefit Plan, Actuarial (Gain) Loss			(109)	294
Defined Benefit Plan, Benefits Paid			(173)	(186)
Defined Benefit Plan, Contributions by Plan Participants			0	0
Defined Benefit Plan, Medicare Part D Subsidy Receipts			0	0
Defined Benefit Plan, Benefit Obligation	$ 2,563		2,654	2,804	2,563
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			2,377	2,333
Defined Benefit Plan, Actual (Loss) Return on Plan Assets			(204)	180
Defined Benefit Plan, Contributions by Employer			50	50
Defined Benefit Plan, Contributions by Plan Participants			0	0
Defined Benefit Plan, Medicare Part D Subsidy Receipts			0	0
Defined Benefit Plan, Fair Value of Plan Assets	$ 2,333		2,050	2,377	2,333
Defined Benefit Plan, Funded Status of Plan			(604)	(427)
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			(604)	(427)
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax			(558)	(296)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax			(4)	(4)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax			(562)	(300)
Defined Benefit Plan, Future Amortization of Gain (Loss)			(5)	0	$ 0
Defined Benefit Plan, Accumulated Benefit Obligation			2,615	$ 2,719
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, 2016			230
Defined Benefit Plan, Expected Future Benefit Payments, 2017			197
Defined Benefit Plan, Expected Future Benefit Payments, 2018			196
Defined Benefit Plan, Expected Future Benefit Payments, 2019			198
Defined Benefit Plan, Expected Future Benefit Payments, 2020			197
Defined Benefit Plan, Expected Future Benefit Payments, 2021-2025			$ 962
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.45%		4.05%	3.66%	4.45%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.50%		3.50%	4.50%	3.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate			3.66%	4.45%	3.40%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets			7.50%	7.50%	8.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase			4.50%	3.50%	3.00%
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income [Abstract]
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)			$ 0	$ 0	$ 0
Defined Benefit Plan, Expected Return on Plan Assets			(172)	(171)	(175)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements and Curtailments			0	0	(3)
Defined Benefit Plan, Net Periodic Benefit Cost			(35)	(38)	(61)
Other comprehensive income defined benefit plan net loss gain arising during period			267	285	(211)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax			0	0	25
Other comprehensive income defined benefit plan amortization of net actuarial gain loss			(5)	0	3
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), 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			262	285	(183)
Total Net benefit cost and other comprehensive income (loss) recognized			227	247	(244)
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			535
Defined Benefit Plan, Fair Value of Plan Assets			356	535
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Money Market Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			5
Defined Benefit Plan, Fair Value of Plan Assets			15	5
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Insurance Contract, Rights and Obligations [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			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			71
Defined Benefit Plan, Fair Value of Plan Assets			70	71
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			459
Defined Benefit Plan, Fair Value of Plan Assets			271	459
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | US Government Agencies Debt Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Asset-backed Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Class P | Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			252
Defined Benefit Plan, Fair Value of Plan Assets			91	252
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			556
Defined Benefit Plan, Fair Value of Plan Assets			559	556
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Money Market Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			91
Defined Benefit Plan, Fair Value of Plan Assets			110	91
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Insurance Contract, Rights and Obligations [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
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			0
Defined Benefit Plan, Fair Value of Plan Assets			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			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			247
Defined Benefit Plan, Fair Value of Plan Assets			244	247
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | US Government Agencies Debt Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			190
Defined Benefit Plan, Fair Value of Plan Assets			171	190
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Asset-backed Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			28
Defined Benefit Plan, Fair Value of Plan Assets			34	28
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
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			0	26
Defined Benefit Plan, Fair Value of Plan Assets	$ 26		1	0	26
Changes in Pension and OPEB Assets [Abstract]
Defined Benefit Plan, Transfers Between Measurement Levels			0	0
Gain (Loss) on Investments			(2)	(18)
Defined Benefit Plan, Purchases, Sales, and Settlements			3	(8)
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Money Market Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Insurance Contract, Rights and Obligations [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			15	15
Defined Benefit Plan, Fair Value of Plan Assets	15		15	15	15
Changes in Pension and OPEB Assets [Abstract]
Defined Benefit Plan, Transfers Between Measurement Levels			0	0
Gain (Loss) on Investments			0	0
Defined Benefit Plan, Purchases, Sales, and Settlements			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			0
Defined Benefit Plan, Fair Value of Plan Assets			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			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | US Government Agencies Debt Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Asset-backed Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			(15)	11
Defined Benefit Plan, Fair Value of Plan Assets	11		(14)	(15)	11
Changes in Pension and OPEB Assets [Abstract]
Defined Benefit Plan, Transfers Between Measurement Levels			0	0
Gain (Loss) on Investments			(2)	(18)
Defined Benefit Plan, Purchases, Sales, and Settlements			3	(8)
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation			624	631
Defined Benefit Plan, Service Cost			0	0	0
Defined Benefit Plan, Interest Cost			21	25	23
Defined Benefit Plan, Actuarial (Gain) Loss			(101)	15
Defined Benefit Plan, Benefits Paid			(39)	(52)
Defined Benefit Plan, Contributions by Plan Participants			2	3
Defined Benefit Plan, Medicare Part D Subsidy Receipts			2	2
Defined Benefit Plan, Benefit Obligation	631		509	624	631
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			389	380
Defined Benefit Plan, Actual (Loss) Return on Plan Assets			(45)	32
Defined Benefit Plan, Contributions by Employer			16	25
Defined Benefit Plan, Contributions by Plan Participants			2	3
Defined Benefit Plan, Medicare Part D Subsidy Receipts			2	1
Defined Benefit Plan, Fair Value of Plan Assets	$ 380		325	389	380
Defined Benefit Plan, Funded Status of Plan			(184)	(235)
Components of Funded Status [Abstract]
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent			139	173
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities			(16)	(22)
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent			(307)	(386)
Components of Accumulated Other Comprehensive Income (Loss) [Abstract]
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax			23	(27)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax			19	20
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax			42	(7)
Defined Benefit Plan, Future Amortization of Gain (Loss)			(1)	1	$ (3)
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation			444	553
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets			121	$ 145
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, 2016			39
Defined Benefit Plan, Expected Future Benefit Payments, 2017			39
Defined Benefit Plan, Expected Future Benefit Payments, 2018			39
Defined Benefit Plan, Expected Future Benefit Payments, 2019			39
Defined Benefit Plan, Expected Future Benefit Payments, 2020			38
Defined Benefit Plan, Expected Future Benefit Payments, 2021-2025			182
Defined Benefit Plan, Expected Future Benefit Payments, Next Fiscal Year			$ 14
Actuarial Assumptions and Sensitivity Analysis [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.34%		3.91%	3.56%	4.34%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.00%	3.34%	3.56%	4.34%	3.62%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets			7.08%	7.43%	7.35%
After-tax expected return on plan assets, used to determine benefit cost	24.00%		21.00%	21.00%	24.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year			9.89%
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			$ 2	$ 2
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation			31	47
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components			(1)	(2)
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation			(27)	(40)
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income [Abstract]
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)			(3)	(2)	$ (1)
Defined Benefit Plan, Expected Return on Plan Assets			(23)	(24)	(22)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements and Curtailments			0	0	0
Defined Benefit Plan, Net Periodic Benefit Cost			(4)	(2)	3
Other comprehensive income defined benefit plan net loss gain arising during period			(49)	10	(50)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax			0	0	(18)
Other comprehensive income defined benefit plan amortization of net actuarial gain loss			(1)	0	(3)
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax			1	1	1
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax			(49)	11	(70)
Total Net benefit cost and other comprehensive income (loss) recognized			(53)	9	(67)
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			99
Defined Benefit Plan, Fair Value of Plan Assets			60	99
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Money Market Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			(3)
Defined Benefit Plan, Fair Value of Plan Assets			0	(3)
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Domestic Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			14
Defined Benefit Plan, Fair Value of Plan Assets			8	14
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Insurance Contract, Rights and Obligations [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			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			1
Defined Benefit Plan, Fair Value of Plan Assets			1	1
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Limited Partnership [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			87
Defined Benefit Plan, Fair Value of Plan Assets			51	87
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			26
Defined Benefit Plan, Fair Value of Plan Assets			16	26
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Money Market Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			26
Defined Benefit Plan, Fair Value of Plan Assets			16	26
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Domestic Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Insurance Contract, Rights and Obligations [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
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			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Limited Partnership [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			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			51
Defined Benefit Plan, Fair Value of Plan Assets			49	51
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Money Market Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Domestic Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Insurance Contract, Rights and Obligations [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			51	50
Defined Benefit Plan, Fair Value of Plan Assets	$ 50		49	51	$ 50
Changes in Pension and OPEB Assets [Abstract]
Defined Benefit Plan, Transfers Between Measurement Levels			0	0
Gain (Loss) on Investments			(1)	(4)
Defined Benefit Plan, Purchases, Sales, and Settlements			(1)	5
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			0
Defined Benefit Plan, Fair Value of Plan Assets			0	0
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 3 [Member] | Limited Partnership [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			0
Defined Benefit Plan, Fair Value of Plan Assets			$ 0	$ 0
Other Postretirement Benefit Plan [Member] | Fixed Income Securities [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			33.00%	33.00%
Other Postretirement Benefit Plan [Member] | Equity Securities [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			67.00%	67.00%
Minimum [Member] | Pension Plan [Member] | Cash [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			0.00%
Minimum [Member] | Pension Plan [Member] | Fixed Income Securities [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			37.00%
Minimum [Member] | Pension Plan [Member] | Equity Securities [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			34.00%
Minimum [Member] | Pension Plan [Member] | Equity Securities [Member] | Class P
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			0.00%
Minimum [Member] | Pension Plan [Member] | Other Investments [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			0.00%
Minimum [Member] | Other Postretirement Benefit Plan [Member] | Cash [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			0.00%
Minimum [Member] | Other Postretirement Benefit Plan [Member] | Fixed Income Securities [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			15.00%
Minimum [Member] | Other Postretirement Benefit Plan [Member] | Master Limited Partnerships [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			13.00%
Minimum [Member] | Other Postretirement Benefit Plan [Member] | Equity Securities [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			15.00%
Maximum [Member] | Pension Plan [Member] | Cash [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			5.00%
Maximum [Member] | Pension Plan [Member] | Fixed Income Securities [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			57.00%
Maximum [Member] | Pension Plan [Member] | Equity Securities [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			59.00%
Maximum [Member] | Pension Plan [Member] | Equity Securities [Member] | Class P
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			10.00%
Maximum [Member] | Pension Plan [Member] | Other Investments [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			2.00%
Maximum [Member] | Other Postretirement Benefit Plan [Member] | Cash [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			19.00%
Maximum [Member] | Other Postretirement Benefit Plan [Member] | Fixed Income Securities [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			47.00%
Maximum [Member] | Other Postretirement Benefit Plan [Member] | Master Limited Partnerships [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			38.00%
Maximum [Member] | Other Postretirement Benefit Plan [Member] | Equity Securities [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			56.00%
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			$ 1,091
Defined Benefit Plan, Fair Value of Plan Assets			916	$ 1,091
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Money Market Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			96
Defined Benefit Plan, Fair Value of Plan Assets			125	96
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Insurance Contract, Rights and Obligations [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			15
Defined Benefit Plan, Fair Value of Plan Assets			15	15
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			71
Defined Benefit Plan, Fair Value of Plan Assets			70	71
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			459
Defined Benefit Plan, Fair Value of Plan Assets			271	459
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			247
Defined Benefit Plan, Fair Value of Plan Assets			244	247
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | US Government Agencies Debt Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			190
Defined Benefit Plan, Fair Value of Plan Assets			171	190
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Asset-backed Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			28
Defined Benefit Plan, Fair Value of Plan Assets			34	28
Within Fair Value Hierarchy [Member] | Pension Plan [Member] | Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			(15)
Defined Benefit Plan, Fair Value of Plan Assets			(14)	(15)
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			176
Defined Benefit Plan, Fair Value of Plan Assets			125	176
Within Fair Value Hierarchy [Member] | Other Postretirement Benefit Plan [Member] | Money Market Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			23
Defined Benefit Plan, Fair Value of Plan Assets			16	23
Within Fair Value Hierarchy [Member] | Other Postretirement Benefit Plan [Member] | Domestic Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			14
Defined Benefit Plan, Fair Value of Plan Assets			8	14
Within Fair Value Hierarchy [Member] | Other Postretirement Benefit Plan [Member] | Insurance Contract, Rights and Obligations [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			51
Defined Benefit Plan, Fair Value of Plan Assets			49	51
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			1
Defined Benefit Plan, Fair Value of Plan Assets			1	1
Within Fair Value Hierarchy [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			87
Defined Benefit Plan, Fair Value of Plan Assets			51	87
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			1,286
Defined Benefit Plan, Fair Value of Plan Assets			1,134	1,286
Fair Value, Net Asset Value as Practical Expedient [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			198
Defined Benefit Plan, Fair Value of Plan Assets			160	198
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			863
Defined Benefit Plan, Fair Value of Plan Assets			775	863
Fair Value, Net Asset Value as Practical Expedient [Member] | Pension Plan [Member] | Equity Trusts [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			199
Defined Benefit Plan, Fair Value of Plan Assets			187	199
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			13
Defined Benefit Plan, Fair Value of Plan Assets			1	13
Fair Value, Net Asset Value as Practical Expedient [Member] | Pension Plan [Member] | Private Equity Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			13
Defined Benefit Plan, Fair Value of Plan Assets			$ 11	$ 13
Fair Value, Net Asset Value as Practical Expedient [Member] | Pension Plan [Member] | Fixed Income Securities [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			45.00%	47.00%
Fair Value, Net Asset Value as Practical Expedient [Member] | Pension Plan [Member] | Equity Securities [Member] | Common collective trusts [Member]
Plan Assets [Abstract]
Defined Benefit Plan, Actual Plan Asset Allocations			55.00%	53.00%
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			$ 213
Defined Benefit Plan, Fair Value of Plan Assets			200	$ 213
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			71
Defined Benefit Plan, Fair Value of Plan Assets			71	71
Fair Value, Net Asset Value as Practical Expedient [Member] | Other Postretirement Benefit Plan [Member] | Fixed Income Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets			63
Defined Benefit Plan, Fair Value of Plan Assets			58	63
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			79
Defined Benefit Plan, Fair Value of Plan Assets			71	$ 79
2016 - 2020 [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
2020 - 2025 [Member] | Other Postretirement Benefit Plan [Member]
Expected Payment of Future Benefits and Employer Contributions [Abstract]
Medicare prescription drug, improvement and modernization act, annual subsidy			$ 18

Share-based Compensation and 86

Share-based Compensation and Employee Benefits Other Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Trans Mountain Pipeline [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	$ 12	$ 10	$ 11
Defined Benefit Plan, Net Periodic Benefit Cost, next twelve months	10
Expected Defined Benefit Pension and OPEB contribution, next twelve months	10
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	$ 10	$ 13	$ 11

Common Equity (Details)

Common Equity (Details) $ / shares in Units, $ in Millions	Jan. 21, 2016$ / shares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)$ / sharesshares	Dec. 19, 2014USD ($)	Dec. 31, 2012shares
Class of Stock [Line Items]
Warrant Repurchase Program, Remaining Authorized Repurchase Amount | $		$ 90
Payments for Repurchase of Warrants | $		$ 12	$ 98	$ 465
Dividends Per Common Share Declared for the Period | $ / shares		$ 1.605	$ 1.740	$ 1.600
Debt Instrument, Convertible, Conversion Ratio		1
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ / shares		$ 40
Class of Warrant or Right, Outstanding		293,263,797	298,135,976	347,933,107		439,809,442
Warrants Exercised, Number of Warrants		(71,268)	(18,040)	(21,208)
Number of warrants repurchased		(6,094,526)	(49,783,406)	(91,973,585)
Share Settlement of Dissenter				128
Class P
Class of Stock [Line Items]
Payments for Repurchase of Common Stock | $			$ 94	$ 172
Share issued (in shares)		103,000,000
Issuances of common shares | $		$ 3,870
Dividends Per Common Share Declared for the Period | $ / shares		$ 1.605	$ 1.740	$ 1.600
Common Stock, Dividends, Per Share, Cash Paid | $ / shares		$ 1.93	$ 1.70	$ 1.56
KMI's Acquisition of EP [Member]
Class of Stock [Line Items]
Warrants issued during the period		0	0	81
Dividend Declared [Member]
Class of Stock [Line Items]
Dividends Per Common Share Declared for the Period | $ / shares	$ 0.125
Kinder Morgan, Inc. [Member] | Warrant [Member] | El Paso Corporation [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 during the period		1,293,615	4,315	118,377
Equity distribution agreement [Member] | Class P
Class of Stock [Line Items]
Value of Stock Available for Sale Under Equity Distribution Agreement | $					$ 5,000
Share issued (in shares)		102,614,508
Stock Sold During the Period, 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	Nov. 18, 2015$ / shares	Oct. 30, 2015USD ($)$ / sharesshares	Dec. 31, 2015$ / sharesshares	Dec. 31, 2014$ / shares
Class of Stock [Line Items]
Depositary Share Offering | shares		32,000,000
Amount of Interest Each Depositary Share has in a 9.75% Series A Mandatory Convertible Preferred Share			0.0005
Preferred Stock, Liquidation Preference Per Share			$ 50
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, Liquidation Preference Per Share		$ 1,000	$ 1,000	$ 0
Preferred Stock, Dividend Rate, Percentage			9.75%	0.00%
Dividends, Preferred Stock	$ 23.291667
Depositary Stock, Dividends Per Share, Declared	$ 1.164583
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, 2015	Dec. 31, 2014	Dec. 31, 2013
Contributions from noncontrolling interests		$ 11	$ 1,767	$ 1,706
Impact from equity transactions of KMP, EPB and KMR
Contributions from noncontrolling interests	$ 1,695			1,580
Noncontrolling Interest, Increase from Subsidiary Equity Issuance	1,640			5,059
Income Tax Effects Allocated Directly to Equity, Equity Transactions	19			93
Adjustments to Additional Paid in Capital, Other	$ 36			$ 161
KMP(a)
Per unit cash distribution declared for the period			$ 4.17	$ 5.33
Per unit cash distribution paid in the period			$ 5.53	$ 5.26
Cash distributions paid in the period to the public			$ 1,654	$ 1,372
EPB(a)
Per unit cash distribution declared for the period			$ 1.95	$ 2.55
Per unit cash distribution paid in the period			$ 2.60	$ 2.51
Cash distributions paid in the period to the public			$ 347	$ 318
KMR(a)(b)
Share distributions paid in the period to the public			7,794,183	6,588,477
Subsidiary Share Distribution, Shares Distributed to Parent			1,127,712	976,723
Equity distribution agreement [Member] | Impact from equity transactions of KMP, EPB and KMR
Noncontrolling Interest, Shares or Equity Units Issued			30,000,000	63,000,000

Related Party Transactions Affi

Related Party Transactions Affiliated Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
RELATED PARTY ASSETS
Other current assets	$ 366	$ 746
Deferred charges and other assets	2,029	2,090
RELATED PARTY LIABILITIES [Abstract]
Other current liabilities	927	1,037
RELATED PARTY REVENUES [Abstract]
Services	8,290	7,650	$ 6,677
Product sales and other	3,274	4,461	3,788
Total Revenues	14,403	16,226	14,070
RELATED PARTY COST OF SALES [Abstract]
Costs of sales	4,115	6,278	5,253
General and administrative	690	610	613
Affiliated Entity [Member]
RELATED PARTY ASSETS
Accounts receivable, net	25	31
Other current assets	36	3
Deferred charges and other assets	0	46
Total Assets	61	80
RELATED PARTY LIABILITIES [Abstract]
Current portion of debt	6	6
Accounts payable	22	22
Other current liabilities	10	0
Long-term debt	167	172
Total Liabilities	205	200
RELATED PARTY REVENUES [Abstract]
Services	72	29	31
Product sales and other	71	86	36
Total Revenues	143	115	67
RELATED PARTY COST OF SALES [Abstract]
Costs of sales	60	74	17
General and administrative	$ 55	$ 57	$ 57

Related Party Transactions Note

Related Party Transactions Notes Receivable (Details) - Notes Receivable [Member] - Plantation Pipeline Company [Member] - Plantation Pipeline Company [Member] - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	51.17%
Notes Receivable, Related Parties	$ 35	$ 47
Notes Receivable, Interest Rate	4.25%
Notes Receivable, Related Parties, Current	$ 35	1
Notes Receivable, Related Parties, Noncurrent		$ 46

Related Party Transactions Subs

Related Party Transactions Subsequent Event (Details) - Midcontinent Express Pipeline LLC [Member] - Loans Receivable [Member] - Midcontinent Express Pipeline LLC [Member] - USD ($)	Feb. 03, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Notes Receivable, Related Parties		$ 0	$ 0
Subsequent Event [Member]
Related Party Transaction [Line Items]
Renewal Term	1 year
Equity Method Investment, Ownership Percentage	50.00%
Subsequent Event [Member] | Minimum [Member]
Related Party Transaction [Line Items]
Notes Receivable, Borrowing Capacity	$ 2,000,000
Subsequent Event [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Notes Receivable, Borrowing Capacity	$ 40,000,000
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, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 103
Operating Leases, Future Minimum Payments, Due in Two Years	90
Operating Leases, Future Minimum Payments, Due in Three Years	83
Operating Leases, Future Minimum Payments, Due in Four Years	78
Operating Leases, Future Minimum Payments, Due in Five Years	69
Operating Leases, Future Minimum Payments, Due Thereafter	406
Operating Leases, Future Minimum Payments Due	829
Operating Leases, Rent Expense	$ 143	$ 114	$ 126
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	40 years

Commitments and Contingent Li94

Commitments and Contingent Liabilities Contingent Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 1,202	$ 1,069
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]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 200
Notes Payable to Banks [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 120

Commitments and Contingent Li95

Commitments and Contingent Liabilities Guarantees and Indemnifications (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 1,202	$ 1,069

Commitments and Contingent Li96

Commitments and Contingent Liabilities Commitments for Jones Act (Details) - Philly Tankers LLC [Member] $ in Millions	Dec. 31, 2015USD ($)
Other Commitments [Line Items]
Unrecorded Unconditional Purchase Obligation	$ 568
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	170
Unrecorded Unconditional Purchase Obligation, Due within Two Years	$ 384

Energy Commodity Price Risk Man

Energy Commodity Price Risk Managment (Details) - Energy Related Derivative [Member] - Forward Contracts [Member]	Dec. 31, 2015MMBblsBcf
Designated as Hedging Instrument [Member] | Crude Oil Fixed Price [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	(21.7)
Designated as Hedging Instrument [Member] | Crude Oil Basis [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	(6.4)
Designated as Hedging Instrument [Member] | Natural Gas Fixed Price [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf	(37.6)
Designated as Hedging Instrument [Member] | Natural Gas Basis [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf	(30.1)
Not Designated as Hedging Instrument [Member] | Crude Oil Fixed Price [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	(0.6)
Not Designated as Hedging Instrument [Member] | Crude Oil Basis [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	(1.3)
Not Designated as Hedging Instrument [Member] | Natural Gas Fixed Price [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf	(14.3)
Not Designated as Hedging Instrument [Member] | Natural Gas Basis [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf	(8.6)
Not Designated as Hedging Instrument [Member] | Natural Gas Liquids Fixed Price [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	(1.9)

Interest Rate Risk Managment (D

Interest Rate Risk Managment (Details) $ in Millions	1 Months Ended
	Dec. 31, 2015USD ($)	Dec. 30, 2015USD ($)	Dec. 31, 2014USD ($)
Derivative [Line Items]
Number of Fixed-to-Variable Interest Rate Swap Agreements Entered Into	9
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 11,000	$ 1,300	$ 9,200
KMP 3.50% Senior Notes due September 1, 2023 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.50%
4.15% Senior Notes due February 1, 2024 [Member] [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.15%
EPB 4.30% Senior Notes due May 1, 2024 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.30%
Fair Value Hedging [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 9,700

Risk Management Foreign Currenc

Risk Management Foreign Currency Risk Management (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Derivative [Line Items]
Cross-currency Swap Agreements	$ 1,358
KMI 1.50% Senior Notes Due 2022 [Member] | Currency Swap [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.79%
KMI 2.25% Senior Notes Due 2027 [Member] | Currency Swap [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.67%
Kinder Morgan, Inc. [Member]
Derivative [Line Items]
Debt Instrument, Term	5 years
Kinder Morgan, Inc. [Member] | KMI 1.50% Senior Notes Due 2022 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.50%
Debt Instrument, Term	7 years
Kinder Morgan, Inc. [Member] | KMI 2.25% Senior Notes Due 2027 [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.25%
Debt Instrument, Term	12 years

Risk Management Fair Value of D

Risk Management Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	$ 377	$ 359
Liability derivatives	(17)	(9)
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	987	718
Liability derivatives	(74)	(87)
Designated as Hedging Instrument [Member] | Energy Related Derivative [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	603	315
Liability derivatives	(13)	(34)
Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	359	309
Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(13)	(34)
Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	244	6
Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	0	0
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	384	403
Liability derivatives	(9)	(53)
Designated as Hedging Instrument [Member] | Currency Swap [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Liability derivatives	(52)	0
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Interest Rate Swap [Member] | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	111	143
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Interest Rate Swap [Member] | 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 [Member] | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	273	260
Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | Interest Rate Swap [Member] | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(9)	(53)
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	(6)	0
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	(46)	0
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	1,024	997
Liability derivatives	(108)	(162)
Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	35	269
Liability derivatives	(1)	(2)
Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	35	73
Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(1)	(2)
Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	196
Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	0	0
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	1	0
Liability derivatives	(16)	0
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	1	0
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(11)	0
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(5)	0
Not Designated as Hedging Instrument [Member] | Power Derivative Contract [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	1	10
Liability derivatives	(17)	(73)
Not Designated as Hedging Instrument [Member] | Power Derivative Contract [Member] | Fair Value of Derivatives Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	1	10
Not Designated as Hedging Instrument [Member] | Power Derivative Contract [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	(17)	(57)
Not Designated as Hedging Instrument [Member] | Power Derivative Contract [Member] | Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	0	0
Not Designated as Hedging Instrument [Member] | Power Derivative Contract [Member] | Other Long-Term Liabilities and Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Liability derivatives	0	(16)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Asset derivatives	37	279
Liability derivatives	$ (34)	$ (75)

Effect of Derivative Contracts

Effect of Derivative Contracts on the Income Statement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net			$ 0
Interest Rate Swap [Member] | Interest, net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (15)	$ 0	0
Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	176	11	(10)
Derivative, Loss on Derivative	31
Energy Related Derivative [Member] | Revenues—Natural gas sales
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	17	(7)	0
Energy Related Derivative [Member] | Revenues—Product sales and other
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	176	20	(10)
Energy Related Derivative [Member] | Costs of sales
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(2)	0	2
Energy Related Derivative [Member] | Other expense (income) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	(2)	(2)
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	164	409	(38)
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)	272	25	(11)
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	2	11	3
Designated as Hedging Instrument [Member] | Interest Rate 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	(4)	(15)	7
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Interest, net [Member] | Fair Value Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	25	207	(425)
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Interest, net [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/(loss)reclassified fromAccumulated OCIinto income(effective portion)	(3)	(4)	2
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, net [Member] | Fair Value Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(33)	(204)	425
Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Loss to be reclassified within twelve months	181
Designated as Hedging Instrument [Member] | Energy Related Derivative [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	201	424	(45)
Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Revenues—Natural gas sales | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/(loss)reclassified fromAccumulated OCIinto income(effective portion)	54	(1)	0
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 Related Derivative [Member] | 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)	236	26	(13)
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	2	11	3
Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Costs of sales | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain/(loss)reclassified fromAccumulated OCIinto income(effective portion)	(15)	4	0
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	(33)	0	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)	0	0	$ 0
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 0	$ 0

Credit Risks (Details)

Credit Risks (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Energy Related Derivative [Member]
Credit Derivatives [Line Items]
Letters of Credit Outstanding, Amount	$ 2	$ 20
Contract and Over the Counter [Member] | Energy Related Derivative [Member]
Credit Derivatives [Line Items]
Derivative, Collateral, Right to Reclaim Cash	0	47
Derivative, Collateral, Obligation to Return Cash	37	$ 13
One notch credit downgrade [Member]
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	1
One notch credit downgrade [Member] | Energy Related Derivative [Member]
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	0
Two notch credit downgrade [Member]
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	4
Two notch credit downgrade [Member] | Energy Related Derivative [Member]
Credit Derivatives [Line Items]
Additional Collateral, Aggregate Fair Value	$ 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, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ 327	$ (3)	$ 7
Accumulated Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Net of Tax	(108)	2	51
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(236)	(23)	(176)
Accumulated other comprehensive loss	(17)	(24)	(118)
Other Comprehensive Income Unrealized Gain Loss On Derivatives Arising During Period Net Of Tax Portion Attributable To Parent	164	254	(14)
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax, Before Reclassifications, Portion Attributable to Parent	(214)	(68)	(49)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax	(122)	(212)	151
Other Comprehensive Income Reclassification Adjustment On Derivatives Included In Net Income Net Of Tax Portion Attributable To Parent	(272)	(22)	4
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	(1)	2
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), Derivatives Qualifying as Hedges, Net of Tax, Portion Attributable to Parent	(108)	330	(10)
Foreign currency translation adjustments (net of tax benefit (expense) of $41, $22, and $(8), respectively)	(214)	(110)	(49)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent	(122)	(213)	153
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	(444)	7	94
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)
OCI before Reclassifications [Member]
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income [Roll Forward]
OCI, before Reclassifications, Net of Tax, Attributable to Parent	(172)	(26)	88
Other comprehensive income (loss), Impact of Merger Transactions before reclassifications, net of tax, portion attributable to parent		56
Amounts reclassified from AOCI [Member]
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income [Roll Forward]
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	$ (272)	$ (23)	$ 6

Fair Value of Derivative Contra

Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value, derivative	$ 0
Liability fair value, derivative	(52)
Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value, derivative	639	$ 594
Liability fair value, derivative	(31)	(109)
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	(61)	(110)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	0	(88)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Liability Net, Gain (Loss) Included in Earnings	(13)	22
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Gain (Loss) Included in Other Comprehensive Income (Loss)	0	78
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Liability Net, Settlements	59	37
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	(15)	(61)
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	0	1
Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value, derivative	385	403
Liability fair value, derivative	(25)	(53)
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]
Asset fair value, derivative	0
Liability fair value, derivative	0
Quoted prices in active markets for identical assets (Level 1) [Member] | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value, derivative	48	49
Liability fair value, derivative	(4)	(25)
Quoted prices in active markets for identical assets (Level 1) [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value, derivative	0	0
Liability fair value, derivative	0	0
Fair Value, Inputs, Level 2 [Member] | Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value, derivative	0
Liability fair value, derivative	(52)
Fair Value, Inputs, Level 2 [Member] | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value, derivative	589	533
Liability fair value, derivative	(10)	(11)
Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value, derivative	385	403
Liability fair value, derivative	(25)	(53)
Significant unobservable inputs (Level 3) [Member] | Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value, derivative	0
Liability fair value, derivative	0
Significant unobservable inputs (Level 3) [Member] | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value, derivative	2	12
Liability fair value, derivative	(17)	(73)
Significant unobservable inputs (Level 3) [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset fair value, derivative	0	0
Liability fair value, derivative	0	0
Not Offset on Balance Sheet [Member] | Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Asset Adjustment for Financial Instruments subject to Master Netting Agreement but Presented Gross	0
Net Liability Adjustment for Financial Instruments Subject to Master Netting Agreement but Presented Gross	0
Not Offset on Balance Sheet [Member] | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Asset Adjustment for Financial Instruments subject to Master Netting Agreement but Presented Gross	(12)	(46)
Net Liability Adjustment for Financial Instruments Subject to Master Netting Agreement but Presented Gross	12	46
Not Offset on Balance Sheet [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Asset Adjustment for Financial Instruments subject to Master Netting Agreement but Presented Gross	(8)	(44)
Net Liability Adjustment for Financial Instruments Subject to Master Netting Agreement but Presented Gross	8	44
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
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(52)
Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	590	535
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(19)	(16)
Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	377	359
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(17)	(9)
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
Derivative, Collateral, Right to Reclaim Cash	0
Contract and Over the Counter [Member] | Energy Related Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Collateral, Obligation to Return Cash	(37)	(13)
Derivative, Collateral, Right to Reclaim Cash	0	47
Contract and Over the Counter [Member] | Interest Rate 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 Financial Instrum

Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 43,227	$ 42,814
Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Fair Value Disclosure	$ 37,481	$ 43,761

Reportable Segments Revenues (D

Reportable Segments Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues
Revenues	$ 14,403	$ 16,226	$ 14,070
Natural Gas Pipelines
Revenues
Revenues	8,704	10,153	8,613
CO2
Revenues
Revenues	1,699	1,960	1,857
Terminals
Revenues
Revenues	1,878	1,717	1,408
Products Pipelines
Revenues
Revenues	1,828	2,068	1,853
Kinder Morgan Canada
Revenues
Revenues	260	291	302
Other
Revenues
Revenues	(3)	1	1
Total segment assets
Revenues
Revenues	14,391	16,206	14,040
Unallocated [Member]
Revenues
Revenues	37	36	36
Less: Total intersegment revenues
Revenues
Revenues	(25)	(16)	(6)
Intersegment revenues | Natural Gas Pipelines
Revenues
Revenues	21	15	4
Intersegment revenues | Terminals
Revenues
Revenues	1	1	2
Intersegment revenues | Products Pipelines
Revenues
Revenues	3	0	0
Single customer exceeding 10% of total [Member]
Revenues
Revenues	$ 0	$ 0	$ 0

Reportable Segments Operating e

Reportable Segments Operating expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Operating expenses(b)	$ 6,891	$ 8,853	$ 7,760
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Operating expenses(b)	4,738	6,241	5,235
CO2
Segment Reporting Information [Line Items]
Operating expenses(b)	432	494	439
Terminals
Segment Reporting Information [Line Items]
Operating expenses(b)	836	746	657
Products Pipelines
Segment Reporting Information [Line Items]
Operating expenses(b)	772	1,258	1,295
Kinder Morgan Canada
Segment Reporting Information [Line Items]
Operating expenses(b)	87	106	110
Other
Segment Reporting Information [Line Items]
Operating expenses(b)	51	24	30
Total segment operating expenses
Segment Reporting Information [Line Items]
Operating expenses(b)	6,916	8,869	7,766
Less: Total intersegment operating expenses
Segment Reporting Information [Line Items]
Operating expenses(b)	$ (25)	$ (16)	$ (6)

Reportable Segments Other expen

Reportable Segments Other expense (income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Other expense (income)(c)	$ 2,066	$ 275	$ (99)
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other expense (income)(c)	1,269	5	(24)
CO2
Segment Reporting Information [Line Items]
Other expense (income)(c)	606	243	0
Terminals
Segment Reporting Information [Line Items]
Other expense (income)(c)	190	29	(74)
Products Pipelines
Segment Reporting Information [Line Items]
Other expense (income)(c)	2	(3)	6
Kinder Morgan Canada
Segment Reporting Information [Line Items]
Other expense (income)(c)	(1)	0	0
Other
Segment Reporting Information [Line Items]
Other expense (income)(c)	$ 0	$ 1	$ (7)

Reportable Segments Depreciatio

Reportable Segments Depreciation, depletion and amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
DD&A	$ 2,309	$ 2,040	$ 1,806
Natural Gas Pipelines
Segment Reporting Information [Line Items]
DD&A	1,046	897	797
CO2
Segment Reporting Information [Line Items]
DD&A	556	570	533
Terminals
Segment Reporting Information [Line Items]
DD&A	433	337	247
Products Pipelines
Segment Reporting Information [Line Items]
DD&A	206	166	155
Kinder Morgan Canada
Segment Reporting Information [Line Items]
DD&A	46	51	54
Other
Segment Reporting Information [Line Items]
DD&A	$ 22	$ 19	$ 20

Reportable Segments Earnings (l

Reportable Segments Earnings (loss) from equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	$ 333	$ 361	$ 288
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	285	279	200
CO2
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	(5)	26	22
Terminals
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	17	18	22
Products Pipelines
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	36	37	40
Kinder Morgan Canada
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	0	0	4
Other
Segment Reporting Information [Line Items]
Earnings from equity investments and amortization of excess cost of equity investments, including loss on impairments	$ 0	$ 1	$ 0

Reportable Segments Interest in

Reportable Segments Interest income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Interest income	$ 4	$ 9	$ 15
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Interest income	0	1	0
Products Pipelines
Segment Reporting Information [Line Items]
Interest income	2	2	2
Kinder Morgan Canada
Segment Reporting Information [Line Items]
Interest income	0	0	3
Other
Segment Reporting Information [Line Items]
Interest income	2	6	8
Total segment operating expenses
Segment Reporting Information [Line Items]
Interest income	4	9	13
Unallocated [Member]
Segment Reporting Information [Line Items]
Interest income	$ 0	$ 0	$ 2

Reportable Segments Other, net-

Reportable Segments Other, net-income(expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Other, net	$ 43	$ 80	$ 53
Including gains on remeasurement and sales of investments [Member]
Segment Reporting Information [Line Items]
Other, net	43	80	835
Including gains on remeasurement and sales of investments [Member] | Natural Gas Pipelines
Segment Reporting Information [Line Items]
Other, net	24	24	578
Including gains on remeasurement and sales of investments [Member] | CO2
Segment Reporting Information [Line Items]
Other, net	0	0	0
Including gains on remeasurement and sales of investments [Member] | Terminals
Segment Reporting Information [Line Items]
Other, net	8	12	1
Including gains on remeasurement and sales of investments [Member] | Products Pipelines
Segment Reporting Information [Line Items]
Other, net	4	(1)	1
Including gains on remeasurement and sales of investments [Member] | Kinder Morgan Canada
Segment Reporting Information [Line Items]
Other, net	8	15	246
Including gains on remeasurement and sales of investments [Member] | Other
Segment Reporting Information [Line Items]
Other, net	$ (1)	$ 30	$ 9

Reportable Segments Income tax

Reportable Segments Income tax benefit (expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Income Tax Expense	$ (564)	$ (648)	$ (742)
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Income Tax Expense	(4)	(6)	(9)
CO2
Segment Reporting Information [Line Items]
Income Tax Expense	(1)	(8)	(7)
Terminals
Segment Reporting Information [Line Items]
Income Tax Expense	(29)	(29)	(14)
Products Pipelines
Segment Reporting Information [Line Items]
Income Tax Expense	(8)	(2)	2
Total segment operating expenses
Segment Reporting Information [Line Items]
Income Tax Expense	(61)	(63)	(49)
Unallocated [Member]
Segment Reporting Information [Line Items]
Income Tax Expense	(503)	(585)	(693)
Kinder Morgan Canada
Segment Reporting Information [Line Items]
Income Tax Expense	$ (19)	$ (18)	$ (21)

Reportable Segments Segment ear

Reportable Segments Segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total segment DD&A	$ (2,309)	$ (2,040)	$ (1,806)
Amortization of excess cost of equity investments	(51)	(45)	(39)
Product sales and other	3,274	4,461	3,788
General and administrative expenses	(690)	(610)	(613)
Interest expense, net of unallocable interest income(e)	(2,055)	(1,807)	(1,688)
Unallocable income tax expense	564	648	742
Loss from discontinued operations, net of tax	0	0	(4)
Net Income	208	2,443	2,692
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(d)	3,063	4,259	4,207
Total segment DD&A	(1,046)	(897)	(797)
Unallocable income tax expense	4	6	9
CO2
Segment Reporting Information [Line Items]
Segment EBDA(d)	657	1,240	1,435
Total segment DD&A	(556)	(570)	(533)
Unallocable income tax expense	1	8	7
Terminals
Segment Reporting Information [Line Items]
Segment EBDA(d)	849	944	836
Total segment DD&A	(433)	(337)	(247)
Unallocable income tax expense	29	29	14
Products Pipelines
Segment Reporting Information [Line Items]
Segment EBDA(d)	1,100	856	602
Total segment DD&A	(206)	(166)	(155)
Unallocable income tax expense	8	2	(2)
Kinder Morgan Canada
Segment Reporting Information [Line Items]
Segment EBDA(d)	163	182	424
Total segment DD&A	(46)	(51)	(54)
Unallocable income tax expense	19	18	21
Other
Segment Reporting Information [Line Items]
Segment EBDA(d)	(53)	13	(5)
Total segment DD&A	(22)	(19)	(20)
Total segment operating expenses
Segment Reporting Information [Line Items]
Segment EBDA(d)	5,779	7,494	7,499
Unallocable income tax expense	61	63	49
Unallocated [Member]
Segment Reporting Information [Line Items]
Product sales and other	37	36	36
Unallocable income tax expense	$ 503	$ 585	$ 693

Reportable Segments Capital exp

Reportable Segments Capital expenditures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Capital expenditures	$ 3,896	$ 3,617	$ 3,369
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	1,642	935	1,085
CO2
Segment Reporting Information [Line Items]
Capital expenditures	725	792	667
Terminals
Segment Reporting Information [Line Items]
Capital expenditures	847	1,049	1,108
Products Pipelines
Segment Reporting Information [Line Items]
Capital expenditures	524	680	416
Kinder Morgan Canada
Segment Reporting Information [Line Items]
Capital expenditures	142	156	77
Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 16	$ 5	$ 16

Reportable Segments Investments

Reportable Segments Investments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Investments	$ 6,040	$ 6,036
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments	5,080	5,174
CO2
Segment Reporting Information [Line Items]
Investments	0	17
Terminals
Segment Reporting Information [Line Items]
Investments	306	219
Products Pipelines
Segment Reporting Information [Line Items]
Investments	641	624
Kinder Morgan Canada
Segment Reporting Information [Line Items]
Investments	10	1
Other
Segment Reporting Information [Line Items]
Investments	$ 3	$ 1

Reportable Segments Assets (Det

Reportable Segments Assets (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Assets at December 31	$ 84,104	$ 83,049
Assets held for sale	19	56
Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets at December 31	53,704	52,532
CO2
Segment Reporting Information [Line Items]
Assets at December 31	4,706	5,227
Terminals
Segment Reporting Information [Line Items]
Assets at December 31	9,083	8,850
Products Pipelines
Segment Reporting Information [Line Items]
Assets at December 31	8,464	7,179
Kinder Morgan Canada
Segment Reporting Information [Line Items]
Assets at December 31	1,434	1,593
Other
Segment Reporting Information [Line Items]
Assets at December 31	418	455
Total segment assets
Segment Reporting Information [Line Items]
Assets at December 31	77,809	75,836
Corporate assets(f)
Segment Reporting Information [Line Items]
Assets at December 31	$ 6,276	$ 7,157

Reportable Segments Geographica

Reportable Segments Geographical information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total revenues	$ 14,403	$ 16,226	$ 14,070
Long-term assets, excluding goodwill and other intangibles	53,939	52,341
U.S.
Segment Reporting Information [Line Items]
Total revenues	13,797	15,605	13,656
Long-term assets, excluding goodwill and other intangibles	51,679	49,992
Canada
Segment Reporting Information [Line Items]
Total revenues	479	437	398
Long-term assets, excluding goodwill and other intangibles	2,193	2,268
Mexico
Segment Reporting Information [Line Items]
Total revenues	127	184	$ 16
Long-term assets, excluding goodwill and other intangibles	$ 67	$ 81

Reportable Segments Other (Deta

Reportable Segments Other (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues from External Customers [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	10.00%	10.00%	10.00%

Litigation, Environmental an120

Litigation, Environmental and Other Contingencies Federal Energy Regulatory Commission Proceedings (Details) - Regulated Operation [Member] - Federal Energy Regulatory Commission [Member] - Various Shippers [Member] - Unfavorable Regulatory Action [Member] $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
SFPP [Member] | Repreations, Refunds, and Rate Reductions [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency Period of Time Litigation Concerns	2 years
SFPP [Member] | Annual Rate Reductions [Member] | Pending Litigation [Member]
SFPP [Abstract]
Loss Contingency, Damages Sought, Value	$ 40
SFPP [Member] | Revenue Subject to Refund [Member] | Pending Litigation [Member]
SFPP [Abstract]
Loss Contingency, Damages Sought, Value	$ 160
2008 rate case and the 2010 rate case [Member] | EPNG [Member] | Opinion 517 issued and implemented (rehearing pending); and Opinion 528 issued and is awaiting filing of court document) [Member]
EPNG [Abstract]
Loss Contingency, Pending Claims, Number	2

Litigation, Environmental an121

Litigation, Environmental and Other Contingencies California Public Utilities Commission Proceedings (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Accrued contingencies	$ 298	$ 383

Litigation, Environmental an122

Litigation, Environmental and Other Contingencies Other Commercial Matters (Details)	Feb. 04, 2016USD ($)	Jul. 30, 2015USD ($)	Apr. 21, 2015USD ($)	Oct. 25, 2013USD ($)	Aug. 31, 2015USD ($)	Sep. 30, 2013USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2011USD ($)
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
Pending Litigation [Member] | 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] | SFPP L.P. [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value				$ 22,300,000
Lessee Leasing Arrangements, Operating Leases, Term of Contract				10 years
Pending Litigation [Member] | 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] | SFPP L.P. [Member] | Loss on Long-term Purchase Commitment [Member]
Loss Contingencies [Line Items]
Loss Contingency, Initial Award Amount, Annual Rent Payable								$ 14,000,000
Pending Litigation [Member] | Price Reporting Litigation [Member] | Kinder Morgan Bulk Terminals, Inc. [Member] | Price Reporting Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value							$ 140,000,000
Pending Litigation [Member] | KMEP Capex Litigation [Member] | KMEP LP Capex Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value							27,500,000
Pending Litigation [Member] | Central Florida Pipeline LLC [Member]
Loss Contingencies [Line Items]
Environmental Remediation Expense					$ 900,000
Tentative Settlement [Member] | Philadelphia Terminal, Notice of Violation [Member] [Member]
Loss Contingencies [Line Items]
Environmental Remediation Expense							$ 570,000
Tentative Settlement [Member] | Point Breeze Terminal, Notice of Violation [Member]
Loss Contingencies [Line Items]
Percent of reduced capacity		10.00%
Environmental Remediation Expense		$ 175,000
Plains Gas Solutions, LLC v. Tennessee Gas Pipeline Company, L.L.C. et al [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value						$ 100,000,000
Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al. [Member]
Loss Contingencies [Line Items]
Payments to Acquire Businesses, Gross			$ 1,130,000,000
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 [Member]
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			$ 171,000,000
Subsequent Event [Member] | Brinckerhoff v. El Paso Pipeline GP Company, LLC., et al. [Member] | Tentative Settlement [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 100,200,000

Litigation, Environmental an123

Litigation, Environmental and Other Contingencies General (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Estimated Litigation Liability	$ 463	$ 400

Litigation, Environmental an124

Litigation, Environmental and Other Contingencies Environmental Matters (Details) $ in Millions	Nov. 08, 2013	Oct. 25, 2013USD ($)	Aug. 06, 2013Defendants	Jul. 24, 2013	Aug. 31, 2007USD ($)	Dec. 31, 2000Terminals	Dec. 31, 2015USD ($)PartiesTerminalsDefendants	Dec. 31, 2010USD ($)	Dec. 31, 1969	Dec. 31, 2014USD ($)
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies							$ 284			$ 340
Recorded Third-Party Environmental Recoveries Receivable							$ 13			$ 14
Rare Metals Inc. [Member]
Loss Contingencies [Line Items]
Number of Uranium Mines									20
Southeast Louisiana Flood Protection Litigation [Member] | 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
Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish [Member] | Plaquemines Parish, Louisiana (Docket No. 60-999) [Member] | Parish of Plaquemines, Louisiana [Member] | TGP [Member]
Loss Contingencies [Line Items]
Loss Contingency, Number of Defendants	17
Regulated Operation [Member] | Portland Harbor Superfund Site, Willamette River, Portland, Oregon [Member] | Portland Harbor Superfund Site, Willamette River, Portland, Oregon [Member] | Environmental Protection Agency [Member] | GATX Terminals Corporation (n/k/a KMLT) [Member]
Loss Contingencies [Line Items]
Number of Liquid Terminals | Terminals						2	4
Number of Parties Involoved In Site Cleanup | Parties							90
Pending Litigation [Member] | Lower Passaic River Study Area [Member]
Loss Contingencies [Line Items]
Number of Facilities							100
Number of Parties at a Joint Defense Group							70
Pending Litigation [Member] | SFPP L.P. [Member] | 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]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value		$ 22.3
Pending Litigation [Member] | SFPP Phoenix Terminal [Member] | KMEP and SFPP [Member] | Unfavorable Regulatory Action [Member] | Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona [Member]
Loss Contingencies [Line Items]
Loss Contingency, Number of Defendants | Defendants			26				70
Loss Contingency, Damages Sought, Value							$ 175
Pending Litigation [Member] | Mission Valley Terminal Facility [Member] | Kinder Morgan Energy Partners, L.P. [Member] | United States District Court, Southern District of California, case number 07CV1883WCAB [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value					$ 170			$ 365
Tentative Settlement [Member] | Mission Valley Terminal Facility [Member] | Kinder Morgan Energy Partners, L.P. [Member] | United States District Court, Southern District of California, case number 07CV1883WCAB [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value								$ 160
Minimum [Member] | Pending Litigation [Member] | Lower Passaic River Study Area [Member]
Loss Contingencies [Line Items]
Environmental Remediation Expense							365
Maximum [Member] | Pending Litigation [Member] | Lower Passaic River Study Area [Member]
Loss Contingencies [Line Items]
Environmental Remediation Expense							3,200
Preferred alternative [Member] | Pending Litigation [Member] | Lower Passaic River Study Area [Member]
Loss Contingencies [Line Items]
Environmental Remediation Expense							$ 1,700

Guarantee of Securities of S125

Guarantee of Securities of Subsidiaries Income Statement and Comprehensive Income (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Guarantor Obligations [Line Items]
Total revenues	$ 14,403,000,000	$ 16,226,000,000	$ 14,070,000,000
Costs of sales	(4,115,000,000)	(6,278,000,000)	(5,253,000,000)
Depreciation, depletion and amortization	2,309,000,000	2,040,000,000	1,806,000,000
Other operating expenses	(3,000,000)	1,000,000	(1,000,000)
Total Operating Costs, Expenses and Other	11,956,000,000	11,778,000,000	10,080,000,000
Operating Income	2,447,000,000	4,448,000,000	3,990,000,000
Earnings from equity investments	414,000,000	406,000,000	392,000,000
Interest, net	(2,051,000,000)	(1,798,000,000)	(1,675,000,000)
Amortization of excess cost of equity investments and other, net	43,000,000	80,000,000	53,000,000
Income from Continuing Operations Before Income Taxes	772,000,000	3,091,000,000	3,438,000,000
Income Tax Expense	(564,000,000)	(648,000,000)	(742,000,000)
Income from continuing operations	208,000,000	2,443,000,000	2,696,000,000
Net Income	208,000,000	2,443,000,000	2,692,000,000
Net Loss (Income) Attributable to Noncontrolling Interests	45,000,000	(1,417,000,000)	(1,499,000,000)
Net income attributable to controlling interests	253,000,000	1,026,000,000	1,193,000,000
Preferred Stock Dividends	(26,000,000)	0	0
Net Income Available to Common Stockholders	227,000,000	1,026,000,000	1,193,000,000
Total other comprehensive income (loss)	444,000,000	(20,000,000)	(40,000,000)
Comprehensive income	(236,000,000)	2,463,000,000	2,732,000,000
Comprehensive loss (income) attributable to noncontrolling interests	45,000,000	(1,486,000,000)	(1,445,000,000)
Comprehensive income attributable to controlling interests	191,000,000	(977,000,000)	(1,287,000,000)
Parent Issuer and Guarantor
Guarantor Obligations [Line Items]
Total revenues	37,000,000	36,000,000	36,000,000
Costs of sales	0	0	0
Depreciation, depletion and amortization	22,000,000	21,000,000	20,000,000
Other operating expenses	71,000,000	30,000,000	22,000,000
Total Operating Costs, Expenses and Other	93,000,000	51,000,000	42,000,000
Operating Income	(56,000,000)	(15,000,000)	(6,000,000)
Earnings (losses) from consolidated subsidiaries	1,430,000,000	2,080,000,000	2,025,000,000
Earnings from equity investments	0	0	0
Interest, net	(686,000,000)	(513,000,000)	(539,000,000)
Amortization of excess cost of equity investments and other, net	0	0	(1,000,000)
Income from Continuing Operations Before Income Taxes	688,000,000	1,552,000,000	1,479,000,000
Income Tax Expense	(435,000,000)	(278,000,000)	(41,000,000)
Income from continuing operations			1,438,000,000
Loss from discontinued operations			0
Net Income	253,000,000	1,274,000,000	1,438,000,000
Net Loss (Income) Attributable to Noncontrolling Interests	0	(248,000,000)	(245,000,000)
Net income attributable to controlling interests	253,000,000	1,026,000,000	1,193,000,000
Preferred Stock Dividends	(26,000,000)
Net Income Available to Common Stockholders	227,000,000
Total other comprehensive income (loss)	444,000,000	24,000,000	(81,000,000)
Comprehensive income	(191,000,000)	1,250,000,000	1,519,000,000
Comprehensive loss (income) attributable to noncontrolling interests	0	(273,000,000)	(232,000,000)
Comprehensive income attributable to controlling interests	191,000,000	(977,000,000)	(1,287,000,000)
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	38,000,000	5,000,000	8,000,000
Total Operating Costs, Expenses and Other	38,000,000	5,000,000	8,000,000
Operating Income	(38,000,000)	(5,000,000)	(8,000,000)
Earnings (losses) from consolidated subsidiaries	1,643,000,000	3,977,000,000	4,010,000,000
Earnings from equity investments	0	0	0
Interest, net	23,000,000	(111,000,000)	(100,000,000)
Amortization of excess cost of equity investments and other, net	1,000,000	0	0
Income from Continuing Operations Before Income Taxes	1,629,000,000	3,861,000,000	3,902,000,000
Income Tax Expense	(4,000,000)	(7,000,000)	(11,000,000)
Income from continuing operations			3,891,000,000
Loss from discontinued operations			0
Net Income	1,625,000,000	3,854,000,000	3,891,000,000
Net Loss (Income) Attributable to Noncontrolling Interests	0	(211,000,000)	(236,000,000)
Net income attributable to controlling interests	1,625,000,000	3,643,000,000	3,655,000,000
Preferred Stock Dividends	0
Net Income Available to Common Stockholders	1,625,000,000
Total other comprehensive income (loss)	460,000,000	(275,000,000)	135,000,000
Comprehensive income	1,165,000,000	4,129,000,000	3,756,000,000
Comprehensive loss (income) attributable to noncontrolling interests	0	(203,000,000)	(237,000,000)
Comprehensive income attributable to controlling interests	(1,165,000,000)	(3,926,000,000)	(3,519,000,000)
Subsidiary Issuer and Guarantor - Copano
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	632,000,000	32,000,000	38,000,000
Total Operating Costs, Expenses and Other	632,000,000	32,000,000	38,000,000
Operating Income	(632,000,000)	(32,000,000)	(38,000,000)
Earnings (losses) from consolidated subsidiaries	68,000,000	224,000,000	163,000,000
Earnings from equity investments	0	0	0
Interest, net	(47,000,000)	(46,000,000)	(36,000,000)
Amortization of excess cost of equity investments and other, net	0	0	(1,000,000)
Income from Continuing Operations Before Income Taxes	(611,000,000)	146,000,000	88,000,000
Income Tax Expense	0	0	0
Income from continuing operations			88,000,000
Loss from discontinued operations			0
Net Income	(611,000,000)	146,000,000	88,000,000
Net Loss (Income) Attributable to Noncontrolling Interests	0	0	0
Net income attributable to controlling interests	(611,000,000)	146,000,000	88,000,000
Preferred Stock Dividends	0
Net Income Available to Common Stockholders	(611,000,000)
Total other comprehensive income (loss)	0	0	0
Comprehensive income	(611,000,000)	146,000,000	88,000,000
Comprehensive loss (income) attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to controlling interests	611,000,000	(146,000,000)	(88,000,000)
Subsidiary Guarantors
Guarantor Obligations [Line Items]
Total revenues	12,607,000,000	14,310,000,000	12,511,000,000
Costs of sales	(3,745,000,000)	(5,737,000,000)	(4,739,000,000)
Depreciation, depletion and amortization	1,898,000,000	1,655,000,000	1,466,000,000
Other operating expenses	4,071,000,000	2,927,000,000	2,325,000,000
Total Operating Costs, Expenses and Other	9,714,000,000	10,319,000,000	8,530,000,000
Operating Income	2,893,000,000	3,991,000,000	3,981,000,000
Earnings (losses) from consolidated subsidiaries	307,000,000	664,000,000	255,000,000
Earnings from equity investments	384,000,000	407,000,000	323,000,000
Interest, net	(1,299,000,000)	(1,039,000,000)	(965,000,000)
Amortization of excess cost of equity investments and other, net	(17,000,000)	(13,000,000)	549,000,000
Income from Continuing Operations Before Income Taxes	2,268,000,000	4,010,000,000	4,143,000,000
Income Tax Expense	(5,000,000)	(71,000,000)	50,000,000
Income from continuing operations			4,193,000,000
Loss from discontinued operations			(4,000,000)
Net Income	2,263,000,000	3,939,000,000	4,189,000,000
Net Loss (Income) Attributable to Noncontrolling Interests	0	0	0
Net income attributable to controlling interests	2,263,000,000	3,939,000,000	4,189,000,000
Preferred Stock Dividends	0
Net Income Available to Common Stockholders	2,263,000,000
Total other comprehensive income (loss)	325,000,000	(288,000,000)	99,000,000
Comprehensive income	1,938,000,000	4,227,000,000	4,090,000,000
Comprehensive loss (income) attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to controlling interests	(1,938,000,000)	(4,227,000,000)	(4,090,000,000)
Subsidiary Non-Guarantors
Guarantor Obligations [Line Items]
Total revenues	1,808,000,000	1,886,000,000	1,512,000,000
Costs of sales	(369,000,000)	(499,000,000)	(468,000,000)
Depreciation, depletion and amortization	389,000,000	364,000,000	320,000,000
Other operating expenses	770,000,000	514,000,000	663,000,000
Total Operating Costs, Expenses and Other	1,528,000,000	1,377,000,000	1,451,000,000
Operating Income	280,000,000	509,000,000	61,000,000
Earnings (losses) from consolidated subsidiaries	(30,000,000)	1,120,000,000	1,755,000,000
Earnings from equity investments	0	(1,000,000)	4,000,000
Interest, net	(42,000,000)	(89,000,000)	(35,000,000)
Amortization of excess cost of equity investments and other, net	8,000,000	48,000,000	249,000,000
Income from Continuing Operations Before Income Taxes	216,000,000	1,587,000,000	2,034,000,000
Income Tax Expense	(120,000,000)	(292,000,000)	(740,000,000)
Income from continuing operations			1,294,000,000
Loss from discontinued operations			0
Net Income	96,000,000	1,295,000,000	1,294,000,000
Net Loss (Income) Attributable to Noncontrolling Interests	0	0	0
Net income attributable to controlling interests	96,000,000	1,295,000,000	1,294,000,000
Preferred Stock Dividends	0
Net Income Available to Common Stockholders	96,000,000
Total other comprehensive income (loss)	326,000,000	168,000,000	172,000,000
Comprehensive income	(230,000,000)	1,127,000,000	1,122,000,000
Comprehensive loss (income) attributable to noncontrolling interests	0	0	0
Comprehensive income attributable to controlling interests	230,000,000	(1,127,000,000)	(1,122,000,000)
Consolidated KMI
Guarantor Obligations [Line Items]
Total revenues	14,403,000,000	16,226,000,000	14,070,000,000
Costs of sales	(4,115,000,000)	(6,278,000,000)	(5,253,000,000)
Depreciation, depletion and amortization	2,309,000,000	2,040,000,000	1,806,000,000
Other operating expenses	5,532,000,000	3,460,000,000	3,021,000,000
Total Operating Costs, Expenses and Other	11,956,000,000	11,778,000,000	10,080,000,000
Operating Income	2,447,000,000	4,448,000,000	3,990,000,000
Earnings (losses) from consolidated subsidiaries	0	0	0
Earnings from equity investments	384,000,000	406,000,000	327,000,000
Interest, net	(2,051,000,000)	(1,798,000,000)	(1,675,000,000)
Amortization of excess cost of equity investments and other, net	(8,000,000)	35,000,000	796,000,000
Income from Continuing Operations Before Income Taxes	772,000,000	3,091,000,000	3,438,000,000
Income Tax Expense	(564,000,000)	(648,000,000)	(742,000,000)
Income from continuing operations			2,696,000,000
Loss from discontinued operations			(4,000,000)
Net Income	208,000,000	2,443,000,000	2,692,000,000
Net Loss (Income) Attributable to Noncontrolling Interests	45,000,000	(1,417,000,000)	(1,499,000,000)
Net income attributable to controlling interests	253,000,000	1,026,000,000	1,193,000,000
Preferred Stock Dividends	(26,000,000)
Net Income Available to Common Stockholders	227,000,000
Total other comprehensive income (loss)	444,000,000	(20,000,000)	(40,000,000)
Comprehensive income	(236,000,000)	2,463,000,000	2,732,000,000
Comprehensive loss (income) attributable to noncontrolling interests	45,000,000	(1,486,000,000)	(1,445,000,000)
Comprehensive income attributable to controlling interests	191,000,000	(977,000,000)	(1,287,000,000)
Consolidating Adjustments
Guarantor Obligations [Line Items]
Total revenues	(49,000,000)	(6,000,000)	11,000,000
Costs of sales	(1,000,000)	(42,000,000)	(46,000,000)
Depreciation, depletion and amortization	0	0	0
Other operating expenses	(50,000,000)	(48,000,000)	(35,000,000)
Total Operating Costs, Expenses and Other	(49,000,000)	(6,000,000)	11,000,000
Operating Income	0	0	0
Earnings (losses) from consolidated subsidiaries	(3,418,000,000)	(8,065,000,000)	(8,208,000,000)
Earnings from equity investments	0	0	0
Interest, net	0	0	0
Amortization of excess cost of equity investments and other, net	0	0	0
Income from Continuing Operations Before Income Taxes	(3,418,000,000)	(8,065,000,000)	(8,208,000,000)
Income Tax Expense	0	0	0
Income from continuing operations			(8,208,000,000)
Loss from discontinued operations			0
Net Income	(3,418,000,000)	(8,065,000,000)	(8,208,000,000)
Net Loss (Income) Attributable to Noncontrolling Interests	45,000,000	(958,000,000)	(1,018,000,000)
Net income attributable to controlling interests	(3,373,000,000)	(9,023,000,000)	(9,226,000,000)
Preferred Stock Dividends	0
Net Income Available to Common Stockholders	(3,373,000,000)
Total other comprehensive income (loss)	(1,111,000,000)	351,000,000	(365,000,000)
Comprehensive income	(2,307,000,000)	(8,416,000,000)	(7,843,000,000)
Comprehensive loss (income) attributable to noncontrolling interests	45,000,000	(1,010,000,000)	(976,000,000)
Comprehensive income attributable to controlling interests	$ 2,262,000,000	$ 9,426,000,000	$ 8,819,000,000

Guarantee of Securities of S126

Guarantee of Securities of Subsidiaries Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
ASSETS
Cash and cash equivalents	$ 229	$ 315	$ 598	$ 714
All other current assets	366	746
Property, plant and equipment, net	40,547	38,564
Investments	6,040	6,036
Goodwill	23,790	24,654	24,504
Deferred income taxes	5,323	5,651
Deferred charges and other assets	2,029	2,090
Total assets	84,104	83,049
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	1,000
Long-term debt	42,406	40,097
Total liabilities	48,701	48,623
Total KMI equity	35,119	34,076
Noncontrolling interests	284	350
Total Stockholders’ Equity	35,403	34,426	28,285	24,100
Total Liabilities and Stockholders’ Equity	84,104	83,049
Parent Issuer and Guarantor
ASSETS
Cash and cash equivalents	123	4	83	48
All other current assets	126	655
Property, plant and equipment, net	252	263
Investments	16	16
Goodwill	15,089	15,087
Deferred income taxes	7,501	7,644
Deferred charges and other assets	215	258
Total assets	53,806	51,986
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	67	1,486
Other current liabilities	321	236
Long-term debt	13,845	11,833
Notes payable to affiliates	2,404	2,619
Deferred income taxes	0	0
All other long-term liabilities and deferred credits	722	583
Total liabilities	18,687	17,910
Total KMI equity	35,119	34,076
Noncontrolling interests	0	0
Total Stockholders’ Equity	35,119	34,076
Total Liabilities and Stockholders’ Equity	53,806	51,986
Subsidiary Issuer and Guarantor - KMP
ASSETS
Cash and cash equivalents	0	15	88	205
All other current assets	119	152
Property, plant and equipment, net	0	0
Investments	2	1
Goodwill	22	22
Deferred income taxes	0	0
Deferred charges and other assets	307	249
Total assets	51,407	55,020
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	500	699
Other current liabilities	458	498
Long-term debt	20,053	20,564
Notes payable to affiliates	448	153
Deferred income taxes	0	0
All other long-term liabilities and deferred credits	193	78
Total liabilities	30,334	33,941
Total KMI equity	21,073	21,079
Noncontrolling interests	0	0
Total Stockholders’ Equity	21,073	21,079
Total Liabilities and Stockholders’ Equity	51,407	55,020
Subsidiary Issuer and Guarantor - Copano
ASSETS
Cash and cash equivalents	0	0	1	0
All other current assets	0	3
Property, plant and equipment, net	0	5
Investments	0	0
Goodwill	287	920
Deferred income taxes	0	0
Deferred charges and other assets	1	0
Total assets	2,629	2,850
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	0	0
Other current liabilities	7	12
Long-term debt	378	386
Notes payable to affiliates	622	753
Deferred income taxes	2	2
All other long-term liabilities and deferred credits	0	2
Total liabilities	1,048	1,270
Total KMI equity	1,581	1,580
Noncontrolling interests	0	0
Total Stockholders’ Equity	1,581	1,580
Total Liabilities and Stockholders’ Equity	2,629	2,850
Subsidiary Guarantors
ASSETS
Cash and cash equivalents	12	17	17	28
All other current assets	2,163	2,547
Property, plant and equipment, net	32,195	29,490
Investments	5,906	5,910
Goodwill	5,221	5,419
Deferred income taxes	0	0
Deferred charges and other assets	4,943	3,772
Total assets	66,322	65,763
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	132	381
Other current liabilities	1,987	2,153
Long-term debt	7,447	6,599
Notes payable to affiliates	19,840	18,500
Deferred income taxes	594	487
All other long-term liabilities and deferred credits	907	987
Total liabilities	34,123	30,589
Total KMI equity	32,199	35,174
Noncontrolling interests	0	0
Total Stockholders’ Equity	32,199	35,174
Total Liabilities and Stockholders’ Equity	66,322	65,763
Subsidiary Non-Guarantors
ASSETS
Cash and cash equivalents	142	279	409	433
All other current assets	195	358
Property, plant and equipment, net	8,100	8,806
Investments	116	109
Goodwill	3,171	3,206
Deferred income taxes	0	0
Deferred charges and other assets	114	113
Total assets	16,233	17,107
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	122	151
Other current liabilities	527	1,024
Long-term debt	683	715
Notes payable to affiliates	1,305	1,240
Deferred income taxes	1,582	1,504
All other long-term liabilities and deferred credits	408	514
Total liabilities	5,341	6,014
Total KMI equity	10,892	11,093
Noncontrolling interests	0	0
Total Stockholders’ Equity	10,892	11,093
Total Liabilities and Stockholders’ Equity	16,233	17,107
Consolidated KMI
ASSETS
Cash and cash equivalents	229	315	598	714
All other current assets	2,595	3,437
Property, plant and equipment, net	40,547	38,564
Investments	6,040	6,036
Goodwill	23,790	24,654
Deferred income taxes	5,323	5,651
Deferred charges and other assets	5,580	4,392
Total assets	84,104	83,049
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	821	2,717
Other current liabilities	3,244	3,645
Long-term debt	42,406	40,097
Notes payable to affiliates	0	0
Deferred income taxes	0	0
All other long-term liabilities and deferred credits	2,230	2,164
Total liabilities	48,701	48,623
Total KMI equity	35,119	34,076
Noncontrolling interests	284	350
Total Stockholders’ Equity	35,403	34,426
Total Liabilities and Stockholders’ Equity	84,104	83,049
Consolidating Adjustments
ASSETS
Cash and cash equivalents	(48)	0	$ 0	$ 0
All other current assets	(8)	(278)
Property, plant and equipment, net	0	0
Investments	0	0
Goodwill	0	0
Deferred income taxes	(2,178)	(1,993)
Deferred charges and other assets	0	0
Total assets	(106,293)	(109,677)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current portion of debt	0	0
Other current liabilities	(56)	(278)
Long-term debt	0	0
Notes payable to affiliates	(24,619)	(23,265)
Deferred income taxes	(2,178)	(1,993)
All other long-term liabilities and deferred credits	0	0
Total liabilities	(40,832)	(41,101)
Total KMI equity	(65,745)	(68,926)
Noncontrolling interests	284	350
Total Stockholders’ Equity	(65,461)	(68,576)
Total Liabilities and Stockholders’ Equity	(106,293)	(109,677)
Affiliated Entity [Member]
ASSETS
All other current assets	36	3
Deferred charges and other assets	0	46
Affiliated Entity [Member] | Parent Issuer and Guarantor
ASSETS
All other current assets	2,233	2,251
Investments	27,401	25,286
Deferred charges and other assets	850	522
LIABILITIES AND STOCKHOLDERS’ EQUITY
Other current liabilities	1,328	1,153
Affiliated Entity [Member] | Subsidiary Issuer and Guarantor - KMP
ASSETS
All other current assets	1,600	1,335
Investments	28,038	33,414
Deferred charges and other assets	21,319	19,832
LIABILITIES AND STOCKHOLDERS’ EQUITY
Other current liabilities	8,682	11,949
Affiliated Entity [Member] | Subsidiary Issuer and Guarantor - Copano
ASSETS
All other current assets	0	11
Investments	2,341	1,911
Deferred charges and other assets	0	0
LIABILITIES AND STOCKHOLDERS’ EQUITY
Other current liabilities	39	115
Affiliated Entity [Member] | Subsidiary Guarantors
ASSETS
All other current assets	9,451	11,565
Investments	4,361	4,628
Deferred charges and other assets	2,070	2,415
LIABILITIES AND STOCKHOLDERS’ EQUITY
Other current liabilities	3,216	1,482
Affiliated Entity [Member] | Subsidiary Non-Guarantors
ASSETS
All other current assets	695	403
Investments	3,320	3,337
Deferred charges and other assets	380	496
LIABILITIES AND STOCKHOLDERS’ EQUITY
Other current liabilities	714	866
Affiliated Entity [Member] | Consolidated KMI
ASSETS
All other current assets	0	0
Investments	0	0
Deferred charges and other assets	0	0
LIABILITIES AND STOCKHOLDERS’ EQUITY
Other current liabilities	0	0
Affiliated Entity [Member] | Consolidating Adjustments
ASSETS
All other current assets	(13,979)	(15,565)
Investments	(65,461)	(68,576)
Deferred charges and other assets	(24,619)	(23,265)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Other current liabilities	$ (13,979)	$ (15,565)

Guarantee of Securities of S127

Guarantee of Securities of Subsidiaries Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Guarantor Obligations [Line Items]
Net cash provided by (used in) operating activities	$ 5,303	$ 4,467	$ 4,122
Capital expenditures	(3,896)	(3,617)	(3,369)
Proceeds from sales of assets and investments	0	0	490
Contributions to investments	(96)	(389)	(217)
Acquisitions of assets and investments	(2,079)	(1,388)	(292)
Distributions from equity investments in excess of cumulative earnings	228	182	185
Other, net	137	2	81
Net Cash Used in Investing Activities	(5,706)	(5,210)	(3,122)
Issuances of debt	14,316	24,573	13,581
Payments of debt	(15,116)	(17,801)	(12,393)
Debt issue costs	(24)	(89)	(38)
Issuances of common shares	3,870	0	0
Issuance of mandatory convertible preferred stock	1,541	0	0
Cash dividends	(4,224)	(1,760)	(1,622)
Payments for repurchases of shares and warrants	(12)	(192)	(637)
Cash consideration of Merger Transactions (Note 1)	0	(3,937)	0
Merger Transactions costs	(2)	(74)	0
Contributions from noncontrolling interests	11	1,767	1,706
Distributions to noncontrolling interests	(34)	(2,013)	(1,692)
Other, net	1	(3)	0
Net Cash Provided by (Used in) Financing Activities	327	471	(1,095)
Effect of exchange rate changes on cash and cash equivalents	(10)	(11)	(21)
Net decrease in Cash and Cash Equivalents	(86)	(283)	(116)
Cash and Cash Equivalents, at Carrying Value	229	315	598	$ 714
Parent Issuer and Guarantor
Guarantor Obligations [Line Items]
Net cash provided by (used in) operating activities	(4,218)	1,419	1,792
Funding to affiliates	(3,204)	(1,949)	(413)
Capital expenditures	(10)	(1)	(6)
Proceeds from sales of assets and investments			0
Contributions to investments	(21)	0	(6)
Investment in KMP	(159)	(550)	(68)
Acquisitions of assets and investments	(1,843)	0	0
Drop down assets to KMP		(875)	(994)
Distributions from equity investments in excess of cumulative earnings	2,653	93	41
Other, net	0	0	0
Net Cash Used in Investing Activities	(2,584)	(1,532)	542
Issuances of debt	14,316	10,594	3,028
Payments of debt	(14,048)	(5,479)	(3,624)
Funding from (to) affiliates	5,502	956	570
Debt issue costs	(24)	(74)	(15)
Issuances of common shares	3,870
Issuance of mandatory convertible preferred stock	1,541
Cash dividends	(4,224)	(1,760)	(1,622)
Payments for repurchases of shares and warrants	(12)	(192)	(637)
Cash consideration of Merger Transactions (Note 1)		(3,937)
Merger Transactions costs		(74)
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	0	0	1
Net Cash Provided by (Used in) Financing Activities	6,921	34	(2,299)
Effect of exchange rate changes on cash and cash equivalents	0	0	0
Net decrease in Cash and Cash Equivalents	119	(79)	35
Cash and Cash Equivalents, at Carrying Value	123	4	83	48
Subsidiary Issuer and Guarantor - KMP
Guarantor Obligations [Line Items]
Net cash provided by (used in) operating activities	6,824	3,810	3,669
Funding to affiliates	(8,388)	(6,644)	(7,183)
Capital expenditures	0	0	0
Proceeds from sales of assets and investments			0
Contributions to investments	0	(189)	(52)
Investment in KMP	0	0	0
Acquisitions of assets and investments	0	0	0
Drop down assets to KMP		875	0
Distributions from equity investments in excess of cumulative earnings	0	440	296
Other, net	24	27	(12)
Net Cash Used in Investing Activities	(8,364)	(7,241)	(6,951)
Issuances of debt	0	13,979	10,300
Payments of debt	(675)	(12,171)	(7,802)
Funding from (to) affiliates	6,989	4,129	2,984
Debt issue costs	0	(15)	(22)
Issuances of common shares	0
Issuance of mandatory convertible preferred stock	0
Cash dividends	0	0	0
Payments for repurchases of shares and warrants	0	0	0
Cash consideration of Merger Transactions (Note 1)		0
Merger Transactions costs		0
Contributions from parents	156	1,912	1,620
Contributions from noncontrolling interests	0	0	0
Distributions to parents	(4,944)	(4,475)	(3,914)
Distributions to noncontrolling interests	0	0	0
Other, net	(1)	(1)	(1)
Net Cash Provided by (Used in) Financing Activities	1,525	3,358	3,165
Effect of exchange rate changes on cash and cash equivalents	0	0	0
Net decrease in Cash and Cash Equivalents	(15)	(73)	(117)
Cash and Cash Equivalents, at Carrying Value	0	15	88	205
Subsidiary Issuer and Guarantor - Copano
Guarantor Obligations [Line Items]
Net cash provided by (used in) operating activities	98	(77)	(408)
Funding to affiliates	(1)	0	(1)
Capital expenditures	(2)	(63)	(141)
Proceeds from sales of assets and investments			0
Contributions to investments	0	0	0
Investment in KMP	0	0	0
Acquisitions of assets and investments	0	0	5
Drop down assets to KMP		0	0
Distributions from equity investments in excess of cumulative earnings	0	0	0
Other, net	5	202	0
Net Cash Used in Investing Activities	2	139	(137)
Issuances of debt	0	0	0
Payments of debt	0	0	(854)
Funding from (to) affiliates	(100)	(63)	1,400
Debt issue costs	0	0	0
Issuances of common shares	0
Issuance of mandatory convertible preferred stock	0
Cash dividends	0	0	0
Payments for repurchases of shares and warrants	0	0	0
Cash consideration of Merger Transactions (Note 1)		0
Merger Transactions costs		0
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	0	0	0
Net Cash Provided by (Used in) Financing Activities	(100)	(63)	546
Effect of exchange rate changes on cash and cash equivalents	0	0	0
Net decrease in Cash and Cash Equivalents	0	(1)	1
Cash and Cash Equivalents, at Carrying Value	0	0	1	0
Subsidiary Guarantors
Guarantor Obligations [Line Items]
Net cash provided by (used in) operating activities	10,691	5,876	5,118
Funding to affiliates	(8,004)	(3,886)	(3,944)
Capital expenditures	(3,557)	(3,050)	(2,418)
Proceeds from sales of assets and investments			118
Contributions to investments	(70)	(389)	(217)
Investment in KMP	0	0	0
Acquisitions of assets and investments	(236)	(1,370)	(297)
Drop down assets to KMP		0	994
Distributions from equity investments in excess of cumulative earnings	143	183	183
Other, net	55	20	105
Net Cash Used in Investing Activities	(11,669)	(8,492)	(7,464)
Issuances of debt	0	0	14
Payments of debt	(383)	(142)	(106)
Funding from (to) affiliates	7,486	7,624	7,127
Debt issue costs	0	0	0
Issuances of common shares	0
Issuance of mandatory convertible preferred stock	0
Cash dividends	0	0	0
Payments for repurchases of shares and warrants	0	0	0
Cash consideration of Merger Transactions (Note 1)		0
Merger Transactions costs		0
Contributions from parents	3	533	75
Contributions from noncontrolling interests	0	0	0
Distributions to parents	(6,133)	(5,398)	(4,776)
Distributions to noncontrolling interests	0	0	0
Other, net	0	(2)	0
Net Cash Provided by (Used in) Financing Activities	973	2,615	2,334
Effect of exchange rate changes on cash and cash equivalents	0	1	1
Net decrease in Cash and Cash Equivalents	(5)	0	(11)
Cash and Cash Equivalents, at Carrying Value	12	17	17	28
Subsidiary Non-Guarantors
Guarantor Obligations [Line Items]
Net cash provided by (used in) operating activities	811	1,174	769
Funding to affiliates	(1,066)	(1,088)	(1,332)
Capital expenditures	(332)	(705)	(804)
Proceeds from sales of assets and investments			372
Contributions to investments	(10)	0	0
Investment in KMP	0	0	0
Acquisitions of assets and investments	0	(18)	0
Drop down assets to KMP		0	0
Distributions from equity investments in excess of cumulative earnings	0	0	0
Other, net	58	(46)	(12)
Net Cash Used in Investing Activities	(1,350)	(1,857)	(1,776)
Issuances of debt	0	0	239
Payments of debt	(10)	(9)	(7)
Funding from (to) affiliates	786	921	792
Debt issue costs	0	0	(1)
Issuances of common shares	0
Issuance of mandatory convertible preferred stock	0
Cash dividends	0	0	0
Payments for repurchases of shares and warrants	0	0	0
Cash consideration of Merger Transactions (Note 1)		0
Merger Transactions costs		0
Contributions from parents	16	64	132
Contributions from noncontrolling interests	0	0	0
Distributions to parents	(380)	(411)	(150)
Distributions to noncontrolling interests	0	0	0
Other, net	0	0	0
Net Cash Provided by (Used in) Financing Activities	412	565	1,005
Effect of exchange rate changes on cash and cash equivalents	(10)	(12)	(22)
Net decrease in Cash and Cash Equivalents	(137)	(130)	(24)
Cash and Cash Equivalents, at Carrying Value	142	279	409	433
Consolidated KMI
Guarantor Obligations [Line Items]
Net cash provided by (used in) operating activities	5,303	4,467	4,122
Funding to affiliates	0	0	0
Capital expenditures	(3,896)	(3,617)	(3,369)
Proceeds from sales of assets and investments			490
Contributions to investments	(96)	(389)	(217)
Investment in KMP	0	0	0
Acquisitions of assets and investments	(2,079)	(1,388)	(292)
Drop down assets to KMP		0	0
Distributions from equity investments in excess of cumulative earnings	228	182	185
Other, net	137	2	81
Net Cash Used in Investing Activities	(5,706)	(5,210)	(3,122)
Issuances of debt	14,316	24,573	13,581
Payments of debt	(15,116)	(17,801)	(12,393)
Funding from (to) affiliates	0	0	0
Debt issue costs	(24)	(89)	(38)
Issuances of common shares	3,870
Issuance of mandatory convertible preferred stock	1,541
Cash dividends	(4,224)	(1,760)	(1,622)
Payments for repurchases of shares and warrants	(12)	(192)	(637)
Cash consideration of Merger Transactions (Note 1)		(3,937)
Merger Transactions costs		(74)
Contributions from parents	0	0	0
Contributions from noncontrolling interests	11	1,767	1,706
Distributions to parents	0	0	0
Distributions to noncontrolling interests	(34)	(2,013)	(1,692)
Other, net	(1)	(3)	0
Net Cash Provided by (Used in) Financing Activities	327	471	(1,095)
Effect of exchange rate changes on cash and cash equivalents	(10)	(11)	(21)
Net decrease in Cash and Cash Equivalents	(86)	(283)	(116)
Cash and Cash Equivalents, at Carrying Value	229	315	598	714
Consolidating Adjustments
Guarantor Obligations [Line Items]
Net cash provided by (used in) operating activities	(8,903)	(7,735)	(6,818)
Funding to affiliates	20,663	13,567	12,873
Capital expenditures	5	202	0
Proceeds from sales of assets and investments			0
Contributions to investments	5	189	58
Investment in KMP	159	550	68
Acquisitions of assets and investments	0	0	0
Drop down assets to KMP		0	0
Distributions from equity investments in excess of cumulative earnings	(2,568)	(534)	(335)
Other, net	(5)	(201)	0
Net Cash Used in Investing Activities	18,259	13,773	12,664
Issuances of debt	0	0	0
Payments of debt	0	0	0
Funding from (to) affiliates	(20,663)	(13,567)	(12,873)
Debt issue costs	0	0	0
Issuances of common shares	0
Issuance of mandatory convertible preferred stock	0
Cash dividends	0	0	0
Payments for repurchases of shares and warrants	0	0	0
Cash consideration of Merger Transactions (Note 1)		0
Merger Transactions costs		0
Contributions from parents	(175)	(2,509)	(1,827)
Contributions from noncontrolling interests	11	1,767	1,706
Distributions to parents	11,457	10,284	8,840
Distributions to noncontrolling interests	(34)	(2,013)	(1,692)
Other, net	0	0	0
Net Cash Provided by (Used in) Financing Activities	(9,404)	(6,038)	(5,846)
Effect of exchange rate changes on cash and cash equivalents	0	0	0
Net decrease in Cash and Cash Equivalents	(48)	0	0
Cash and Cash Equivalents, at Carrying Value	$ (48)	$ 0	$ 0	$ 0

Guarantee of Securities of S128

Guarantee of Securities of Subsidiaries Guarantee of Securities of Subsidiaries (Details) $ in Millions	Dec. 31, 2015USD ($)
Parent Issuer and Guarantor
Long-term Debt	$ 13,346
Subsidiary Issuer and Guarantor - KMP
Long-term Debt	19,985
Subsidiary Issuer and Guarantor - Copano
Long-term Debt	332
Subsidiary Guarantors
Long-term Debt	6,882
Capitalized Lease Debt Not Subject to Cross Guarantee Agreement	$ 177