Energy Transfer Operating (ET+E) 10-K 23 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Feb. 16, 2018	Jun. 30, 2017
Document Information [Line Items]
Entity Current Reporting Status	Yes
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Entity Registrant Name	Energy Transfer Partners, L.P.
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Central Index Key	1,161,154
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		1,164,024,480
Entity Public Float			$ 21,660
Entity Common Stock, Shares Outstanding	2,017
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 306	$ 360
Accounts receivable, net	3,946	3,002
Accounts receivable from related companies	318	209
Inventories	1,589	1,626
Income taxes receivable	135	128
Derivative assets	24	20
Other current assets	210	298
Total current assets	6,528	5,643
Property, plant and equipment	67,699	58,220
Accumulated depreciation and depletion	(9,262)	(7,303)
PROPERTY, PLANT AND EQUIPMENT, net	58,437	50,917
Advances to and investments in unconsolidated affiliates	3,816	4,280
Other non-current assets, net	758	672
Intangible assets, net	5,311	4,696
Goodwill	3,115	3,897
Total assets	77,965	70,105
Current liabilities:
Accounts payable	4,126	2,900
Accounts payable to related companies	209	43
Derivative liabilities	109	166
Accrued and other current liabilities	2,143	1,905
Current maturities of long-term debt	407	1,189
Total current liabilities	6,994	6,203
Long-term debt, less current maturities	32,687	31,741
Long-term notes payable – related company	0	250
Non-current derivative liabilities	145	76
Deferred income taxes	2,883	4,394
Other non-current liabilities	1,084	952
Commitments and contingencies
Legacy ETP Preferred Units	0	33
Redeemable noncontrolling interests	21	15
Equity:
General Partner	244	206
Limited Partners:
Common Unitholders (1,164,112,575 and 794,803,854 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)	26,531	14,925
Class E Unitholder (8,853,832 units authorized, issued and outstanding – held by subsidiary)	0	0
Class G Unitholder (90,706,000 units authorized, issued and outstanding – held by subsidiary)	0	0
Class H Unitholder (81,001,069 units authorized, issued and outstanding as of December 31, 2016)	0	3,480
Class I Unitholder (100 units authorized, issued and outstanding)	0	2
Class K Unitholders (101,525,429 units authorized, issued and outstanding – held by subsidiaries)	0	0
Accumulated other comprehensive income	3	8
Total partners’ capital	28,269	18,621
Noncontrolling interest	5,882	7,820
Total equity	34,151	26,441
Total liabilities and equity	77,965	70,105
Series A Preferred Units [Member]
Equity:
Preferred Units	944	0
Series B Preferred Units [Member]
Equity:
Preferred Units	$ 547	$ 0

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2017	Dec. 31, 2016
Series A Preferred Units [Member]
Preferred Units, Authorized	950,000	0
Preferred Units, Issued	950,000	0
Preferred Units, Outstanding	950,000	0
Series B Preferred Units [Member]
Preferred Units, Authorized	550,000	0
Preferred Units, Issued	550,000	0
Preferred Units, Outstanding	550,000	0
Common Units
Units - Outstanding	1,164,112,575	794,803,854
Class E Units
Units - Authorized	8,853,832	8,853,832
Units - Issued	8,853,832	8,853,832
Units - Outstanding	8,853,832	8,853,832
Class G Units
Units - Authorized	90,706,000	90,706,000
Units - Issued	90,706,000	90,706,000
Units - Outstanding	90,706,000	90,706,000
Class H Units
Units - Authorized	0	81,001,069
Units - Issued	0	81,001,069
Units - Outstanding	0	81,001,069
Class I Units
Units - Authorized	100	100
Units - Issued	100	100
Units - Outstanding	100	100
Class K Units [Member]
Units - Authorized	101,525,429	101,525,429
Units - Issued	101,525,429	101,525,429
Units - Outstanding	101,525,429	101,525,429

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
REVENUES:
Natural gas sales	$ 4,172	$ 3,619	$ 3,671
NGL sales	6,972	4,841	3,936
Crude sales	10,184	6,766	8,378
Gathering, transportation and other fees	4,265	4,003	3,997
Refined product sales (see Note 3)	1,515	1,047	9,958
Other (see Note 3)	1,946	1,551	4,352
Total revenues	29,054	21,827	34,292
COSTS AND EXPENSES:
Cost of products sold (see Note 3)	20,801	15,080	26,714
Operating expenses (see Note 3)	2,170	1,839	2,608
Depreciation, depletion and amortization	2,332	1,986	1,929
Selling, general and administrative (see Note 3)	434	348	475
Impairment losses	920	813	339
Total costs and expenses	26,657	20,066	32,065
OPERATING INCOME	2,397	1,761	2,227
OTHER INCOME (EXPENSE):
Interest expense, net	(1,365)	(1,317)	(1,291)
Equity in earnings from unconsolidated affiliates	156	59	469
Impairment of investments in unconsolidated affiliates	(313)	(308)	0
Gains on acquisitions	0	83	0
Losses on extinguishments of debt	(42)	0	(43)
Losses on interest rate derivatives	(37)	(12)	(18)
Other, net	209	131	22
INCOME BEFORE INCOME TAX BENEFIT	1,005	397	1,366
Income tax benefit	(1,496)	(186)	(123)
NET INCOME	2,501	583	1,489
Less: Net income attributable to noncontrolling interest	420	295	134
Less: Net loss attributable to predecessor	0	0	(34)
NET INCOME ATTRIBUTABLE TO PARTNERS	2,081	288	1,389
General Partner’s interest in net income	990	948	1,064
Preferred Unitholders’ interest in net income	12	0	0
Class H Unitholder’s interest in net income	93	351	258
Class I Unitholder’s interest in net income	0	8	94
Common Unitholders’ interest in net income (loss)	$ 986	$ (1,019)	$ (27)
INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT:
Basic net income (loss) per Common Unit	$ 0.94	$ (1.38)	$ (0.07)
Diluted income (loss) per Common Unit	0.93	(1.38)	(0.08)
NET INCOME (LOSS) PER COMMON UNIT:
Basic	0.94	(1.38)	(0.07)
Diluted	$ 0.93	$ (1.38)	$ (0.08)

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net income	$ 2,501	$ 583	$ 1,489
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	6	2	(3)
Actuarial gain (loss) relating to pension and other postretirement benefits	(12)	(1)	65
Foreign currency translation adjustment	0	(1)	(1)
Change in other comprehensive income (loss) from unconsolidated affiliates	1	4	(1)
Total other comprehensive income	(5)	4	60
Comprehensive income	2,496	587	1,549
Less: Comprehensive income attributable to noncontrolling interest	420	295	134
Less: Comprehensive loss attributable to predecessor	0	0	(34)
Comprehensive income attributable to partners	$ 2,076	$ 292	$ 1,449

CONSOLIDATED STATEMENT OF EQUIT

CONSOLIDATED STATEMENT OF EQUITY - USD ($) $ in Millions	Total	General Partner	Limited Partner [Member]	Class H [Member]	Class I Units	AOCI Attributable to Parent [Member]	Noncontrolling Interest [Member]	Predecessor Equity [Member]	Series A Preferred Units [Member]	Series B Preferred Units [Member]	Bakken Pipeline Transaction [Member]	Bakken Pipeline Transaction [Member]General Partner	Bakken Pipeline Transaction [Member]Limited Partner [Member]	Bakken Pipeline Transaction [Member]Class H [Member]	Bakken Pipeline Transaction [Member]Class I Units	Bakken Pipeline Transaction [Member]AOCI Attributable to Parent [Member]	Bakken Pipeline Transaction [Member]Noncontrolling Interest [Member]	Bakken Pipeline Transaction [Member]Predecessor Equity [Member]	Bakken Pipeline Transaction [Member]Series A Preferred Units [Member]	Bakken Pipeline Transaction [Member]Series B Preferred Units [Member]	PennTex Acquisition [Member]	PennTex Acquisition [Member]Limited Partner [Member]	Sale of Bakken Pipeline interest [Member]	Sale of Bakken Pipeline interest [Member]General Partner	Sale of Bakken Pipeline interest [Member]Limited Partner [Member]	Sale of Bakken Pipeline interest [Member]Class H [Member]	Sale of Bakken Pipeline interest [Member]Class I Units	Sale of Bakken Pipeline interest [Member]AOCI Attributable to Parent [Member]	Sale of Bakken Pipeline interest [Member]Noncontrolling Interest [Member]	Sale of Bakken Pipeline interest [Member]Predecessor Equity [Member]	Sale of Bakken Pipeline interest [Member]Series A Preferred Units [Member]	Sale of Bakken Pipeline interest [Member]Series B Preferred Units [Member]	Sale of Rover Pipeline interest [Member]	Sale of Rover Pipeline interest [Member]General Partner	Sale of Rover Pipeline interest [Member]Limited Partner [Member]	Sale of Rover Pipeline interest [Member]Class H [Member]	Sale of Rover Pipeline interest [Member]Class I Units	Sale of Rover Pipeline interest [Member]AOCI Attributable to Parent [Member]	Sale of Rover Pipeline interest [Member]Noncontrolling Interest [Member]	Sale of Rover Pipeline interest [Member]Predecessor Equity [Member]	Sale of Rover Pipeline interest [Member]Series A Preferred Units [Member]	Sale of Rover Pipeline interest [Member]Series B Preferred Units [Member]	Sunoco LP Exchange [Member]	Sunoco LP Exchange [Member]General Partner	Sunoco LP Exchange [Member]Limited Partner [Member]	Sunoco LP Exchange [Member]Class H [Member]	Sunoco LP Exchange [Member]Class I Units	Sunoco LP Exchange [Member]AOCI Attributable to Parent [Member]	Sunoco LP Exchange [Member]Noncontrolling Interest [Member]	Sunoco LP Exchange [Member]Predecessor Equity [Member]	Sunoco LP Exchange [Member]Series A Preferred Units [Member]	Sunoco LP Exchange [Member]Series B Preferred Units [Member]	Susser Exchange Transaction [Member]	Susser Exchange Transaction [Member]General Partner	Susser Exchange Transaction [Member]Limited Partner [Member]	Susser Exchange Transaction [Member]Class H [Member]	Susser Exchange Transaction [Member]Class I Units	Susser Exchange Transaction [Member]AOCI Attributable to Parent [Member]	Susser Exchange Transaction [Member]Noncontrolling Interest [Member]	Susser Exchange Transaction [Member]Predecessor Equity [Member]	Susser Exchange Transaction [Member]Series A Preferred Units [Member]	Susser Exchange Transaction [Member]Series B Preferred Units [Member]
Balance at Dec. 31, 2014	$ 25,298	$ 184	$ 10,427	$ 1,512	$ 0	$ (56)	$ 5,143	$ 8,088	$ 0	$ 0
Increase (Decrease) in Unitholders' Equity
Distributions to partners	(3,134)	(944)	(1,863)	(247)	(80)	0	0	0	0	0
Predecessor distributions to partners	202	0	0	0	0	0	0	202	0	0
Distributions to noncontrolling interest	(338)	0	0	0	0	0	(338)	0	0	0
Units issued for cash	1,428	0	1,428	0	0	0	0	0	0	0
Predecessor units issued for cash	34	0	0	0	0	0	0	34	0	0
Regency Merger	0	0	7,890	0	0	0	0	(7,890)	0	0
Capital contributions from noncontrolling interest	875	0	0	0	0	0	875	0	0	0
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	1,946
Susser Merger																					$ 0
Subsidiary units issued for cash	1,519	2	298	0	0	0	1,219	0	0	0
Exchange of equity and Controlling Interest in a Subsidiary											$ 1,019	$ 0	$ (999)	$ 1,946	$ 0	$ 0	$ 72	$ 0	$ 0	$ 0																							$ (992)	$ 0	$ (52)	$ 0	$ 0	$ 0	$ (940)	$ 0	$ 0	$ 0	$ (68)	$ 0	$ (68)	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
Acquisition and disposition of noncontrolling interest	(65)	0	(26)	0	0	0	(39)	0	0	0
Other comprehensive income, net of tax	60	0	0	0	0	60	0	0	0	0
Other, net	63	0	23	0	0	0	36	4	0	0
Net income	1,489	1,064	(27)	258	94	0	134	(34)	0	0
Class H Unitholder’s interest in net income	258
Net Income (Loss) Allocated to General Partners	1,064
Less: Net income attributable to noncontrolling interest	134
Balance at Dec. 31, 2015	26,986	306	17,031	3,469	14	4	6,162	0	0	0
Increase (Decrease) in Unitholders' Equity
Distributions to partners	(3,542)	(1,048)	(2,134)	(340)	(20)	0	0	0	0	0
Distributions to noncontrolling interest	(481)	0	0	0	0	0	(481)	0	0	0
Units issued for cash	1,098	0	1,098	0	0	0	0	0	0	0
Predecessor units issued for cash	0
Capital contributions from noncontrolling interest	236	0	0	0	0	0	236	0	0	0
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	0
Susser Merger	543	0		0	0	0	236	0	0	0											307	$ 307
Subsidiary units issued for cash	1,388	0	37	0	0	0	1,351	0	0	0
Exchange of equity and Controlling Interest in a Subsidiary	(405)	0	(405)	0	0	0	0	0	0	0
Other comprehensive income, net of tax	4	0	0	0	0	4	0	0	0	0
Other, net	31	0	10	0	0	0	21	0	0	0
Net income	583	948	(1,019)	351	8	0	295	0	0	0
Class H Unitholder’s interest in net income	351
Net Income (Loss) Allocated to General Partners	948
Less: Net income attributable to noncontrolling interest	295
Balance at Dec. 31, 2016	26,441	206	14,925	3,480	2	8	7,820	0	0	0
Increase (Decrease) in Unitholders' Equity
Distributions to partners	(3,468)	(952)	(2,419)	(95)	(2)	0	0	0	0	0
Distributions to noncontrolling interest	(430)	0	0	0	0	0	(430)	0	0	0
Units issued for cash	3,762	0	2,283	0	0	0	0	0	937	542
Predecessor units issued for cash	0
Capital contributions from noncontrolling interest	2,202	0	0	0	0	0	2,202	0	0	0
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	0																						$ 2,000	$ 0	$ 1,260	$ 0	$ 0	$ 0	$ 740	$ 0	$ 0	$ 0	$ 1,478	$ 0	$ 93	$ 0	$ 0	$ 0	$ 1,385	$ 0	$ 0	$ 0
Susser Merger	0	0	9,416	(3,478)	0	0	(5,938)	0	0	0											$ 0
Acquisition and disposition of noncontrolling interest	(280)	0	(48)	0	0	0	(232)	0	0	0
Other comprehensive income, net of tax	(5)	0	0	0	0	(5)	0	0	0	0
Other, net	(50)	0	35	0	0	0	(85)	0	0	0
Net income	2,501	990	986	93	0	0	420	0	7	5
Class H Unitholder’s interest in net income	93
Net Income (Loss) Allocated to General Partners	990
Less: Net income attributable to noncontrolling interest	420
Balance at Dec. 31, 2017	$ 34,151	$ 244	$ 26,531	$ 0	$ 0	$ 3	$ 5,882	$ 0	$ 944	$ 547

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 2,501	$ 583	$ 1,489
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	2,332	1,986	1,929
Deferred income taxes	(1,531)	(169)	202
Amortization included in interest expense	2	(20)	(36)
Inventory valuation adjustments	0
Unit-based compensation expense	74	80	79
Impairment losses	920	813	339
Gains on acquisitions	0	(83)	0
Losses on extinguishments of debt	42	0	43
Impairment of investments in unconsolidated affiliates	313	308	0
Distributions on unvested awards	(31)	(25)	(16)
Equity in earnings of unconsolidated affiliates	(156)	(59)	(469)
Distributions from unconsolidated affiliates	440	406	440
Other non-cash	(261)	(271)	(22)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	(160)	(246)	(1,173)
Net cash provided by operating activities	4,485	3,303	2,747
INVESTING ACTIVITIES:
Cash transferred to ETE in connection with the Sunoco LP Exchange	0	0	(114)
Cash paid for acquisition of a noncontrolling interest	0	0	(129)
Cash paid for all other acquisitions	(264)	(159)	(675)
Capital expenditures, excluding allowance for equity funds used during construction	(8,335)	(7,550)	(9,098)
Contributions in aid of construction costs	24	71	80
Contributions to unconsolidated affiliates	(268)	(59)	(45)
Distributions from unconsolidated affiliates in excess of cumulative earnings	136	135	124
Proceeds from the sale of assets	35	25	23
Change in restricted cash	0	14	19
Other	1	1	(16)
Net cash used in investing activities	(5,473)	(6,390)	(7,820)
FINANCING ACTIVITIES:
Proceeds from borrowings	26,736	19,916	22,462
Repayments of long-term debt	(26,494)	(15,799)	(17,843)
Repayments of Related Party Debt	(255)
Cash (paid to) received from affiliate notes		124	233
Common Units issued for cash	2,283	1,098	1,428
Preferred Units issued for cash	1,479	0	0
Predecessor units issued for cash	0	0	34
Subsidiary units issued for cash	0	1,388	1,519
Capital contributions from noncontrolling interest	1,214	236	841
Distributions to partners	3,468	3,542	3,134
Predecessor distributions to partners	0	0	(202)
Distributions to noncontrolling interest	(430)	(481)	(338)
Redemption of Legacy ETP Preferred Units	(53)	0	0
Debt issuance costs	(83)	(22)	(63)
Other	5	2	0
Net cash provided by financing activities	934	2,920	4,937
Decrease in cash and cash equivalents	(54)	(167)	(136)
Cash and cash equivalents, beginning of period	360	527	663
Cash and cash equivalents, end of period	306	360	527
Bakken Pipeline [Member]
INVESTING ACTIVITIES:
Proceeds from Divestiture of Interest in Joint Venture	2,000	0	0
Rover Pipeline LLC [Member]
INVESTING ACTIVITIES:
Proceeds from Divestiture of Interest in Joint Venture	1,478	0	0
PennTex [Member]
INVESTING ACTIVITIES:
Cash paid for all other acquisitions	280	0	0
Vitol Acquisition [Member]
INVESTING ACTIVITIES:
Cash paid for all other acquisitions	0	769	0
PennTex Acquisition [Member]
INVESTING ACTIVITIES:
Cash paid for all other acquisitions	0	299	0
Legacy Sunoco, Inc. [Member]
INVESTING ACTIVITIES:
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction	0	2,200	0
Bakken Pipeline Transaction [Member]
INVESTING ACTIVITIES:
Proceeds from sale of noncontrolling interest	0	0	980
Susser Exchange Transaction [Member]
INVESTING ACTIVITIES:
Proceeds from sale of noncontrolling interest	0	0	967
Rover Pipeline Sale [Member]
INVESTING ACTIVITIES:
Proceeds from sale of noncontrolling interest	$ 0	$ 0	$ 64

Operations and Organization (No

Operations and Organization (Notes)	12 Months Ended
	Dec. 31, 2017
Operations And Organization [Abstract]
OPERATIONS AND ORGANIZATION	OPERATIONS AND BASIS OF PRESENTATION: Organization. The consolidated financial statements presented herein contain the results of Energy Transfer Partners, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETP”). The Partnership is managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner. In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled. In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of maintaining clarity, the following references are used herein: • References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger; • References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and • References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger. The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes). The Sunoco Logistics Merger was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assets and liabilities in the consolidated financial statements, and no gain or loss was recognized. For the periods prior to the Sunoco Logistics Merger, the Sunoco Logistics limited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements. The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger. The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales. The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States. The Partnership owns a controlling interest in Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products. Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity. Management evaluated subsequent events through the date the financial statements were issued. For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity. The Partnership owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, these undivided interests are consolidated proportionately.

Estimates, Significant Accounti

Estimates, Significant Accounting Policies and Balance Sheet Detials (Notes)	12 Months Ended
	Dec. 31, 2017
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Estimates Significant Accounting Policies And Balance Sheet Detail Text Block	ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL: Change in Accounting Policy During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method. As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows: Year Ended December 31, 2016 Year Ended December 31, 2015 As Originally Reported* Effect of Change As Adjusted As Originally Reported* Effect of Change As Adjusted Consolidated Statement of Operations and Comprehensive Income: Cost of products sold $ 15,039 $ 41 $ 15,080 $ 26,682 $ 32 $ 26,714 Operating income 1,802 (41 ) 1,761 2,259 (32 ) 2,227 Income before income tax benefit 438 (41 ) 397 1,398 (32 ) 1,366 Net income 624 (41 ) 583 1,521 (32 ) 1,489 Net income attributable to partners 297 (9 ) 288 1,398 (9 ) 1,389 Net loss per common unit - basic (1.37 ) (0.01 ) (1.38 ) (0.06 ) (0.01 ) (0.07 ) Net loss per common unit - diluted (1.37 ) (0.01 ) (1.38 ) (0.07 ) (0.01 ) (0.08 ) Comprehensive income 628 (41 ) 587 1,581 (32 ) 1,549 Comprehensive income attributable to partners 301 (9 ) 292 1,458 (9 ) 1,449 Consolidated Statements of Cash Flows: Net income 624 (41 ) 583 1,521 (32 ) 1,489 Inventory valuation adjustments (170 ) 170 — 104 (162 ) (58 ) Net change in operating assets and liabilities (change in inventories) (117 ) (129 ) (246 ) (1,367 ) 194 (1,173 ) Consolidated Balance Sheets (at period end): Inventories 1,712 (86 ) 1,626 1,213 (45 ) 1,168 Total partners' capital 18,642 (21 ) 18,621 20,836 (12 ) 20,824 * Amounts reflect certain reclassifications made to conform to the current year presentation. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates. Recent Accounting Pronouncements ASU 2014-09 In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material. For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of our midstream segment agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income. ASU 2016-02 In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. ASU 2016-16 On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. ASU 2017-04 In January 2017, the FASB issued ASU No. 2017-04 “ Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment. ” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017. ASU 2017-12 In August 2017, the FASB issued ASU No. 2017-12 “ Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. ” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. Revenue Recognition Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues. Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and segment margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors. NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer. In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized. We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations. Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs. Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2017 2016 2015 Accounts receivable $ (950 ) $ (919 ) $ 819 Accounts receivable from related companies 67 30 (243 ) Inventories 37 (497 ) (157 ) Other current assets 39 83 (178 ) Other non-current assets, net (94 ) (78 ) 188 Accounts payable 758 972 (1,215 ) Accounts payable to related companies (3 ) 29 (160 ) Accrued and other current liabilities (47 ) 39 (83 ) Other non-current liabilities 24 33 (219 ) Price risk management assets and liabilities, net 9 62 75 Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (160 ) $ (246 ) $ (1,173 ) Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2017 2016 2015 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 1,059 $ 822 $ 896 Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP — 194 — Net gains from subsidiary common unit transactions — 37 300 NON-CASH FINANCING ACTIVITIES: Issuance of Common Units in connection with the PennTex Acquisition $ — $ 307 $ — Issuance of Common Units in connection with the Regency Merger — — 9,250 Issuance of Class H Units in connection with the Bakken Pipeline Transaction — — 1,946 Contribution of assets from noncontrolling interest 988 — 34 Redemption of Common Units in connection with the Bakken Pipeline Transaction — — 999 Redemption of Common Units in connection with the Sunoco LP Exchange — — 52 SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 1,329 $ 1,411 $ 1,467 Cash paid for (refund of) income taxes 50 (229 ) 71 Accounts Receivable Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due. We enter into netting arrangements with counterparties to the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets. Inventories As discussed under “Change in Accounting Policy” in Note 2, the Partnership changed its accounting policy for certain inventory in the fourth quarter of 2017. Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method. Inventories consisted of the following: December 31, 2017 2016 Natural gas, NGLs, and refined products $ 733 $ 758 Crude oil 551 651 Spare parts and other 305 217 Total inventories $ 1,589 $ 1,626 We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations. Other Current Assets Other current assets consisted of the following: December 31, 2017 2016 Deposits paid to vendors $ 64 $ 74 Prepaid expenses and other 146 224 Total other current assets $ 210 $ 298 Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2017, the Partnership recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, the Partnership recorded a $133 million fixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds. Components and useful lives of property, plant and equipment were as follows: December 31, 2017 2016 Land and improvements $ 1,706 $ 676 Buildings and improvements (1 to 45 years) 1,960 1,617 Pipelines and equipment (5 to 83 years) 44,050 36,356 Natural gas and NGL storage facilities (5 to 46 years) 1,681 1,452 Bulk storage, equipment and facilities (2 to 83 years) 3,036 3,701 Vehicles (1 to 25 years) 124 217 Right of way (20 to 83 years) 3,424 3,349 Natural resources 434 434 Other (1 to 40 years) 534 484 Construction work-in-process 10,750 9,934 67,699 58,220 Less – Accumulated depreciation and depletion (9,262 ) (7,303 ) Property, plant and equipment, net $ 58,437 $ 50,917 We recognized the following amounts for the periods presented: Years Ended December 31, 2017 2016 2015 Depreciation and depletion expense $ 2,060 $ 1,793 $ 1,713 Capitalized interest 283 199 163 Advances to and Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2017 2016 Regulatory assets $ 85 $ 86 Deferred charges 210 217 Restricted funds 192 190 Long-term affiliated receivable 85 90 Other 186 89 Total other non-current assets, net $ 758 $ 672 Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies. Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: December 31, 2017 December 31, 2016 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 6,250 $ (1,003 ) $ 5,362 $ (737 ) Patents (10 years) 48 (26 ) 48 (21 ) Trade Names (20 years) 66 (25 ) 66 (22 ) Other (5 to 20 years) 1 — 2 (2 ) Total intangible assets $ 6,365 $ (1,054 ) $ 5,478 $ (782 ) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2017 2016 2015 Reported in depreciation, depletion and amortization $ 272 $ 193 $ 216 Estimated aggregate amortization expense for the next five years is as follows: Years Ending December 31: 2018 $ 280 2019 278 2020 278 2021 268 2022 256 We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. In 2015, we recorded $24 million of intangible asset impairments related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows. Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services All Other Total Balance, December 31, 2015 $ 10 $ 912 $ 718 $ 772 $ 912 $ 2,104 $ 5,428 Reduction due to contribution of legacy Sunoco, Inc. retail business — — — — — (1,289 ) (1,289 ) Acquired — — 177 — 251 — 428 Impaired — (638 ) (32 ) — — — (670 ) Balance, December 31, 2016 10 274 863 772 1,163 815 3,897 Acquired — — 8 — 4 — 12 Impaired — (262 ) — (79 ) — (452 ) (793 ) Other — — (1 ) — — — (1 ) Balance, December 31, 2017 $ 10 $ 12 $ 870 $ 693 $ 1,167 $ 363 $ 3,115 Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During the fourth quarter of 2017, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $262 million in the interstate transportation and storage segment, $79 million in the NGL and refined products transportation and services segment and $452 million in the all other segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. During the fourth quarter of 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015. The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by managem

Acquisitions, Divestitures and

Acquisitions, Divestitures and Related Transactions (Notes)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
ACQUISITIONS AND DIVESTITURE	ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS: 2018 Transactions CDM Contribution Agreement In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion , consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately $335 million , (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately $112 million and (iii) an amount in cash equal to $1.225 billion , subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions. In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million . 2017 Transactions Rover Contribution Agreement In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments. ETP and Sunoco Logistics Merger As discussed in Note 1 , in April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed the Sunoco Logistics Merger. Permian Express Partners In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment. In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88% . ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity. Bakken Equity Sale In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction. 2016 Transactions PennTex Acquisition On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately $627 million in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana. As discussed in Note 8, the Partnership purchased PennTex’s remaining outstanding common units in June 2017. Summary of Assets Acquired and Liabilities Assumed We accounted for the PennTex acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. The total purchase price was allocated as follows: At November 1, 2016 Total current assets $ 34 Property, plant and equipment 393 Goodwill (1) 177 Intangible assets 446 1,050 Total current liabilities 6 Long-term debt, less current maturities 164 Other non-current liabilities 17 Noncontrolling interest 236 423 Total consideration 627 Cash received 21 Total consideration, net of cash received $ 606 (1) None of the goodwill is expected to be deductible for tax purposes. The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. Sunoco Logistics’ Vitol Acquisition In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for $760 million plus working capital. The acquisition provides Sunoco Logistics with an approximately 2 million barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50% interest in SunVit Pipeline LLC (“SunVit”), which increased Sunoco Logistics’ overall ownership of SunVit to 100% . The $769 million purchase price, net of cash received, consisted primarily of net working capital of $13 million largely attributable to inventory and receivables; property, plant and equipment of $286 million primarily related to pipeline and terminalling assets; intangible assets of $313 million attributable to customer relationships; and goodwill of $251 million . Bakken Financing In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The $2.50 billion credit facility provided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2017 , $2.50 billion was outstanding under this credit facility. Bayou Bridge In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a 30% interest in the entity and Sunoco Logistics is the operator of the system. Sunoco Retail to Sunoco LP In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion . Sunoco LP paid $2.20 billion in cash, including a working capital adjustment and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016. In connection with this transaction, the Partnership deconsolidated the legacy Sunoco, Inc. retail business, including goodwill of $1.29 billion and intangible assets of $294 million . The results of Sunoco, LLC and the legacy Sunoco, Inc. retail business’ operations have not been presented as discontinued operations and Sunoco, Inc.’s retail business assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements. Following is a summary of amounts reflected for the prior periods in ETP’s consolidated statements of operations related to Sunoco, LLC and the legacy Sunoco, Inc. retail business, which operations are no longer consolidated: Year Ended December 31, 2015 Revenues $ 12,482 Cost of products sold 11,174 Operating expenses 798 Selling, general and administrative expenses 106 2015 Transactions Sunoco LP In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million . Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million in Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015. In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million . The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries. Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE (the “Sunoco LP Exchange”). In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years , which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE provided ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. In connection with this transaction, the Partnership deconsolidated Sunoco LP, including goodwill of $1.81 billion and intangible assets of $982 million related to Sunoco LP. At December 31, 2017, the Partnership held 37.8 million Sunoco LP common units accounted for under the equity method. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, as discussed in Note 4 , our investment in Sunoco LP consists of 26.2 million units. The results of Sunoco LP’s operations have not been presented as discontinued operations and Sunoco LP’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements. Bakken Pipeline In March 2015, ETE transferred 46.2 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, the Partnership also issued to ETE 100 Class I Units that provided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017. In October 2015, Sunoco Logistics completed the acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access and ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction. Regency Merger On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency, with Regency surviving as a wholly-owned subsidiary of the Partnership (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.6186 Partnership common units. ETP issued 258.3 million Partnership common units to Regency unitholders, including 23.3 million units issued to Partnership subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding Legacy ETP Preferred Units on a one-for-one basis. In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years. The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger. ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.

Advances to and Investments in

Advances to and Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2017
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Investments in and Advances to Affiliates, Schedule of Investments [Text Block]	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: Citrus ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, an approximately 5,360 -mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment. FEP We have a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. Our investment in FEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures . The Partnership recorded an impairment of its investment in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor. MEP We own a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures . Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016. HPC We own a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. Our investment in HPC is reflected in the intrastate transportation and storage segment. The Partnership evaluated its investment in HPC for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures . During the year ended December 31, 2017, the Partnership recorded a $172 million impairment of its equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven by the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes. Sunoco LP Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from the Partnership. As a result, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. As of December 31, 2017 , the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units, and is reflected in the all other segment. In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million . ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility. The carrying values of the Partnership’s advances to and investments in unconsolidated affiliates as of December 31, 2017 and 2016 were as follows: December 31, 2017 2016 Citrus $ 1,754 $ 1,729 FEP 121 101 MEP 242 318 HPC 28 382 Sunoco LP 1,095 1,225 Others 576 525 Total $ 3,816 $ 4,280 The following table presents equity in earnings (losses) of unconsolidated affiliates: Years Ended December 31, 2017 2016 2015 Citrus $ 144 $ 102 $ 97 FEP 53 51 55 MEP 38 40 45 HPC (1) (168 ) 31 32 Sunoco, LLC — — (10 ) Sunoco LP (2) 12 (211 ) 202 Other 77 46 48 Total equity in earnings of unconsolidated affiliates 156 59 469 (1) For the year ended December 31, 2017 , equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million . (2) For the years ended December 31, 2017 and 2016 , equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $176 million and $277 million , respectively. Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP, HPC and Sunoco LP (on a 100% basis) for all periods presented: December 31, 2017 2016 Current assets $ 4,750 $ 1,532 Property, plant and equipment, net 9,893 10,310 Other assets 2,286 5,980 Total assets $ 16,929 $ 17,822 Current liabilities $ 2,075 $ 1,918 Non-current liabilities 9,375 10,343 Equity 5,479 5,561 Total liabilities and equity $ 16,929 $ 17,822 Years Ended December 31, 2017 2016 2015 Revenue $ 13,081 $ 11,150 $ 13,815 Operating income 636 859 1,052 Net income (loss) 294 (22 ) 664 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

Net Income Per Limited Partner

Net Income Per Limited Partner Unit (Notes)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
NET INCOME PER LIMITED PARTNER UNIT	NET INCOME (LOSS) PER LIMITED PARTNER UNIT: The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit. The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger. Years Ended December 31, 2017 2016 2015 Net income $ 2,501 $ 583 $ 1,489 Less: Income attributable to noncontrolling interest 420 295 134 Less: Loss attributable to predecessor — — (34 ) Net income, net of noncontrolling interest 2,081 288 1,389 General Partner’s interest in net income 990 948 1,064 Preferred Unitholders’ interest in net income 12 — — Class H Unitholder’s interest in net income 93 351 258 Class I Unitholder’s interest in net income — 8 94 Common Unitholders’ interest in net income (loss) 986 (1,019 ) (27 ) Additional earnings allocated from (to) General Partner 9 (10 ) (5 ) Distributions on employee unit awards, net of allocation to General Partner (27 ) (19 ) (16 ) Net income (loss) available to Common Unitholders $ 968 $ (1,048 ) $ (48 ) Weighted average Common Units – basic 1,032.7 758.2 649.2 Basic net income (loss) per Common Unit $ 0.94 $ (1.38 ) $ (0.07 ) Income (loss) available to Common Unitholders $ 968 $ (1,048 ) $ (48 ) Loss attributable to Legacy ETP Preferred Units — — (6 ) Diluted income (loss) available to Common Unitholders $ 968 $ (1,048 ) $ (54 ) Weighted average Common Units – basic 1,032.7 758.2 649.2 Dilutive effect of unvested Unit Awards 5.1 — — Dilutive effect of Legacy ETP Preferred Units — — 1.0 Weighted average Common Units – diluted 1,037.8 758.2 650.2 Diluted income (loss) per Common Unit $ 0.93 $ (1.38 ) $ (0.08 )

Debt Obligations (Notes)

Debt Obligations (Notes)	12 Months Ended
	Dec. 31, 2017
Debt Obligations [Abstract]
DEBT OBLIGATIONS	DEBT OBLIGATIONS: Our debt obligations consist of the following: December 31, 2017 2016 ETP Debt 6.125% Senior Notes due February 15, 2017 $ — $ 400 2.50% Senior Notes due June 15, 2018 (1) 650 650 6.70% Senior Notes due July 1, 2018 (1) 600 600 9.70% Senior Notes due March 15, 2019 400 400 9.00% Senior Notes due April 15, 2019 450 450 5.50% Senior Notes due February 15, 2020 250 250 5.75% Senior Notes due September 1, 2020 400 400 4.15% Senior Notes due October 1, 2020 1,050 1,050 4.40% Senior Notes due April 1, 2021 600 600 6.50% Senior Notes due July 15, 2021 — 500 4.65% Senior Notes due June 1, 2021 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 4.65% Senior Notes due February 15, 2022 300 300 5.875% Senior Notes due March 1, 2022 900 900 5.00% Senior Notes due October 1, 2022 700 700 3.45% Senior Notes due January 15, 2023 350 350 3.60% Senior Notes due February 1, 2023 800 800 5.50% Senior Notes due April 15, 2023 — 700 4.50% Senior Notes due November 1, 2023 600 600 4.90% Senior Notes due February 1, 2024 350 350 7.60% Senior Notes due February 1, 2024 277 277 4.25% Senior Notes due April 1, 2024 500 500 9.00% Debentures due November 1, 2024 65 65 4.05% Senior Notes due March 15, 2025 1,000 1,000 5.95% Senior Notes due December 1, 2025 400 400 4.75% Senior Notes due January 15, 2026 1,000 1,000 3.90% Senior Notes due July 15, 2026 550 550 4.20% Senior Notes due April 15, 2027 600 — 4.00% Senior Notes due October 1, 2027 750 — 8.25% Senior Notes due November 15, 2029 267 267 4.90% Senior Notes due March 15, 2035 500 500 6.625% Senior Notes due October 15, 2036 400 400 7.50% Senior Notes due July 1, 2038 550 550 6.85% Senior Notes due February 15, 2040 250 250 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.30% Senior Notes due April 1, 2044 700 700 5.15% Senior Notes due March 15, 2045 1,000 1,000 5.35% Senior Notes due May 15, 2045 800 800 6.125% Senior Notes due December 15, 2045 1,000 1,000 5.30% Senior Notes due April 15, 2047 900 — 5.40% Senior Notes due October 1, 2047 1,500 — Floating Rate Junior Subordinated Notes due November 1, 2066 546 546 ETP $4.0 billion Revolving Credit Facility due December 2022 2,292 — ETP $1.0 billion 364-Day Credit Facility due November 2018 (2) 50 — ETLP $3.75 billion Revolving Credit Facility due November 2019 — 2,777 Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 — 1,292 Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017 — 630 Unamortized premiums, discounts and fair value adjustments, net 33 66 Deferred debt issuance costs (170 ) (166 ) 29,210 29,454 Transwestern Debt 5.64% Senior Notes due May 24, 2017 — 82 5.36% Senior Notes due December 9, 2020 175 175 5.89% Senior Notes due May 24, 2022 150 150 5.66% Senior Notes due December 9, 2024 175 175 6.16% Senior Notes due May 24, 2037 75 75 Deferred debt issuance costs (1 ) (1 ) 574 656 Panhandle Debt 6.20% Senior Notes due November 1, 2017 — 300 7.00% Senior Notes due June 15, 2018 400 400 8.125% Senior Notes due June 1, 2019 150 150 7.60% Senior Notes due February 1, 2024 82 82 7.00% Senior Notes due July 15, 2029 66 66 8.25% Senior Notes due November 15, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 28 50 813 1,135 Sunoco, Inc. Debt 5.75% Senior Notes due January 15, 2017 — 400 Bakken Project Debt Bakken Project $2.50 billion Credit Facility due August 2019 2,500 1,100 Deferred debt issuance costs (8 ) (13 ) 2,492 1,087 PennTex Debt PennTex $275 million Revolving Credit Facility due December 2019 — 168 Other 5 30 Total debt 33,094 32,930 Less: Current maturities of long-term debt 407 1,189 Long-term debt, less current maturities $ 32,687 $ 31,741 (1) As of December 31, 2017 management had the intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current. (2) Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis. The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $118 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: 2018 $ 1,700 2019 3,500 2020 1,875 2021 1,400 2022 5,346 Thereafter 19,391 Total $ 33,212 Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap. ETP Senior Notes The ETP senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually. The ETP senior notes are unsecured obligations of the Partnership and as a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries. Transwestern Senior Notes The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually. Panhandle Junior Subordinated Notes The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175% . The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 4.39% at December 31, 2017 . Credit Facilities and Commercial Paper ETP Credit Facilities On December 1, 2017 the Partnership entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”). The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitments may be increased up to $6.0 billion under certain conditions. We use the ETP Credit Facilities to provide temporary financing for our growth projects, as well as for general partnership purposes. As of December 31, 2017 , the ETP Five-Year Facility had $2.29 billion outstanding, of which $2.01 billion was commercial paper. The amount available for future borrowings was $1.56 billion after taking into account letters of credit of $150 million . The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 2.48% . As of December 31, 2017 , the ETP 364-Day Facility had $50 million outstanding, and the amount available for future borrowings was $950 million . The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 5.00% . ETLP Credit Facility The ETLP Credit Facility allowed for borrowings of up to $3.75 billion and was used to provide temporary financing for our growth projects, as well as for general partnership purposes. This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017. Sunoco Logistics Credit Facilities ETP maintained a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017. In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion . In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017. Bakken Credit Facility In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”). As of December 31, 2017 , the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00% . PennTex Revolving Credit Facility PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated. Covenants Related to Our Credit Agreements Covenants Related to ETP The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions. The ETP Credit Facilities contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things: • incur indebtedness; • grant liens; • enter into mergers; • dispose of assets; • make certain investments; • make Distributions (as defined in the ETP Credit Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit Facilities); • engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries; • engage in transactions with affiliates; and • enter into restrictive agreements. The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000% . The applicable rate for commitment fees under the ETP Five-Year Facility ranges from 0.125% to 0.300% . The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.250% to 0.750% . The applicable rate for commitment fees under the ETP 364-Day Facility ranges from 0.125% to 0.225% . The ETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1 , which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 3.96 to 1 at December 31, 2017 , as calculated in accordance with the credit agreements. The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio. Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions. Covenants Related to Panhandle Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants. Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries. In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt. Covenants Related to Bakken Credit Facility The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to: • prohibition of certain incremental secured indebtedness; • prohibition of certain liens / negative pledge; • limitations on uses of loan proceeds; • limitations on asset sales and purchases; • limitations on permitted business activities; • limitations on mergers and acquisitions; • limitations on investments; • limitations on transactions with affiliates; and • maintenance of commercially reasonable insurance coverage. A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder. Compliance with our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2017 .

Series A Preferred Units (Notes

Series A Preferred Units (Notes)	12 Months Ended
	Dec. 31, 2017
Temporary Equity Disclosure [Abstract]
Preferred Units [Text Block]	LEGACY ETP PREFERRED UNITS: The Legacy ETP Preferred Units were mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and were reflected as long-term liabilities in our consolidated balance sheets. The Legacy ETP Preferred Units were entitled to a preferential quarterly cash distribution of $0.445 per Preferred Unit if outstanding on the record dates of the Partnership’s common unit distributions. In January 2017, ETP repurchased all of its 1.9 million outstanding Legacy ETP Preferred Units for cash in the aggregate amount of $53 million .

Equity (Notes)

Equity (Notes)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
EQUITY	EQUITY: Limited Partner interests are represented by Common, Class E Units, Class G Units, Class I Units, Class J Units and Class K Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s outstanding securities also include preferred units, as described below. No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance. IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiary of ETE, owns all of the IDRs. Common Units The change in Common Units was as follows: Years Ended December 31, 2017 (1) 2016 (1) 2015 (1) Number of Common Units, beginning of period 794.8 758.5 533.4 Common Units redeemed in connection with certain transactions — (26.7 ) (77.8 ) Common Units issued in connection with public offerings 54.0 — — Common Units issued in connection with certain acquisitions — 13.3 258.2 Common Units issued in connection with the Distribution Reinvestment Plan 12.0 9.9 11.7 Common Units issued in connection with Equity Distribution Agreements 22.6 39.0 31.7 Common Units issued to ETE in a private placement transaction 23.7 — — Common Unit increase from Sunoco Logistics Merger (2) 255.4 — — Issuance of Common Units under equity incentive plans 1.6 0.8 1.3 Number of Common Units, end of period 1,164.1 794.8 758.5 (1) The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger. (2) Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger. Our Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.” Equity Distribution Program From time to time, we have sold Common Units through equity distribution agreements. Such sales of Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreements. In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion . During the year ended December 31, 2017 , we issued 22.6 million units for $503 million , net of commissions of $5 million . As of December 31, 2017 , $752 million of our Common Units remained available to be issued under our currently effective equity distribution agreement. Equity Incentive Plan Activity We issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations. Distribution Reinvestment Program Our Distribution Reinvestment Plan (the “DRIP”) provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units. In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, the Partnership initiated a new distribution reinvestment plan. During the years ended December 31, 2017 , 2016 and 2015 , aggregate distributions of $228 million , $216 million , and $360 million , respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units. As of December 31, 2017 , a total of 20.8 million Common Units remain available to be issued under the existing registration statement. August 2017 Units Offering In August 2017, the Partnership issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by the Partnership to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes. January 2017 Private Placement In January 2017, the Partnership sold 23.7 million ETP Common Units to ETE in a private placement transaction for gross proceeds of approximately $568 million . Class E Units There are currently 8.9 million Class E Units outstanding, all of which are currently owned by HHI. The Class E Units generally do not have any voting rights. The Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year. As the Class E Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire the Class E Units at a future date. Class G Units There are currently 90.7 million Class G Units outstanding, all of which are held by a wholly-owned subsidiary of the Partnership. The Class G Units generally do not have any voting rights. The Class G Units are entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class G Unit per year. Allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are reflected as treasury units in the consolidated financial statements. Class H Units Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which were generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017. Class I Units In connection with the Bakken Pipeline Transaction discussed in Note 3, in April 2015, ETP issued 100 Class I Units. The Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the Class I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the Class I Units and (ii) after making cash distributions to Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in our Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to the April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding. Bakken Equity Sale In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction. Class K Units On December 29, 2016, the Partnership issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in the Partnership, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco. If the Partnership is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of December 31, 2017 , a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETP. Sales of Common Units by legacy Sunoco Logistics Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions. In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol. In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes. In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion . In connection with the Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated. ETP Preferred Units In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Preferred Units at a price of $1,000 per unit. Distributions on the Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000 . On and after February 15, 2023, distributions on the Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The Series A Preferred Units are redeemable at ETP’s option on or after February 15, 2023 at a redemption price of $1,000 per Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000 . On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of $1,000 per Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. PennTex Tender Offer and Limited Call Right Exercise In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ. Quarterly Distributions of Available Cash Under the Partnership’s limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner. If cash distributions exceed $0.0833 per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to 48 percent , of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The following table shows the target distribution levels and distribution “splits” between the general and limited partners and the holders of the Partnership’s incentive distribution rights (”IDRs”): Marginal Percentage Interest in Distributions Total Quarterly Distribution Target Amount IDRs Partners (1) Minimum Quarterly Distribution $0.0750 —% 100% First Target Distribution up to $0.0833 —% 100% Second Target Distribution above $0.0833 up to $0.0958 13% 87% Third Target Distribution above $0.0958 up to $0.2638 35% 65% Thereafter above $0.2638 48% 52% (1) Includes general partner and limited partner interests, based on the proportionate ownership of each. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows: Quarter Ended ETP Sunoco Logistics December 31, 2014 $ 0.6633 $ 0.4000 March 31, 2015 0.6767 0.4190 June 30, 2015 0.6900 0.4380 September 30, 2015 0.7033 0.4580 December 31, 2015 0.7033 0.4790 March 31, 2016 0.7033 0.4890 June 30, 2016 0.7033 0.5000 September 30, 2016 0.7033 0.5100 December 31, 2016 0.7033 0.5200 Distributions on common units declared and paid by Post-Merger ETP were as follows: Quarter Ended Record Date Payment Date Rate March 31, 2017 May 10, 2017 May 16, 2017 $ 0.5350 June 30, 2017 August 7, 2017 August 15, 2017 0.5500 September 30, 2017 November 7, 2017 November 14, 2017 0.5650 December 31, 2017 February 8, 2018 February 14, 2018 0.5650 In connection with previous transactions, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods: Total Year 2018 $ 153 2019 128 Each year beyond 2019 33 Distributions declared and paid by ETP to the preferred unitholders were as follows: Distribution per Preferred Unit Quarter Ended Record Date Payment Date Series A Series B December 31, 2017 February 1, 2018 February 15, 2018 $ 15.451 $ 16.378 Accumulated Other Comprehensive Income The following table presents the components of AOCI, net of tax: December 31, 2017 2016 Available-for-sale securities $ 8 $ 2 Foreign currency translation adjustment (5 ) (5 ) Actuarial gain related to pensions and other postretirement benefits (5 ) 7 Investments in unconsolidated affiliates, net 5 4 Total AOCI, net of tax $ 3 $ 8 The table below sets forth the tax amounts included in the respective components of other comprehensive income: December 31, 2017 2016 Available-for-sale securities $ (2 ) $ (2 ) Foreign currency translation adjustment 3 3 Actuarial loss relating to pension and other postretirement benefits 3 — Total $ 4 $ 1

Unit-Based Compensation Plans (

Unit-Based Compensation Plans (Notes)	12 Months Ended
	Dec. 31, 2017
Deferred Compensation Arrangements [Abstract]
UNIT-BASED COMPENSATION PLANS	UNIT-BASED COMPENSATION PLANS: ETP Unit-Based Compensation Plan We have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2017 , an aggregate total of 8.4 million ETP Common Units remain available to be awarded under our equity incentive plans. Restricted Units We have granted restricted unit awards to employees that vest over a specified time period, typically a five -year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five -year service vesting requirement. The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2016 9.4 $ 27.68 Legacy Sunoco Logistics unvested awards as of December 31, 2016 3.2 28.57 Awards granted 4.9 17.69 Awards vested (2.3 ) 34.22 Awards forfeited (1.1 ) 25.03 Unvested awards as of December 31, 2017 14.1 23.18 During the years ended December 31, 2017, 2016, and 2015 , the weighted average grant-date fair value per unit award granted was $17.69 , $23.82 and $23.47 , respectively. The total fair value of awards vested was $40 million , $40 million and $57 million , respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2017 , a total of 14.1 million unit awards remain unvested, for which ETP expects to recognize a total of $189 million in compensation expense over a weighted average period of 2.7 years . Cash Restricted Units. The Partnership previously granted cash restricted units, which entitled the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting. The Partnership does not currently have any cash restricted units outstanding.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES: As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) are summarized as follows: Years Ended December 31, 2017 2016 2015 Current expense (benefit): Federal $ 53 $ 18 $ (274 ) State (18 ) (35 ) (51 ) Total 35 (17 ) (325 ) Deferred expense (benefit): Federal (1,723 ) (173 ) 231 State 192 4 (29 ) Total (1,531 ) (169 ) 202 Total income tax benefit $ (1,496 ) $ (186 ) $ (123 ) Historically, our effective rate has differed from the statutory rate primarily due to Partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2017 , 2016 and 2015 is as follows: Years Ended December 31, 2017 2016* 2015* Income tax expense at United States statutory rate of 35 percent $ 352 $ 139 $ 479 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax (457 ) (504 ) (504 ) Federal rate change (1,559 ) — — Goodwill impairments 172 223 — State income taxes (net of federal income tax effects) 131 (17 ) (37 ) Dividend received deduction (14 ) (15 ) (24 ) Audit settlement — — (7 ) Change in tax status of subsidiary (124 ) — — Other 3 (12 ) (30 ) Income tax benefit $ (1,496 ) $ (186 ) $ (123 ) * As adjusted. See Note 2. Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: December 31, 2017 2016 Deferred income tax assets: Net operating losses and alternative minimum tax credit $ 604 $ 380 Pension and other postretirement benefits 21 30 Long-term debt 14 32 Other 93 84 Total deferred income tax assets 732 526 Valuation allowance (189 ) (118 ) Net deferred income tax assets $ 543 $ 408 Deferred income tax liabilities: Property, plant and equipment $ (664 ) $ (1,054 ) Investment in unconsolidated affiliates (2,664 ) (3,728 ) Other (98 ) (20 ) Total deferred income tax liabilities (3,426 ) (4,802 ) Net deferred income taxes $ (2,883 ) $ (4,394 ) The table below provides a rollforward of the net deferred income tax liability as follows: December 31, 2017 2016 Net deferred income tax liability, beginning of year $ (4,394 ) $ (4,082 ) Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) — (460 ) Tax provision 1,531 169 Other (20 ) (21 ) Net deferred income tax liability, end of year $ (2,883 ) $ (4,394 ) ETP Holdco and other corporate subsidiaries have federal net operating loss carryforward of $1.57 billion , all of which will expire in 2031 through 2037 . Our corporate subsidiaries have $62 million of federal alternative minimum tax credits at December 31, 2017 , of which $29 million is expected to be reclassified to current income tax receivable in 2018 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have state net operating loss carryforward benefits of $210 million , net of federal tax, which expire between 2018 and 2036 . A valuation allowance of $186 million is applicable to the state net operating loss carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania and the remaining $3 million valuation allowance is applicable to the federal net operating loss carryforward benefit. The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2017 2016 2015 Balance at beginning of year $ 615 $ 610 $ 440 Additions attributable to tax positions taken in the current year — 8 — Additions attributable to tax positions taken in prior years 28 18 178 Reduction attributable to tax positions taken in prior years (25 ) (20 ) — Lapse of statute (9 ) (1 ) (8 ) Balance at end of year $ 609 $ 615 $ 610 As of December 31, 2017 , we have $605 million ( $576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017 , we recognized interest and penalties of less than $3 million . At December 31, 2017 , we have interest and penalties accrued of $9 million , net of tax. Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in this litigation, it will receive tax refunds of approximately $530 million . However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the financial statements as of December 31, 2017 . In December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact. Nextel has until April 4, 2018 to file a petition for writ of certiorari with the U.S. Supreme Court. Sunoco, Inc. has recognized approximately $67 million ( $53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter. However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ( $21 million after federal income tax benefits) against the receivable. In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for the 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007. Sunoco, Inc. has been examined by the IRS for tax years through 2013. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments. ETP and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations. On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017 . As a result, the Partnership recognized a deferred tax benefit of $1.56 billion in December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

Regulatory Matters, Commitments

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Notes)	12 Months Ended
	Dec. 31, 2017
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Commitments Contingencies and Guarantees [Text Block]	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: Contingent Residual Support Agreement – AmeriGas In connection with the closing of the contribution of its propane operations in January 2012, ETP previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes. Guarantee of Sunoco LP Notes In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”). On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts: • $1.00 billion aggregate principal amount of 4.875% , senior notes due 2023; • $800 million aggregate principal amount of 5.50% senior notes due 2026; and • $400 million aggregate principal amount of 5.875% senior notes due 2028. Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes. FERC Audit In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing. Commitments In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETP believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations. ETP’s joint venture agreements require that it funds its proportionate share of capital contributions to its unconsolidated affiliates. Such contributions will depend upon ETP’s unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034 . The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: Years Ended December 31, 2017 2016 2015 Rental expense (1) $ 90 $ 81 $ 176 Less: Sublease rental income — (1 ) (16 ) Rental expense, net $ 90 $ 80 $ 160 (1) Includes contingent rentals totaling $26 million for the year ended December 31, 2015. Future minimum lease commitments for such leases are: Years Ending December 31: 2018 $ 39 2019 36 2020 37 2021 30 2022 23 Thereafter 92 Future minimum lease commitments 257 Less: Sublease rental income (8 ) Net future minimum lease commitments $ 249 Litigation and Contingencies We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Dakota Access Pipeline On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access intervened in the case. The SRST soon added a request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot. After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval. The SRST appealed the denial of the preliminary injunction to the United States Court of Appeals for the D.C. Circuit and filed an emergency motion in the United States District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statutes governing the use of government property. In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and TRO to block operation of the pipeline. These motions raised, for the first time, claims based on the religious rights of the Tribe. The District Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal. The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes. On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018. On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The auditor’s report is required to be filed with the Court by April 1, 2018. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access is required to file the revised plan with the Court by April 1, 2018. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first report was filed with the court on December 29, 2017. In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. Briefing on YST’s motion is ongoing. While we believe that the pending lawsuits are unlikely to halt or suspend the operation of the pipeline, we cannot assure this outcome. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project. Mont Belvieu Incident On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses. MTBE Litigation Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees. As of December 31, 2017 , Sunoco, Inc. is a defendant in seven cases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland. Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. Dismissal of the case against Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018. It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position. Regency Merger Litigation Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al. , C.A. No. 11130-CB, in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (the “Regency Litigation Defendants”). The Regency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted the Regency Litigation Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC. The Regency Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger. Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million , consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP filed a petition for review with the Texas Supreme Court. Enterprise’s response is due February 26, 2018. Sunoco Logistics Merger Litigation Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig ., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs sought rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the Motion to Dismiss, the ETP Unitholder Plaintiffs chose to voluntarily dismiss their claims without prejudice in November 2017. The ETP-SXL Defendants cannot predict whether the ETP Unitholder Plaintiffs will refile their claims against the ETP-SXL Defendants or what the outcome of any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger. Litigation filed by BP Products On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25 - 000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million , a figure that BP reduced in subsequent filings to approximately $41 million . SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016. On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued its initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint. On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC. Other Litigation and Contingencies We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2017 and 2016 , accruals of approximately $33 million and $77 million , respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period. The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. No amounts have been recorded in our December 31, 2017 or 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Environmental Matters Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position. Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs. In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality. On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped. The Administrative Order detailed alleged violations of the permits issued by PADEP in February of 2017, during the construction of the project. Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues. Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP. PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order. That request was granted on February 8, 2018. Environmental Remediation Our subsidiaries are responsible for environmental remediation at certain sites, including the following: • Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties. • Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons. • Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites. • Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2017 , Sunoco, Inc. had been named as a PRP at approximately 43 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant. To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets. The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financia

Derivative assets and liabiltie

Derivative assets and liabilties (Notes)	12 Months Ended
	Dec. 31, 2017
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
DERIVATIVE ASSETS AND LIABILITIES	DERIVATIVE ASSETS AND LIABILITIES: Commodity Price Risk We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy. The following table details our outstanding commodity-related derivatives: December 31, 2017 December 31, 2016 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (BBtu): Fixed Swaps/Futures 1,078 2018 (683 ) 2017 Basis Swaps IFERC/NYMEX (1) 48,510 2018-2020 2,243 2017 Options – Calls 13,000 2018 — — Power (Megawatt): Forwards 435,960 2018-2019 391,880 2017-2018 Futures (25,760 ) 2018 109,564 2017-2018 Options – Puts (153,600 ) 2018 (50,400 ) 2017 Options – Calls 137,600 2018 186,400 2017 Crude (MBbls) – Futures — — (617 ) 2017 (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX 4,650 2018-2020 10,750 2017-2018 Swing Swaps IFERC 87,253 2018-2019 (5,663 ) 2017 Fixed Swaps/Futures (4,700 ) 2018-2019 (52,653 ) 2017-2019 Forward Physical Contracts (145,105 ) 2018-2020 (22,492 ) 2017 Natural Gas Liquid (MBbls) – Forwards/Swaps 6,679 2018-2019 (5,787 ) 2017 Refined Products (MBbls) – Futures (3,783 ) 2018-2019 (2,240 ) 2017 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (39,770 ) 2018 (36,370 ) 2017 Fixed Swaps/Futures (39,770 ) 2018 (36,370 ) 2017 Hedged Item – Inventory 39,770 2018 36,370 2017 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. Interest Rate Risk We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances. The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes: Term Type (1) Notional Amount Outstanding December 31, 2017 December 31, 2016 July 2017 (2) Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $ — $ 500 July 2018 (2) Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300 200 July 2019 (2) Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300 200 July 2020 (2) Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400 — December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 1,200 March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300 300 (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date. Credit Risk Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance. The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income. Derivative Summary The following table provides a summary of our derivative assets and liabilities: Fair Value of Derivative Instruments Asset Derivatives Liability Derivatives December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 14 $ — $ (2 ) $ (4 ) 14 — (2 ) (4 ) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 262 338 (281 ) (416 ) Commodity derivatives 44 24 (55 ) (52 ) Interest rate derivatives — — (219 ) (193 ) Embedded derivatives in Legacy ETP Preferred Units — — — (1 ) 306 362 (555 ) (662 ) Total derivatives $ 320 $ 362 $ (557 ) $ (666 ) The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Derivatives without offsetting agreements Derivative liabilities $ — $ — $ (219 ) $ (194 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 44 24 (55 ) (52 ) Broker cleared derivative contracts Other current assets (liabilities) 276 338 (283 ) (420 ) 320 362 (557 ) (666 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (20 ) (4 ) 20 4 Counterparty netting Other current assets (liabilities) (263 ) (338 ) 263 338 Total net derivatives $ 37 $ 20 $ (274 ) $ (324 ) We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date. The following tables summarize the amounts recognized with respect to our derivative financial instruments: Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Years Ended December 31, 2017 2016 2015 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 26 $ 14 $ 21 Total $ 26 $ 14 $ 21 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2017 2016 2015 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ 31 $ (35 ) $ (11 ) Commodity derivatives – Non-trading Cost of products sold 3 (173 ) 23 Interest rate derivatives Losses on interest rate derivatives (37 ) (12 ) (18 ) Embedded derivatives Other, net 1 4 12 Total $ (2 ) $ (216 ) $ 6

Retirement Benefits (Notes)

Retirement Benefits (Notes)	12 Months Ended
	Dec. 31, 2017
RETIREMENT BENEFITS
Pension and Other Postretirement Benefits Disclosure	RETIREMENT BENEFITS: Savings and Profit Sharing Plans We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $38 million , $44 million and $39 million to these 401(k) savings plans for the years ended December 31, 2017, 2016, and 2015 , respectively. Pension and Other Postretirement Benefit Plans Panhandle Postretirement benefits expense for the years ended December 31, 2017, 2016 and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees. Sunoco, Inc. Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015. Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations. Obligations and Funded Status Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: December 31, 2017 December 31, 2016 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Change in benefit obligation: Benefit obligation at beginning of period $ 18 $ 51 $ 165 $ 20 $ 57 $ 180 Interest cost 1 1 4 1 2 4 Amendments — — 7 — — — Benefits paid, net (2 ) (6 ) (20 ) (1 ) (7 ) (21 ) Actuarial (gain) loss and other 2 1 (1 ) (2 ) (1 ) 2 Settlements (18 ) — — — — — Benefit obligation at end of period 1 47 155 18 51 165 Change in plan assets: Fair value of plan assets at beginning of period 12 — 248 15 — 253 Return on plan assets and other 3 — 11 (2 ) — 6 Employer contributions 6 — 10 — — 10 Benefits paid, net (2 ) — (20 ) (1 ) — (21 ) Settlements (18 ) — — — — — Fair value of plan assets at end of period 1 — 249 12 — 248 Amount underfunded (overfunded) at end of period $ — $ 47 $ (94 ) $ 6 $ 51 $ (83 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 120 $ — $ — $ 108 Current liabilities — (8 ) (2 ) — (7 ) (2 ) Non-current liabilities — (39 ) (24 ) (6 ) (44 ) (23 ) $ — $ (47 ) $ 94 $ (6 ) $ (51 ) $ 83 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain $ — $ 5 $ (17 ) $ — $ — $ (12 ) Prior service cost — — 20 — — 14 $ — $ 5 $ 3 $ — $ — $ 2 The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2017 December 31, 2016 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 1 $ 47 N/A $ 18 $ 51 N/A Accumulated benefit obligation 1 47 $ 155 18 51 $ 165 Fair value of plan assets 1 — 249 12 — 248 Components of Net Periodic Benefit Cost December 31, 2017 December 31, 2016 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Interest cost $ 2 $ 4 $ 3 $ 4 Expected return on plan assets — (9 ) (1 ) (8 ) Prior service cost amortization — 2 — 1 Net periodic benefit cost $ 2 $ (3 ) $ 2 $ (3 ) Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2017 December 31, 2016 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.27 % 2.34 % 3.65 % 2.34 % Rate of compensation increase N/A N/A N/A N/A The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2017 December 31, 2016 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.52 % 3.10 % 3.60 % 3.06 % Expected return on assets: Tax exempt accounts 3.50 % 7.00 % 3.50 % 7.00 % Taxable accounts N/A 4.50 % N/A 4.50 % Rate of compensation increase N/A N/A N/A N/A The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness. The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: December 31, 2017 2016 Health care cost trend rate 7.20 % 6.73 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.99 % 4.96 % Year that the rate reaches the ultimate trend rate 2023 2021 Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits. Plan Assets For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35% , fixed income of 65% to 75% . The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets. The fair value of the pension plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2017 Fair Value Total Level 1 Level 2 Level 3 Asset category: Mutual funds (1) $ 1 $ 1 $ — $ — Total $ 1 $ 1 $ — $ — (1) Comprised of approximately 100% equities as of December 31, 2017 . Fair Value Measurements at December 31, 2016 Fair Value Total Level 1 Level 2 Level 3 Asset category: Mutual funds (1) $ 12 $ 12 $ — $ — Total $ 12 $ 12 $ — $ — (1) Comprised of approximately 100% equities as of December 31, 2016 . The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2017 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 33 $ 33 $ — $ — Mutual funds (1) 146 146 — — Fixed income securities 70 — 70 — Total $ 249 $ 179 $ 70 $ — (1) Primarily comprised of approximately 48% equities, 51% fixed income securities and 1% cash as of December 31, 2017 . Fair Value Measurements at December 31, 2016 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 23 $ 23 $ — $ — Mutual funds (1) 134 134 — — Fixed income securities 91 — 91 — Total $ 248 $ 157 $ 91 $ — (1) Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016 . The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. Contributions We expect to contribute $8 million to pension plans and $10 million to other postretirement plans in 2018 . The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes. Benefit Payments Panhandle and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: Years Pension Benefits - Unfunded Plans (1) Other Postretirement Benefits (Gross, Before Medicare Part D) 2018 $ 8 $ 24 2019 6 23 2020 6 21 2021 5 19 2022 4 17 2023 – 2027 15 37 (1) Expected benefit payments of funded pension plans are less than $1 million for the next ten years. The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS: In June 2017, the Partnership acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 8 . ETE previously paid us to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by us on behalf of ETE and its subsidiaries. These agreements expired in 2016. The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. The following table summarizes the affiliate revenues on our consolidated statements of operations: Years Ended December 31, 2017 2016 2015 Affiliated revenues $ 697 $ 377 $ 417 The following table summarizes the related company balances on our consolidated balance sheets: December 31, 2017 2016 Accounts receivable from related companies: ETE $ — $ 22 Sunoco LP 219 96 FGT 11 15 Other 88 76 Total accounts receivable from related companies $ 318 $ 209 Accounts payable to related companies: Sunoco LP 195 20 Other 14 23 Total accounts payable to related companies $ 209 $ 43 December 31, 2017 2016 Long-term notes receivable (payable) – related companies: Sunoco LP $ 85 $ 87 Phillips 66 — (250 ) Net long-term notes receivable (payable) – related companies $ 85 $ (163 )

Reportable Segments (Notes)

Reportable Segments (Notes)	12 Months Ended
	Dec. 31, 2017
Reportable Segments [Abstract]
REPORTABLE SEGMENTS	REPORTABLE SEGMENTS: Our financial statements currently reflect the following reportable segments, which conduct their business in the United States, as follows: • intrastate transportation and storage; • interstate transportation and storage; • midstream; • NGL and refined products transportation and services; • crude oil transportation and services; and • all other. The Partnership previously presented its retail marketing business as a separate reportable segment. Due to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP. As of December 31, 2017 , the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, our investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units . This equity method investment in Sunoco LP has now been aggregated into the all other segment. Consequently, the retail marketing business that was previously consolidated has also been aggregated in the all other segment for all periods presented. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation, terminalling and other fees. Revenues from our crude oil transportation and services segment are primarily reflected in crude sales. Revenues from our all other segment are primarily reflected in refined product sales. We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership. The following tables present financial information by segment: Years Ended December 31, 2017 2016 2015 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,891 $ 2,155 $ 1,912 Intersegment revenues 192 458 338 3,083 2,613 2,250 Interstate transportation and storage: Revenues from external customers 915 946 1,008 Intersegment revenues 19 23 17 934 969 1,025 Midstream: Revenues from external customers 2,510 2,342 2,607 Intersegment revenues 4,433 2,837 2,449 6,943 5,179 5,056 NGL and refined products transportation and services: Revenues from external customers 8,326 5,973 4,569 Intersegment revenues 322 436 428 8,648 6,409 4,997 Crude oil transportation and services: Revenues from external customers 11,672 7,539 8,980 Intersegment revenues 31 — — 11,703 7,539 8,980 All other: Revenues from external customers 2,740 2,872 15,216 Intersegment revenues 161 400 558 2,901 3,272 15,774 Eliminations (5,158 ) (4,154 ) (3,790 ) Total revenues $ 29,054 $ 21,827 $ 34,292 Years Ended December 31, 2017 2016 2015 Cost of products sold: Intrastate transportation and storage $ 2,327 $ 1,897 $ 1,554 Midstream 4,761 3,381 3,264 NGL and refined products transportation and services 6,508 4,553 3,431 Crude oil transportation and services 9,826 6,416 8,158 All other 2,509 2,942 14,029 Eliminations (5,130 ) (4,109 ) (3,722 ) Total cost of products sold $ 20,801 $ 15,080 $ 26,714 Years Ended December 31, 2017 2016 2015 Depreciation, depletion and amortization: Intrastate transportation and storage $ 147 $ 144 $ 129 Interstate transportation and storage 214 207 210 Midstream 954 840 720 NGL and refined products transportation and services 401 355 290 Crude oil transportation and services 402 251 218 All other 214 189 362 Total depreciation, depletion and amortization $ 2,332 $ 1,986 $ 1,929 Years Ended December 31, 2017 2016 2015 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ (156 ) $ 35 $ 32 Interstate transportation and storage 236 193 197 Midstream 20 19 (19 ) NGL and refined products transportation and services 33 41 29 Crude oil transportation and services 4 (4 ) (9 ) All other 19 (225 ) 239 Total equity in earnings of unconsolidated affiliates $ 156 $ 59 $ 469 Years Ended December 31, 2017 2016 2015 Segment Adjusted EBITDA: Intrastate transportation and storage $ 626 $ 613 $ 543 Interstate transportation and storage 1,098 1,117 1,155 Midstream 1,481 1,133 1,237 NGL and refined products transportation and services 1,641 1,496 1,179 Crude oil transportation and services 1,379 834 521 All other 487 540 882 Total Segment Adjusted EBITDA 6,712 5,733 5,517 Depreciation, depletion and amortization (2,332 ) (1,986 ) (1,929 ) Interest expense, net (1,365 ) (1,317 ) (1,291 ) Gains on acquisitions — 83 — Impairment losses (920 ) (813 ) (339 ) Losses on interest rate derivatives (37 ) (12 ) (18 ) Non-cash unit-based compensation expense (74 ) (80 ) (79 ) Unrealized gains (losses) on commodity risk management activities 56 (131 ) (65 ) Inventory valuation adjustments — — 58 Losses on extinguishments of debt (42 ) — (43 ) Adjusted EBITDA related to unconsolidated affiliates (984 ) (946 ) (937 ) Equity in earnings from unconsolidated affiliates 156 59 469 Impairment of investments in unconsolidated affiliates (313 ) (308 ) — Other, net 148 115 23 Income before income tax benefit $ 1,005 $ 397 $ 1,366 December 31, 2017 2016 2015 Assets: Intrastate transportation and storage $ 5,020 $ 5,176 $ 4,882 Interstate transportation and storage 13,518 10,833 11,345 Midstream 20,004 17,873 17,039 NGL and refined products transportation and services 17,600 14,074 11,568 Crude oil transportation and services 17,736 15,909 10,941 All other 4,087 6,240 9,353 Total assets $ 77,965 $ 70,105 $ 65,128 Years Ended December 31, 2017 2016 2015 Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis): Intrastate transportation and storage $ 175 $ 76 $ 105 Interstate transportation and storage 726 280 866 Midstream 1,308 1,255 2,174 NGL and refined products transportation and services 2,971 2,198 2,853 Crude oil transportation and services 453 1,841 1,358 All other 268 160 811 Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis) $ 5,901 $ 5,810 $ 8,167 December 31, 2017 2016 2015 Advances to and investments in unconsolidated affiliates: Intrastate transportation and storage $ 85 $ 399 $ 406 Interstate transportation and storage 2,118 2,149 2,516 Midstream 126 111 117 NGL and refined products transportation and services 234 235 258 Crude oil transportation and services 22 18 21 All other 1,231 1,368 1,685 Total advances to and investments in unconsolidated affiliates $ 3,816 $ 4,280 $ 5,003

Quarterly Financial Data (Notes

Quarterly Financial Data (Notes)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Data [Abstract]
QUARTERLY FINANCIAL DATA (UNAUDITED)	QUARTERLY FINANCIAL DATA (UNAUDITED): Summarized unaudited quarterly financial data is presented below. The sum of net income per Limited Partner unit by quarter does not equal the net income per limited partner unit for the year due to the computation of income allocation between the General Partner and Limited Partners and variations in the weighted average units outstanding used in computing such amounts. Quarters Ended March 31* June 30* September 30* December 31 Total Year 2017: Revenues $ 6,895 $ 6,576 $ 6,973 $ 8,610 $ 29,054 Operating income 683 736 779 199 2,397 Net income 393 296 715 1,097 2,501 Common Unitholders’ interest in net income (loss) 32 (49 ) 335 668 986 Basic net income (loss) per Common Unit $ 0.03 $ (0.04 ) $ 0.29 $ 0.57 $ 0.94 Diluted net income (loss) per Common Unit $ 0.03 $ (0.04 ) $ 0.29 $ 0.57 $ 0.93 Quarters Ended March 31* June 30* September 30* December 31* Total Year* 2016: Revenues $ 4,481 $ 5,289 $ 5,531 $ 6,526 $ 21,827 Operating income 598 708 594 (139 ) 1,761 Net income 360 465 94 (336 ) 583 Common Unitholders’ interest in net income (loss) (71 ) 58 (252 ) (754 ) (1,019 ) Basic net income (loss) per Common Unit $ (0.11 ) $ 0.06 $ (0.34 ) $ (0.97 ) $ (1.38 ) Diluted net income (loss) per Common Unit $ (0.11 ) $ 0.06 $ (0.34 ) $ (0.97 ) $ (1.38 ) * As adjusted. See Note 2. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality. The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $920 million and $813 million , respectively. Impairment losses in 2017 were primarily related to our Trunkline, SUG Holding Company, LLC, CDM, Sea Robin and refined products reporting units. Impairment losses in 2016 were primarily related to our PEPL reporting unit, Sea Robin reporting unit and midstream midcontinent operations. The three months ended December 31, 2017 and September 30, 2016 reflected the recognition of a non-cash impairment of our investments in subsidiaries of $313 million and $308 million , respectively, in our interstate transportation and storage segment. For certain periods reflected above, distributions paid for the period exceeded net income attributable to partners. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.

Guarantor Financial Information

Guarantor Financial Information (Notes)	12 Months Ended
	Dec. 31, 2017
Guarantor Financial Information [Abstract]
Condensed Financial Information of Parent Company Only Disclosure [Text Block]	CONSOLIDATING GUARANTOR FINANCIAL INFORMATION Prior to the Sunoco Logistics Merger, Sunoco Logistics Partners Operations L.P., a subsidiary of Sunoco Logistics was the issuer of multiple series of senior notes that were guaranteed by Sunoco Logistics. Subsequent to the Sunoco Logistics Merger, these notes continue to be guaranteed by the parent company. These guarantees are full and unconditional. For the purposes of this footnote, Energy Transfer Partners, L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.” The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting. To present the supplemental condensed consolidating financial information on a comparable basis, the prior period financial information has been recast as if the Sunoco Logistics Merger occurred on January 1, 2015. The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows: December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash and cash equivalents $ — $ (3 ) $ 309 $ — $ 306 All other current assets — 159 6,063 — 6,222 Property, plant and equipment — — 58,437 — 58,437 Investments in unconsolidated affiliates 48,378 11,648 3,816 (60,026 ) 3,816 All other assets — — 9,184 — 9,184 Total assets $ 48,378 $ 11,804 $ 77,809 $ (60,026 ) $ 77,965 Current liabilities (1,496 ) (3,660 ) 12,150 — 6,994 Non-current liabilities 21,604 7,607 7,609 — 36,820 Noncontrolling interest — — 5,882 — 5,882 Total partners’ capital 28,270 7,857 52,168 (60,026 ) 28,269 Total liabilities and equity $ 48,378 $ 11,804 $ 77,809 $ (60,026 ) $ 77,965 December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash and cash equivalents $ — $ 41 $ 319 $ — $ 360 All other current assets — 2 5,281 — 5,283 Property, plant and equipment — — 50,917 — 50,917 Investments in unconsolidated affiliates 23,350 10,664 4,280 (34,014 ) 4,280 All other assets — 5 9,260 — 9,265 Total assets $ 23,350 $ 10,712 $ 70,057 $ (34,014 ) $ 70,105 Current liabilities (1,761 ) (3,800 ) 11,764 — 6,203 Non-current liabilities 299 7,313 30,148 (299 ) 37,461 Noncontrolling interest — — 1,232 — 1,232 Total partners’ capital 24,812 7,199 26,913 (33,715 ) 25,209 Total liabilities and equity $ 23,350 $ 10,712 $ 70,057 $ (34,014 ) $ 70,105 Year Ended December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 29,054 $ — $ 29,054 Operating costs, expenses, and other — 1 26,656 — 26,657 Operating income (loss) — (1 ) 2,398 — 2,397 Interest expense, net — (156 ) (1,209 ) — (1,365 ) Equity in earnings of unconsolidated affiliates 2,564 1,242 156 (3,806 ) 156 Impairment of investments in unconsolidated affiliate — — (313 ) — (313 ) Losses on interest rate derivatives — — (37 ) — (37 ) Other, net — — 168 (1 ) 167 Income before income tax benefit 2,564 1,085 1,163 (3,807 ) 1,005 Income tax benefit — — (1,496 ) — (1,496 ) Net income 2,564 1,085 2,659 (3,807 ) 2,501 Less: Net income attributable to noncontrolling interest — — 420 — 420 Net income attributable to partners $ 2,564 $ 1,085 $ 2,239 $ (3,807 ) $ 2,081 Other comprehensive income (loss) $ — $ — $ (5 ) $ — $ (5 ) Comprehensive income 2,564 1,085 2,654 (3,807 ) 2,496 Comprehensive income attributable to noncontrolling interest — — 420 — 420 Comprehensive income attributable to partners $ 2,564 $ 1,085 $ 2,234 $ (3,807 ) $ 2,076 Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 21,827 $ — $ 21,827 Operating costs, expenses, and other — 1 20,065 — 20,066 Operating income (loss) — (1 ) 1,762 — 1,761 Interest expense, net — (157 ) (1,160 ) — (1,317 ) Equity in earnings of unconsolidated affiliates 554 863 59 (1,417 ) 59 Impairment of investment in unconsolidated affiliate — — (308 ) — (308 ) Losses on interest rate derivatives — — (12 ) — (12 ) Other, net — — 214 — 214 Income before income tax benefit 554 705 555 (1,417 ) 397 Income tax benefit — — (186 ) — (186 ) Net income 554 705 741 (1,417 ) 583 Less: Net income attributable to noncontrolling interest — — 41 — 41 Net income attributable to partners $ 554 $ 705 $ 700 $ (1,417 ) $ 542 Other comprehensive income $ — $ — $ 4 $ — $ 4 Comprehensive income 554 705 745 (1,417 ) 587 Comprehensive income attributable to noncontrolling interest — — 41 — 41 Comprehensive income attributable to partners $ 554 $ 705 $ 704 $ (1,417 ) $ 546 Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 34,292 $ — $ 34,292 Operating costs, expenses, and other — 1 32,064 — 32,065 Operating income (loss) — (1 ) 2,228 — 2,227 Interest expense, net — (133 ) (1,158 ) — (1,291 ) Equity in earnings of unconsolidated affiliates 1,441 526 469 (1,967 ) 469 Losses on interest rate derivatives — — (18 ) — (18 ) Other, net — — (21 ) — (21 ) Income before income tax benefit 1,441 392 1,500 (1,967 ) 1,366 Income tax benefit — — (123 ) — (123 ) Net income 1,441 392 1,623 (1,967 ) 1,489 Less: Net income attributable to noncontrolling interest — — 53 — 53 Net income attributable to partners $ 1,441 $ 392 $ 1,570 $ (1,967 ) $ 1,436 Other comprehensive income $ — $ — $ 60 $ — $ 60 Comprehensive income 1,441 392 1,683 (1,967 ) 1,549 Comprehensive income attributable to noncontrolling interest — — 53 — 53 Comprehensive income attributable to partners $ 1,441 $ 392 $ 1,630 $ (1,967 ) $ 1,496 Year Ended December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash flows from operating activities $ 2,564 $ 1,047 $ 4,681 $ (3,807 ) $ 4,485 Cash flows from investing activities (2,240 ) (1,368 ) (5,672 ) 3,807 (5,473 ) Cash flows from financing activities (324 ) 277 981 — 934 Change in cash — (44 ) (10 ) — (54 ) Cash at beginning of period — 41 319 — 360 Cash at end of period $ — $ (3 ) $ 309 $ — $ 306 Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash flows from operating activities $ 553 $ 675 $ 3,492 $ (1,417 ) $ 3,303 Cash flows from investing activities (976 ) (2,400 ) (4,431 ) 1,417 (6,390 ) Cash flows from financing activities 423 1,729 768 — 2,920 Change in cash — 4 (171 ) — (167 ) Cash at beginning of period — 37 490 — 527 Cash at end of period $ — $ 41 $ 319 $ — $ 360 Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash flows from operating activities $ 1,441 $ 388 $ 2,886 $ (1,968 ) $ 2,747 Cash flows from investing activities (2,271 ) (1,815 ) (5,702 ) 1,968 (7,820 ) Cash flows from financing activities 830 1,363 2,744 — 4,937 Change in cash — (64 ) (72 ) — (136 ) Cash at beginning of period — 101 562 — 663 Cash at end of period $ — $ 37 $ 490 $ — $ 527

Estimates, Significant Accoun25

Estimates, Significant Accounting Policies and Balance Sheet Detials (Policy)	12 Months Ended
	Dec. 31, 2017
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Accounting Changes	Change in Accounting Policy During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
New Accounting Pronouncements, Policy [Policy Text Block]	Recent Accounting Pronouncements ASU 2014-09 In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material. For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of our midstream segment agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income. ASU 2016-02 In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. ASU 2016-16 On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. ASU 2017-04 In January 2017, the FASB issued ASU No. 2017-04 “ Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment. ” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017. ASU 2017-12 In August 2017, the FASB issued ASU No. 2017-12 “ Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. ” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
Revenue Recognition	Revenue Recognition Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues. Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and segment margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors. NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer. In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized. We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
Regulatory Accounting - Regulatory Assets and Liabilities	Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information	Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
Accounts Receivable	Accounts Receivable Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due. We enter into netting arrangements with counterparties to the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
Inventories	Inventories As discussed under “Change in Accounting Policy” in Note 2, the Partnership changed its accounting policy for certain inventory in the fourth quarter of 2017. Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method. Inventories consisted of the following: December 31, 2017 2016 Natural gas, NGLs, and refined products $ 733 $ 758 Crude oil 551 651 Spare parts and other 305 217 Total inventories $ 1,589 $ 1,626 We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2017, the Partnership recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, the Partnership recorded a $133 million fixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
Advances to and Investment in Affiliates	Advances to and Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.
Other Noncurrent Assets [Policy Text Block]	Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2017 2016 Regulatory assets $ 85 $ 86 Deferred charges 210 217 Restricted funds 192 190 Long-term affiliated receivable 85 90 Other 186 89 Total other non-current assets, net $ 758 $ 672 Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.
Intangible Assets Disclosure [Text Block]	Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: December 31, 2017 December 31, 2016 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 6,250 $ (1,003 ) $ 5,362 $ (737 ) Patents (10 years) 48 (26 ) 48 (21 ) Trade Names (20 years) 66 (25 ) 66 (22 ) Other (5 to 20 years) 1 — 2 (2 ) Total intangible assets $ 6,365 $ (1,054 ) $ 5,478 $ (782 ) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2017 2016 2015 Reported in depreciation, depletion and amortization $ 272 $ 193 $ 216 Estimated aggregate amortization expense for the next five years is as follows: Years Ending December 31: 2018 $ 280 2019 278 2020 278 2021 268 2022 256 We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. In 2015, we recorded $24 million of intangible asset impairments related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows.
Goodwill	Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services All Other Total Balance, December 31, 2015 $ 10 $ 912 $ 718 $ 772 $ 912 $ 2,104 $ 5,428 Reduction due to contribution of legacy Sunoco, Inc. retail business — — — — — (1,289 ) (1,289 ) Acquired — — 177 — 251 — 428 Impaired — (638 ) (32 ) — — — (670 ) Balance, December 31, 2016 10 274 863 772 1,163 815 3,897 Acquired — — 8 — 4 — 12 Impaired — (262 ) — (79 ) — (452 ) (793 ) Other — — (1 ) — — — (1 ) Balance, December 31, 2017 $ 10 $ 12 $ 870 $ 693 $ 1,167 $ 363 $ 3,115 Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During the fourth quarter of 2017, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $262 million in the interstate transportation and storage segment, $79 million in the NGL and refined products transportation and services segment and $452 million in the all other segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. During the fourth quarter of 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015. The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
Asset Retirement Obligation	Asset Retirement Obligations We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates. Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2017 and 2016 , in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time. As of December 31, 2017 and 2016, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $165 million and $170 million , respectively. Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely. Long-lived assets related to AROs aggregated $2 million and $14 million , and were reflected as property, plant and equipment on our balance sheet as of December 31, 2017 and 2016 , respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016 , respectively.
Accrued and Other Current Liabilities	Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: December 31, 2017 2016 Interest payable $ 443 $ 440 Customer advances and deposits 59 56 Accrued capital expenditures 1,006 749 Accrued wages and benefits 208 212 Taxes payable other than income taxes 108 63 Exchanges payable 154 208 Other 165 177 Total accrued and other current liabilities $ 2,143 $ 1,905 Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Redeemable Noncontrolling Interest [Text Block]	Redeemable Noncontrolling Interests The noncontrolling interest holders in one of our consolidated subsidiaries has the option to sell its interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on ETP’s consolidated balance sheet.
Environmental Costs, Policy [Policy Text Block]	Environmental Remediation We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2017 was $34.28 billion and $33.09 billion , respectively. As of December 31, 2016 , the aggregate fair value and carrying amount of our debt obligations was $33.85 billion and $32.93 billion , respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2017 , no transfers were made between any levels within the fair value hierarchy.
Contributions in Aid of Construction Costs	Contributions in Aid of Construction Costs On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs	Shipping and Handling Costs Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.
Costs and Expenses	Costs and Expenses Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel. We record the collection of taxes to be remitted to government authorities on a net basis except for our all other segment in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). For the year ended December 31, 2015 , excise taxes collected by Sunoco LP were $1.85 billion . The Partnership deconsolidated Sunoco LP effective July 1, 2015 and no excise taxes were collected by our consolidated operations subsequent to that date.
Consolidation, Subsidiary Stock Issuances, Policy [Policy Text Block]	Issuances of Subsidiary Units We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.
Income Tax, Policy [Policy Text Block]	Income Taxes ETP is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”). As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETP would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016, and 2015 , our qualifying income met the statutory requirement. The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline Company and until July 31, 2015, Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques. At inception of a hedge, 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. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period. If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations. Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]	Unit-Based Compensation For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pension and Other Postretirement Plans, Policy [Policy Text Block]	Pensions and Other Postretirement Benefit Plans The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income (Loss)	Allocation of Income For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for United States Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.

Estimates, Significant Accoun26

Estimates, Significant Accounting Policies and Balance Sheet Detials (Tables)	12 Months Ended
	Dec. 31, 2017
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows: Year Ended December 31, 2016 Year Ended December 31, 2015 As Originally Reported* Effect of Change As Adjusted As Originally Reported* Effect of Change As Adjusted Consolidated Statement of Operations and Comprehensive Income: Cost of products sold $ 15,039 $ 41 $ 15,080 $ 26,682 $ 32 $ 26,714 Operating income 1,802 (41 ) 1,761 2,259 (32 ) 2,227 Income before income tax benefit 438 (41 ) 397 1,398 (32 ) 1,366 Net income 624 (41 ) 583 1,521 (32 ) 1,489 Net income attributable to partners 297 (9 ) 288 1,398 (9 ) 1,389 Net loss per common unit - basic (1.37 ) (0.01 ) (1.38 ) (0.06 ) (0.01 ) (0.07 ) Net loss per common unit - diluted (1.37 ) (0.01 ) (1.38 ) (0.07 ) (0.01 ) (0.08 ) Comprehensive income 628 (41 ) 587 1,581 (32 ) 1,549 Comprehensive income attributable to partners 301 (9 ) 292 1,458 (9 ) 1,449 Consolidated Statements of Cash Flows: Net income 624 (41 ) 583 1,521 (32 ) 1,489 Inventory valuation adjustments (170 ) 170 — 104 (162 ) (58 ) Net change in operating assets and liabilities (change in inventories) (117 ) (129 ) (246 ) (1,367 ) 194 (1,173 ) Consolidated Balance Sheets (at period end): Inventories 1,712 (86 ) 1,626 1,213 (45 ) 1,168 Total partners' capital 18,642 (21 ) 18,621 20,836 (12 ) 20,824 * Amounts reflect certain reclassifications made to conform to the current year presentation.
Net change in operating assets and liabilities (net of acquisitions)	The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2017 2016 2015 Accounts receivable $ (950 ) $ (919 ) $ 819 Accounts receivable from related companies 67 30 (243 ) Inventories 37 (497 ) (157 ) Other current assets 39 83 (178 ) Other non-current assets, net (94 ) (78 ) 188 Accounts payable 758 972 (1,215 ) Accounts payable to related companies (3 ) 29 (160 ) Accrued and other current liabilities (47 ) 39 (83 ) Other non-current liabilities 24 33 (219 ) Price risk management assets and liabilities, net 9 62 75 Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (160 ) $ (246 ) $ (1,173 )
Non-cash investing and financing activities and supplemental cash flow information	Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2017 2016 2015 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 1,059 $ 822 $ 896 Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP — 194 — Net gains from subsidiary common unit transactions — 37 300 NON-CASH FINANCING ACTIVITIES: Issuance of Common Units in connection with the PennTex Acquisition $ — $ 307 $ — Issuance of Common Units in connection with the Regency Merger — — 9,250 Issuance of Class H Units in connection with the Bakken Pipeline Transaction — — 1,946 Contribution of assets from noncontrolling interest 988 — 34 Redemption of Common Units in connection with the Bakken Pipeline Transaction — — 999 Redemption of Common Units in connection with the Sunoco LP Exchange — — 52 SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 1,329 $ 1,411 $ 1,467 Cash paid for (refund of) income taxes 50 (229 ) 71
Inventory	Inventories consisted of the following: December 31, 2017 2016 Natural gas, NGLs, and refined products $ 733 $ 758 Crude oil 551 651 Spare parts and other 305 217 Total inventories $ 1,589 $ 1,626
Other Current Assets	Other current assets consisted of the following: December 31, 2017 2016 Deposits paid to vendors $ 64 $ 74 Prepaid expenses and other 146 224 Total other current assets $ 210 $ 298
Components and useful lives of property, plant and equipment	Components and useful lives of property, plant and equipment were as follows: December 31, 2017 2016 Land and improvements $ 1,706 $ 676 Buildings and improvements (1 to 45 years) 1,960 1,617 Pipelines and equipment (5 to 83 years) 44,050 36,356 Natural gas and NGL storage facilities (5 to 46 years) 1,681 1,452 Bulk storage, equipment and facilities (2 to 83 years) 3,036 3,701 Vehicles (1 to 25 years) 124 217 Right of way (20 to 83 years) 3,424 3,349 Natural resources 434 434 Other (1 to 40 years) 534 484 Construction work-in-process 10,750 9,934 67,699 58,220 Less – Accumulated depreciation and depletion (9,262 ) (7,303 ) Property, plant and equipment, net $ 58,437 $ 50,917
Depreciation expense	We recognized the following amounts for the periods presented: Years Ended December 31, 2017 2016 2015 Depreciation and depletion expense $ 2,060 $ 1,793 $ 1,713 Capitalized interest 283 199 163
Other non-current assets	Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization.
Components and useful lives of intangibles assets	Components and useful lives of intangible assets were as follows: December 31, 2017 December 31, 2016 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 6,250 $ (1,003 ) $ 5,362 $ (737 ) Patents (10 years) 48 (26 ) 48 (21 ) Trade Names (20 years) 66 (25 ) 66 (22 ) Other (5 to 20 years) 1 — 2 (2 ) Total intangible assets $ 6,365 $ (1,054 ) $ 5,478 $ (782 )
Amortization expense of intangible assets	Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2017 2016 2015 Reported in depreciation, depletion and amortization $ 272 $ 193 $ 216
Amortization expense, expected	Estimated aggregate amortization expense for the next five years is as follows: Years Ending December 31: 2018 $ 280 2019 278 2020 278 2021 268 2022 256
Changes in carrying amount of goodwill	Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services All Other Total Balance, December 31, 2015 $ 10 $ 912 $ 718 $ 772 $ 912 $ 2,104 $ 5,428 Reduction due to contribution of legacy Sunoco, Inc. retail business — — — — — (1,289 ) (1,289 ) Acquired — — 177 — 251 — 428 Impaired — (638 ) (32 ) — — — (670 ) Balance, December 31, 2016 10 274 863 772 1,163 815 3,897 Acquired — — 8 — 4 — 12 Impaired — (262 ) — (79 ) — (452 ) (793 ) Other — — (1 ) — — — (1 ) Balance, December 31, 2017 $ 10 $ 12 $ 870 $ 693 $ 1,167 $ 363 $ 3,115
Schedule of Asset Retirement Obligations [Table Text Block]	Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Accounts payable and accrued liabilities	Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Summary of fair value of financials	The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2017 and 2016 based on inputs used to derive their fair values: Fair Value Total Fair Value Measurements at December 31, 2017 Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 11 $ 11 $ — Swing Swaps IFERC 13 — 13 Fixed Swaps/Futures 70 70 — Forward Physical Swaps 8 — 8 Power: Forwards 23 — 23 Natural Gas Liquids – Forwards/Swaps 193 193 — Crude – Futures 2 2 — Total commodity derivatives 320 276 44 Other non-current assets 21 14 7 Total assets $ 341 $ 290 $ 51 Liabilities: Interest rate derivatives $ (219 ) $ — $ (219 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (24 ) (24 ) — Swing Swaps IFERC (15 ) (1 ) (14 ) Fixed Swaps/Futures (57 ) (57 ) — Forward Physical Swaps (2 ) — (2 ) Power – Forwards (22 ) — (22 ) Natural Gas Liquids – Forwards/Swaps (192 ) (192 ) — Refined Products – Futures (25 ) (25 ) — Crude – Futures (1 ) (1 ) — Total commodity derivatives (338 ) (300 ) (38 ) Total liabilities $ (557 ) $ (300 ) $ (257 ) Fair Value Total Fair Value Measurements at December 31, 2016 Level 1 Level 2 Level 3 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 14 $ 14 $ — $ — Swing Swaps IFERC 2 — 2 — Fixed Swaps/Futures 96 96 — — Forward Physical Swaps 1 — 1 — Power: Forwards 4 — 4 — Futures 1 1 — — Options – Calls 1 1 — — Natural Gas Liquids – Forwards/Swaps 233 233 — — Refined Products – Futures 1 1 — — Crude – Futures 9 9 — — Total commodity derivatives 362 355 7 — Other non-current assets 13 8 5 — Total assets $ 375 $ 363 $ 12 $ — Liabilities: Interest rate derivatives $ (193 ) $ — $ (193 ) $ — Embedded derivatives in the Legacy ETP Preferred Units (1 ) — — (1 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (11 ) (11 ) — — Swing Swaps IFERC (3 ) — (3 ) — Fixed Swaps/Futures (149 ) (149 ) — — Power: Forwards (5 ) — (5 ) — Futures (1 ) (1 ) — — Natural Gas Liquids – Forwards/Swaps (273 ) (273 ) — — Refined Products – Futures (17 ) (17 ) — — Crude – Futures (13 ) (13 ) — — Total commodity derivatives (472 ) (464 ) (8 ) — Total liabilities $ (666 ) $ (464 ) $ (201 ) $ (1 )

Acquisitions, Divestitures an27

Acquisitions, Divestitures and Related Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
PennTex Acquisition [Member]
Summary Of Preliminary Assets And Liability Acquired	The total purchase price was allocated as follows: At November 1, 2016 Total current assets $ 34 Property, plant and equipment 393 Goodwill (1) 177 Intangible assets 446 1,050 Total current liabilities 6 Long-term debt, less current maturities 164 Other non-current liabilities 17 Noncontrolling interest 236 423 Total consideration 627 Cash received 21 Total consideration, net of cash received $ 606 (1) None of the goodwill is expected to be deductible for tax purposes. The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Sunoco LP and Legacy Sunoco Inc. [Member]
Additional Financial Information Disclosure [Text Block]	Following is a summary of amounts reflected for the prior periods in ETP’s consolidated statements of operations related to Sunoco, LLC and the legacy Sunoco, Inc. retail business, which operations are no longer consolidated: Year Ended December 31, 2015 Revenues $ 12,482 Cost of products sold 11,174 Operating expenses 798 Selling, general and administrative expenses 106

Advances to and Investments i28

Advances to and Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2017
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Investments in and Advances to Affiliates [Table Text Block]	The carrying values of the Partnership’s advances to and investments in unconsolidated affiliates as of December 31, 2017 and 2016 were as follows: December 31, 2017 2016 Citrus $ 1,754 $ 1,729 FEP 121 101 MEP 242 318 HPC 28 382 Sunoco LP 1,095 1,225 Others 576 525 Total $ 3,816 $ 4,280 The following table presents equity in earnings (losses) of unconsolidated affiliates: Years Ended December 31, 2017 2016 2015 Citrus $ 144 $ 102 $ 97 FEP 53 51 55 MEP 38 40 45 HPC (1) (168 ) 31 32 Sunoco, LLC — — (10 ) Sunoco LP (2) 12 (211 ) 202 Other 77 46 48 Total equity in earnings of unconsolidated affiliates 156 59 469 (1) For the year ended December 31, 2017 , equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million . (2) For the years ended December 31, 2017 and 2016 , equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $176 million and $277 million , respectively.
Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block]	Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP, HPC and Sunoco LP (on a 100% basis) for all periods presented: December 31, 2017 2016 Current assets $ 4,750 $ 1,532 Property, plant and equipment, net 9,893 10,310 Other assets 2,286 5,980 Total assets $ 16,929 $ 17,822 Current liabilities $ 2,075 $ 1,918 Non-current liabilities 9,375 10,343 Equity 5,479 5,561 Total liabilities and equity $ 16,929 $ 17,822 Years Ended December 31, 2017 2016 2015 Revenue $ 13,081 $ 11,150 $ 13,815 Operating income 636 859 1,052 Net income (loss) 294 (22 ) 664 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

Net Income Per Limited Partne29

Net Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of Earnings Per Unit, Basic and Diluted	The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit. The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger. Years Ended December 31, 2017 2016 2015 Net income $ 2,501 $ 583 $ 1,489 Less: Income attributable to noncontrolling interest 420 295 134 Less: Loss attributable to predecessor — — (34 ) Net income, net of noncontrolling interest 2,081 288 1,389 General Partner’s interest in net income 990 948 1,064 Preferred Unitholders’ interest in net income 12 — — Class H Unitholder’s interest in net income 93 351 258 Class I Unitholder’s interest in net income — 8 94 Common Unitholders’ interest in net income (loss) 986 (1,019 ) (27 ) Additional earnings allocated from (to) General Partner 9 (10 ) (5 ) Distributions on employee unit awards, net of allocation to General Partner (27 ) (19 ) (16 ) Net income (loss) available to Common Unitholders $ 968 $ (1,048 ) $ (48 ) Weighted average Common Units – basic 1,032.7 758.2 649.2 Basic net income (loss) per Common Unit $ 0.94 $ (1.38 ) $ (0.07 ) Income (loss) available to Common Unitholders $ 968 $ (1,048 ) $ (48 ) Loss attributable to Legacy ETP Preferred Units — — (6 ) Diluted income (loss) available to Common Unitholders $ 968 $ (1,048 ) $ (54 ) Weighted average Common Units – basic 1,032.7 758.2 649.2 Dilutive effect of unvested Unit Awards 5.1 — — Dilutive effect of Legacy ETP Preferred Units — — 1.0 Weighted average Common Units – diluted 1,037.8 758.2 650.2 Diluted income (loss) per Common Unit $ 0.93 $ (1.38 ) $ (0.08 )

Debt Obligations (Tables)

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Obligations [Abstract]
Debt instruments	Our debt obligations consist of the following: December 31, 2017 2016 ETP Debt 6.125% Senior Notes due February 15, 2017 $ — $ 400 2.50% Senior Notes due June 15, 2018 (1) 650 650 6.70% Senior Notes due July 1, 2018 (1) 600 600 9.70% Senior Notes due March 15, 2019 400 400 9.00% Senior Notes due April 15, 2019 450 450 5.50% Senior Notes due February 15, 2020 250 250 5.75% Senior Notes due September 1, 2020 400 400 4.15% Senior Notes due October 1, 2020 1,050 1,050 4.40% Senior Notes due April 1, 2021 600 600 6.50% Senior Notes due July 15, 2021 — 500 4.65% Senior Notes due June 1, 2021 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 4.65% Senior Notes due February 15, 2022 300 300 5.875% Senior Notes due March 1, 2022 900 900 5.00% Senior Notes due October 1, 2022 700 700 3.45% Senior Notes due January 15, 2023 350 350 3.60% Senior Notes due February 1, 2023 800 800 5.50% Senior Notes due April 15, 2023 — 700 4.50% Senior Notes due November 1, 2023 600 600 4.90% Senior Notes due February 1, 2024 350 350 7.60% Senior Notes due February 1, 2024 277 277 4.25% Senior Notes due April 1, 2024 500 500 9.00% Debentures due November 1, 2024 65 65 4.05% Senior Notes due March 15, 2025 1,000 1,000 5.95% Senior Notes due December 1, 2025 400 400 4.75% Senior Notes due January 15, 2026 1,000 1,000 3.90% Senior Notes due July 15, 2026 550 550 4.20% Senior Notes due April 15, 2027 600 — 4.00% Senior Notes due October 1, 2027 750 — 8.25% Senior Notes due November 15, 2029 267 267 4.90% Senior Notes due March 15, 2035 500 500 6.625% Senior Notes due October 15, 2036 400 400 7.50% Senior Notes due July 1, 2038 550 550 6.85% Senior Notes due February 15, 2040 250 250 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.30% Senior Notes due April 1, 2044 700 700 5.15% Senior Notes due March 15, 2045 1,000 1,000 5.35% Senior Notes due May 15, 2045 800 800 6.125% Senior Notes due December 15, 2045 1,000 1,000 5.30% Senior Notes due April 15, 2047 900 — 5.40% Senior Notes due October 1, 2047 1,500 — Floating Rate Junior Subordinated Notes due November 1, 2066 546 546 ETP $4.0 billion Revolving Credit Facility due December 2022 2,292 — ETP $1.0 billion 364-Day Credit Facility due November 2018 (2) 50 — ETLP $3.75 billion Revolving Credit Facility due November 2019 — 2,777 Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 — 1,292 Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017 — 630 Unamortized premiums, discounts and fair value adjustments, net 33 66 Deferred debt issuance costs (170 ) (166 ) 29,210 29,454 Transwestern Debt 5.64% Senior Notes due May 24, 2017 — 82 5.36% Senior Notes due December 9, 2020 175 175 5.89% Senior Notes due May 24, 2022 150 150 5.66% Senior Notes due December 9, 2024 175 175 6.16% Senior Notes due May 24, 2037 75 75 Deferred debt issuance costs (1 ) (1 ) 574 656 Panhandle Debt 6.20% Senior Notes due November 1, 2017 — 300 7.00% Senior Notes due June 15, 2018 400 400 8.125% Senior Notes due June 1, 2019 150 150 7.60% Senior Notes due February 1, 2024 82 82 7.00% Senior Notes due July 15, 2029 66 66 8.25% Senior Notes due November 15, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 28 50 813 1,135 Sunoco, Inc. Debt 5.75% Senior Notes due January 15, 2017 — 400 Bakken Project Debt Bakken Project $2.50 billion Credit Facility due August 2019 2,500 1,100 Deferred debt issuance costs (8 ) (13 ) 2,492 1,087 PennTex Debt PennTex $275 million Revolving Credit Facility due December 2019 — 168 Other 5 30 Total debt 33,094 32,930 Less: Current maturities of long-term debt 407 1,189 Long-term debt, less current maturities $ 32,687 $ 31,741
Future maturities of long-term debt	The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $118 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: 2018 $ 1,700 2019 3,500 2020 1,875 2021 1,400 2022 5,346 Thereafter 19,391 Total $ 33,212

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2017
Schedule of Distributions Made To General and Limited Partners [Table Text Block]	The following table shows the target distribution levels and distribution “splits” between the general and limited partners and the holders of the Partnership’s incentive distribution rights (”IDRs”): Marginal Percentage Interest in Distributions Total Quarterly Distribution Target Amount IDRs Partners (1) Minimum Quarterly Distribution $0.0750 —% 100% First Target Distribution up to $0.0833 —% 100% Second Target Distribution above $0.0833 up to $0.0958 13% 87% Third Target Distribution above $0.0958 up to $0.2638 35% 65% Thereafter above $0.2638 48% 52% (1) Includes general partner and limited partner interests, based on the proportionate ownership of each.
Schedule of Capital Units [Table Text Block]	The change in Common Units was as follows: Years Ended December 31, 2017 (1) 2016 (1) 2015 (1) Number of Common Units, beginning of period 794.8 758.5 533.4 Common Units redeemed in connection with certain transactions — (26.7 ) (77.8 ) Common Units issued in connection with public offerings 54.0 — — Common Units issued in connection with certain acquisitions — 13.3 258.2 Common Units issued in connection with the Distribution Reinvestment Plan 12.0 9.9 11.7 Common Units issued in connection with Equity Distribution Agreements 22.6 39.0 31.7 Common Units issued to ETE in a private placement transaction 23.7 — — Common Unit increase from Sunoco Logistics Merger (2) 255.4 — — Issuance of Common Units under equity incentive plans 1.6 0.8 1.3 Number of Common Units, end of period 1,164.1 794.8 758.5
Schedule of Future Relinquishments of Incentive Distribution Rights [Table Text Block]	In connection with previous transactions, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods: Total Year 2018 $ 153 2019 128 Each year beyond 2019 33
Schedule of Preferred Units [Table Text Block]	Distributions declared and paid by ETP to the preferred unitholders were as follows: Distribution per Preferred Unit Quarter Ended Record Date Payment Date Series A Series B December 31, 2017 February 1, 2018 February 15, 2018 $ 15.451 $ 16.378
Comprehensive Income (Loss) Note [Text Block]	The following table presents the components of AOCI, net of tax: December 31, 2017 2016 Available-for-sale securities $ 8 $ 2 Foreign currency translation adjustment (5 ) (5 ) Actuarial gain related to pensions and other postretirement benefits (5 ) 7 Investments in unconsolidated affiliates, net 5 4 Total AOCI, net of tax $ 3 $ 8
Schedule of taxes related to accumulated other comprehensive income [Table Text Block]	The table below sets forth the tax amounts included in the respective components of other comprehensive income: December 31, 2017 2016 Available-for-sale securities $ (2 ) $ (2 ) Foreign currency translation adjustment 3 3 Actuarial loss relating to pension and other postretirement benefits 3 — Total $ 4 $ 1
ETP [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows: Quarter Ended ETP Sunoco Logistics December 31, 2014 $ 0.6633 $ 0.4000 March 31, 2015 0.6767 0.4190 June 30, 2015 0.6900 0.4380 September 30, 2015 0.7033 0.4580 December 31, 2015 0.7033 0.4790 March 31, 2016 0.7033 0.4890 June 30, 2016 0.7033 0.5000 September 30, 2016 0.7033 0.5100 December 31, 2016 0.7033 0.5200 Distributions on common units declared and paid by Post-Merger ETP were as follows: Quarter Ended Record Date Payment Date Rate March 31, 2017 May 10, 2017 May 16, 2017 $ 0.5350 June 30, 2017 August 7, 2017 August 15, 2017 0.5500 September 30, 2017 November 7, 2017 November 14, 2017 0.5650 December 31, 2017 February 8, 2018 February 14, 2018 0.5650

Unit-Based Compensation Plans32

Unit-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
UNIT-BASED COMPENSATION PLANS	UNIT-BASED COMPENSATION PLANS: ETP Unit-Based Compensation Plan We have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2017 , an aggregate total of 8.4 million ETP Common Units remain available to be awarded under our equity incentive plans. Restricted Units We have granted restricted unit awards to employees that vest over a specified time period, typically a five -year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five -year service vesting requirement. The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2016 9.4 $ 27.68 Legacy Sunoco Logistics unvested awards as of December 31, 2016 3.2 28.57 Awards granted 4.9 17.69 Awards vested (2.3 ) 34.22 Awards forfeited (1.1 ) 25.03 Unvested awards as of December 31, 2017 14.1 23.18 During the years ended December 31, 2017, 2016, and 2015 , the weighted average grant-date fair value per unit award granted was $17.69 , $23.82 and $23.47 , respectively. The total fair value of awards vested was $40 million , $40 million and $57 million , respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2017 , a total of 14.1 million unit awards remain unvested, for which ETP expects to recognize a total of $189 million in compensation expense over a weighted average period of 2.7 years . Cash Restricted Units. The Partnership previously granted cash restricted units, which entitled the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting. The Partnership does not currently have any cash restricted units outstanding.
Activity of the awards granted to employees and non-employee directors	The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2016 9.4 $ 27.68 Legacy Sunoco Logistics unvested awards as of December 31, 2016 3.2 28.57 Awards granted 4.9 17.69 Awards vested (2.3 ) 34.22 Awards forfeited (1.1 ) 25.03 Unvested awards as of December 31, 2017 14.1 23.18

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) are summarized as follows: Years Ended December 31, 2017 2016 2015 Current expense (benefit): Federal $ 53 $ 18 $ (274 ) State (18 ) (35 ) (51 ) Total 35 (17 ) (325 ) Deferred expense (benefit): Federal (1,723 ) (173 ) 231 State 192 4 (29 ) Total (1,531 ) (169 ) 202 Total income tax benefit $ (1,496 ) $ (186 ) $ (123 )
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Historically, our effective rate has differed from the statutory rate primarily due to Partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2017 , 2016 and 2015 is as follows: Years Ended December 31, 2017 2016* 2015* Income tax expense at United States statutory rate of 35 percent $ 352 $ 139 $ 479 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax (457 ) (504 ) (504 ) Federal rate change (1,559 ) — — Goodwill impairments 172 223 — State income taxes (net of federal income tax effects) 131 (17 ) (37 ) Dividend received deduction (14 ) (15 ) (24 ) Audit settlement — — (7 ) Change in tax status of subsidiary (124 ) — — Other 3 (12 ) (30 ) Income tax benefit $ (1,496 ) $ (186 ) $ (123 ) * As adjusted. See Note 2.
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: December 31, 2017 2016 Deferred income tax assets: Net operating losses and alternative minimum tax credit $ 604 $ 380 Pension and other postretirement benefits 21 30 Long-term debt 14 32 Other 93 84 Total deferred income tax assets 732 526 Valuation allowance (189 ) (118 ) Net deferred income tax assets $ 543 $ 408 Deferred income tax liabilities: Property, plant and equipment $ (664 ) $ (1,054 ) Investment in unconsolidated affiliates (2,664 ) (3,728 ) Other (98 ) (20 ) Total deferred income tax liabilities (3,426 ) (4,802 ) Net deferred income taxes $ (2,883 ) $ (4,394 )
Balance Sheet Classification of Deferred Taxes [Table Text Block]	The table below provides a rollforward of the net deferred income tax liability as follows: December 31, 2017 2016 Net deferred income tax liability, beginning of year $ (4,394 ) $ (4,082 ) Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) — (460 ) Tax provision 1,531 169 Other (20 ) (21 ) Net deferred income tax liability, end of year $ (2,883 ) $ (4,394 )
Schedule of Unrecognized Tax Benefits Rollforward [Table Text Block]	The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2017 2016 2015 Balance at beginning of year $ 615 $ 610 $ 440 Additions attributable to tax positions taken in the current year — 8 — Additions attributable to tax positions taken in prior years 28 18 178 Reduction attributable to tax positions taken in prior years (25 ) (20 ) — Lapse of statute (9 ) (1 ) (8 ) Balance at end of year $ 609 $ 615 $ 610

Regulatory Matters, Commitmen34

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Tables)	12 Months Ended
	Dec. 31, 2017
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Lessee, Operating Lease, Disclosure [Table Text Block]	We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034 . The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: Years Ended December 31, 2017 2016 2015 Rental expense (1) $ 90 $ 81 $ 176 Less: Sublease rental income — (1 ) (16 ) Rental expense, net $ 90 $ 80 $ 160 (1) Includes contingent rentals totaling $26 million for the year ended December 31, 2015
Future Minimum Lease Commitments	Future minimum lease commitments for such leases are: Years Ending December 31: 2018 $ 39 2019 36 2020 37 2021 30 2022 23 Thereafter 92 Future minimum lease commitments 257 Less: Sublease rental income (8 ) Net future minimum lease commitments $ 249
Environmental Exit Costs by Cost [Table Text Block]	The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements. December 31, 2017 2016 Current $ 36 $ 26 Non-current 314 283 Total environmental liabilities $ 350 $ 309

Derivative assets and liabilt35

Derivative assets and liabilties (Tables)	12 Months Ended
	Dec. 31, 2017
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Outstanding commodity-related derivatives	The following table details our outstanding commodity-related derivatives: December 31, 2017 December 31, 2016 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (BBtu): Fixed Swaps/Futures 1,078 2018 (683 ) 2017 Basis Swaps IFERC/NYMEX (1) 48,510 2018-2020 2,243 2017 Options – Calls 13,000 2018 — — Power (Megawatt): Forwards 435,960 2018-2019 391,880 2017-2018 Futures (25,760 ) 2018 109,564 2017-2018 Options – Puts (153,600 ) 2018 (50,400 ) 2017 Options – Calls 137,600 2018 186,400 2017 Crude (MBbls) – Futures — — (617 ) 2017 (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX 4,650 2018-2020 10,750 2017-2018 Swing Swaps IFERC 87,253 2018-2019 (5,663 ) 2017 Fixed Swaps/Futures (4,700 ) 2018-2019 (52,653 ) 2017-2019 Forward Physical Contracts (145,105 ) 2018-2020 (22,492 ) 2017 Natural Gas Liquid (MBbls) – Forwards/Swaps 6,679 2018-2019 (5,787 ) 2017 Refined Products (MBbls) – Futures (3,783 ) 2018-2019 (2,240 ) 2017 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (39,770 ) 2018 (36,370 ) 2017 Fixed Swaps/Futures (39,770 ) 2018 (36,370 ) 2017 Hedged Item – Inventory 39,770 2018 36,370 2017 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Interest rate swaps outstanding	Term Type (1) Notional Amount Outstanding December 31, 2017 December 31, 2016 July 2017 (2) Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $ — $ 500 July 2018 (2) Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300 200 July 2019 (2) Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300 200 July 2020 (2) Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400 — December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 1,200 March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300 300 (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
Fair Value of derivative instruments	The following table provides a summary of our derivative assets and liabilities: Fair Value of Derivative Instruments Asset Derivatives Liability Derivatives December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 14 $ — $ (2 ) $ (4 ) 14 — (2 ) (4 ) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 262 338 (281 ) (416 ) Commodity derivatives 44 24 (55 ) (52 ) Interest rate derivatives — — (219 ) (193 ) Embedded derivatives in Legacy ETP Preferred Units — — — (1 ) 306 362 (555 ) (662 ) Total derivatives $ 320 $ 362 $ (557 ) $ (666 )
Offsetting Assets Table Text Block [Table Text Block]	The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Derivatives without offsetting agreements Derivative liabilities $ — $ — $ (219 ) $ (194 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 44 24 (55 ) (52 ) Broker cleared derivative contracts Other current assets (liabilities) 276 338 (283 ) (420 ) 320 362 (557 ) (666 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (20 ) (4 ) 20 4 Counterparty netting Other current assets (liabilities) (263 ) (338 ) 263 338 Total net derivatives $ 37 $ 20 $ (274 ) $ (324 )
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Years Ended December 31, 2017 2016 2015 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 26 $ 14 $ 21 Total $ 26 $ 14 $ 21
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2017 2016 2015 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ 31 $ (35 ) $ (11 ) Commodity derivatives – Non-trading Cost of products sold 3 (173 ) 23 Interest rate derivatives Losses on interest rate derivatives (37 ) (12 ) (18 ) Embedded derivatives Other, net 1 4 12 Total $ (2 ) $ (216 ) $ 6

Retirement Benefits Retirement

Retirement Benefits Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: December 31, 2017 December 31, 2016 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Change in benefit obligation: Benefit obligation at beginning of period $ 18 $ 51 $ 165 $ 20 $ 57 $ 180 Interest cost 1 1 4 1 2 4 Amendments — — 7 — — — Benefits paid, net (2 ) (6 ) (20 ) (1 ) (7 ) (21 ) Actuarial (gain) loss and other 2 1 (1 ) (2 ) (1 ) 2 Settlements (18 ) — — — — — Benefit obligation at end of period 1 47 155 18 51 165 Change in plan assets: Fair value of plan assets at beginning of period 12 — 248 15 — 253 Return on plan assets and other 3 — 11 (2 ) — 6 Employer contributions 6 — 10 — — 10 Benefits paid, net (2 ) — (20 ) (1 ) — (21 ) Settlements (18 ) — — — — — Fair value of plan assets at end of period 1 — 249 12 — 248 Amount underfunded (overfunded) at end of period $ — $ 47 $ (94 ) $ 6 $ 51 $ (83 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 120 $ — $ — $ 108 Current liabilities — (8 ) (2 ) — (7 ) (2 ) Non-current liabilities — (39 ) (24 ) (6 ) (44 ) (23 ) $ — $ (47 ) $ 94 $ (6 ) $ (51 ) $ 83 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain $ — $ 5 $ (17 ) $ — $ — $ (12 ) Prior service cost — — 20 — — 14 $ — $ 5 $ 3 $ — $ — $ 2
Schedule of Accumulated and Projected Benefit Obligations [Table Text Block]	The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2017 December 31, 2016 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 1 $ 47 N/A $ 18 $ 51 N/A Accumulated benefit obligation 1 47 $ 155 18 51 $ 165 Fair value of plan assets 1 — 249 12 — 248
Schedule of Net Benefit Costs [Table Text Block]	December 31, 2017 December 31, 2016 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Interest cost $ 2 $ 4 $ 3 $ 4 Expected return on plan assets — (9 ) (1 ) (8 ) Prior service cost amortization — 2 — 1 Net periodic benefit cost $ 2 $ (3 ) $ 2 $ (3 )
Schedule of Benefit Obligations Assumptions [Table Text Block]	The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2017 December 31, 2016 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.27 % 2.34 % 3.65 % 2.34 % Rate of compensation increase N/A N/A N/A N/A
Schedule or Description of Weighted Average Discount Rate [Table Text Block]	The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2017 December 31, 2016 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.52 % 3.10 % 3.60 % 3.06 % Expected return on assets: Tax exempt accounts 3.50 % 7.00 % 3.50 % 7.00 % Taxable accounts N/A 4.50 % N/A 4.50 % Rate of compensation increase N/A N/A N/A N/A
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]	The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: December 31, 2017 2016 Health care cost trend rate 7.20 % 6.73 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.99 % 4.96 % Year that the rate reaches the ultimate trend rate 2023 2021
Fair Value of Plan Assets [Table Text Block]	The fair value of the pension plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2017 Fair Value Total Level 1 Level 2 Level 3 Asset category: Mutual funds (1) $ 1 $ 1 $ — $ — Total $ 1 $ 1 $ — $ — (1) Comprised of approximately 100% equities as of December 31, 2017 . Fair Value Measurements at December 31, 2016 Fair Value Total Level 1 Level 2 Level 3 Asset category: Mutual funds (1) $ 12 $ 12 $ — $ — Total $ 12 $ 12 $ — $ — (1) Comprised of approximately 100% equities as of December 31, 2016 . The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2017 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 33 $ 33 $ — $ — Mutual funds (1) 146 146 — — Fixed income securities 70 — 70 — Total $ 249 $ 179 $ 70 $ — (1) Primarily comprised of approximately 48% equities, 51% fixed income securities and 1% cash as of December 31, 2017 . Fair Value Measurements at December 31, 2016 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 23 $ 23 $ — $ — Mutual funds (1) 134 134 — — Fixed income securities 91 — 91 — Total $ 248 $ 157 $ 91 $ — (1) Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016 . The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.
Schedule of Expected Benefit Payments [Table Text Block]	Panhandle and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: Years Pension Benefits - Unfunded Plans (1) Other Postretirement Benefits (Gross, Before Medicare Part D) 2018 $ 8 $ 24 2019 6 23 2020 6 21 2021 5 19 2022 4 17 2023 – 2027 15 37

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Schedule Of Related Party Transactions By Related Party [Table Text Block]	The following table summarizes the affiliate revenues on our consolidated statements of operations: Years Ended December 31, 2017 2016 2015 Affiliated revenues $ 697 $ 377 $ 417
Related Party Balances For Period Presented [Table Text Block]	The following table summarizes the related company balances on our consolidated balance sheets: December 31, 2017 2016 Accounts receivable from related companies: ETE $ — $ 22 Sunoco LP 219 96 FGT 11 15 Other 88 76 Total accounts receivable from related companies $ 318 $ 209 Accounts payable to related companies: Sunoco LP 195 20 Other 14 23 Total accounts payable to related companies $ 209 $ 43 December 31, 2017 2016 Long-term notes receivable (payable) – related companies: Sunoco LP $ 85 $ 87 Phillips 66 — (250 ) Net long-term notes receivable (payable) – related companies $ 85 $ (163 )

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2017
Reportable Segments [Abstract]
Reportable segments	The following tables present financial information by segment: Years Ended December 31, 2017 2016 2015 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,891 $ 2,155 $ 1,912 Intersegment revenues 192 458 338 3,083 2,613 2,250 Interstate transportation and storage: Revenues from external customers 915 946 1,008 Intersegment revenues 19 23 17 934 969 1,025 Midstream: Revenues from external customers 2,510 2,342 2,607 Intersegment revenues 4,433 2,837 2,449 6,943 5,179 5,056 NGL and refined products transportation and services: Revenues from external customers 8,326 5,973 4,569 Intersegment revenues 322 436 428 8,648 6,409 4,997 Crude oil transportation and services: Revenues from external customers 11,672 7,539 8,980 Intersegment revenues 31 — — 11,703 7,539 8,980 All other: Revenues from external customers 2,740 2,872 15,216 Intersegment revenues 161 400 558 2,901 3,272 15,774 Eliminations (5,158 ) (4,154 ) (3,790 ) Total revenues $ 29,054 $ 21,827 $ 34,292 Years Ended December 31, 2017 2016 2015 Cost of products sold: Intrastate transportation and storage $ 2,327 $ 1,897 $ 1,554 Midstream 4,761 3,381 3,264 NGL and refined products transportation and services 6,508 4,553 3,431 Crude oil transportation and services 9,826 6,416 8,158 All other 2,509 2,942 14,029 Eliminations (5,130 ) (4,109 ) (3,722 ) Total cost of products sold $ 20,801 $ 15,080 $ 26,714 Years Ended December 31, 2017 2016 2015 Depreciation, depletion and amortization: Intrastate transportation and storage $ 147 $ 144 $ 129 Interstate transportation and storage 214 207 210 Midstream 954 840 720 NGL and refined products transportation and services 401 355 290 Crude oil transportation and services 402 251 218 All other 214 189 362 Total depreciation, depletion and amortization $ 2,332 $ 1,986 $ 1,929 Years Ended December 31, 2017 2016 2015 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ (156 ) $ 35 $ 32 Interstate transportation and storage 236 193 197 Midstream 20 19 (19 ) NGL and refined products transportation and services 33 41 29 Crude oil transportation and services 4 (4 ) (9 ) All other 19 (225 ) 239 Total equity in earnings of unconsolidated affiliates $ 156 $ 59 $ 469 Years Ended December 31, 2017 2016 2015 Segment Adjusted EBITDA: Intrastate transportation and storage $ 626 $ 613 $ 543 Interstate transportation and storage 1,098 1,117 1,155 Midstream 1,481 1,133 1,237 NGL and refined products transportation and services 1,641 1,496 1,179 Crude oil transportation and services 1,379 834 521 All other 487 540 882 Total Segment Adjusted EBITDA 6,712 5,733 5,517 Depreciation, depletion and amortization (2,332 ) (1,986 ) (1,929 ) Interest expense, net (1,365 ) (1,317 ) (1,291 ) Gains on acquisitions — 83 — Impairment losses (920 ) (813 ) (339 ) Losses on interest rate derivatives (37 ) (12 ) (18 ) Non-cash unit-based compensation expense (74 ) (80 ) (79 ) Unrealized gains (losses) on commodity risk management activities 56 (131 ) (65 ) Inventory valuation adjustments — — 58 Losses on extinguishments of debt (42 ) — (43 ) Adjusted EBITDA related to unconsolidated affiliates (984 ) (946 ) (937 ) Equity in earnings from unconsolidated affiliates 156 59 469 Impairment of investments in unconsolidated affiliates (313 ) (308 ) — Other, net 148 115 23 Income before income tax benefit $ 1,005 $ 397 $ 1,366 December 31, 2017 2016 2015 Assets: Intrastate transportation and storage $ 5,020 $ 5,176 $ 4,882 Interstate transportation and storage 13,518 10,833 11,345 Midstream 20,004 17,873 17,039 NGL and refined products transportation and services 17,600 14,074 11,568 Crude oil transportation and services 17,736 15,909 10,941 All other 4,087 6,240 9,353 Total assets $ 77,965 $ 70,105 $ 65,128 Years Ended December 31, 2017 2016 2015 Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis): Intrastate transportation and storage $ 175 $ 76 $ 105 Interstate transportation and storage 726 280 866 Midstream 1,308 1,255 2,174 NGL and refined products transportation and services 2,971 2,198 2,853 Crude oil transportation and services 453 1,841 1,358 All other 268 160 811 Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis) $ 5,901 $ 5,810 $ 8,167 December 31, 2017 2016 2015 Advances to and investments in unconsolidated affiliates: Intrastate transportation and storage $ 85 $ 399 $ 406 Interstate transportation and storage 2,118 2,149 2,516 Midstream 126 111 117 NGL and refined products transportation and services 234 235 258 Crude oil transportation and services 22 18 21 All other 1,231 1,368 1,685 Total advances to and investments in unconsolidated affiliates $ 3,816 $ 4,280 $ 5,003

Quarterly Financial Data (Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information [Table Text Block]	Quarters Ended March 31* June 30* September 30* December 31 Total Year 2017: Revenues $ 6,895 $ 6,576 $ 6,973 $ 8,610 $ 29,054 Operating income 683 736 779 199 2,397 Net income 393 296 715 1,097 2,501 Common Unitholders’ interest in net income (loss) 32 (49 ) 335 668 986 Basic net income (loss) per Common Unit $ 0.03 $ (0.04 ) $ 0.29 $ 0.57 $ 0.94 Diluted net income (loss) per Common Unit $ 0.03 $ (0.04 ) $ 0.29 $ 0.57 $ 0.93 Quarters Ended March 31* June 30* September 30* December 31* Total Year* 2016: Revenues $ 4,481 $ 5,289 $ 5,531 $ 6,526 $ 21,827 Operating income 598 708 594 (139 ) 1,761 Net income 360 465 94 (336 ) 583 Common Unitholders’ interest in net income (loss) (71 ) 58 (252 ) (754 ) (1,019 ) Basic net income (loss) per Common Unit $ (0.11 ) $ 0.06 $ (0.34 ) $ (0.97 ) $ (1.38 ) Diluted net income (loss) per Common Unit $ (0.11 ) $ 0.06 $ (0.34 ) $ (0.97 ) $ (1.38 ) * As adjusted. See Note 2. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.

Guarantor Financial Informati40

Guarantor Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Guarantor Financial Information [Abstract]
Condensed Balance Sheet [Table Text Block]	The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows: December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash and cash equivalents $ — $ (3 ) $ 309 $ — $ 306 All other current assets — 159 6,063 — 6,222 Property, plant and equipment — — 58,437 — 58,437 Investments in unconsolidated affiliates 48,378 11,648 3,816 (60,026 ) 3,816 All other assets — — 9,184 — 9,184 Total assets $ 48,378 $ 11,804 $ 77,809 $ (60,026 ) $ 77,965 Current liabilities (1,496 ) (3,660 ) 12,150 — 6,994 Non-current liabilities 21,604 7,607 7,609 — 36,820 Noncontrolling interest — — 5,882 — 5,882 Total partners’ capital 28,270 7,857 52,168 (60,026 ) 28,269 Total liabilities and equity $ 48,378 $ 11,804 $ 77,809 $ (60,026 ) $ 77,965 December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash and cash equivalents $ — $ 41 $ 319 $ — $ 360 All other current assets — 2 5,281 — 5,283 Property, plant and equipment — — 50,917 — 50,917 Investments in unconsolidated affiliates 23,350 10,664 4,280 (34,014 ) 4,280 All other assets — 5 9,260 — 9,265 Total assets $ 23,350 $ 10,712 $ 70,057 $ (34,014 ) $ 70,105 Current liabilities (1,761 ) (3,800 ) 11,764 — 6,203 Non-current liabilities 299 7,313 30,148 (299 ) 37,461 Noncontrolling interest — — 1,232 — 1,232 Total partners’ capital 24,812 7,199 26,913 (33,715 ) 25,209 Total liabilities and equity $ 23,350 $ 10,712 $ 70,057 $ (34,014 ) $ 70,105
Condensed Income Statement [Table Text Block]	Year Ended December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 29,054 $ — $ 29,054 Operating costs, expenses, and other — 1 26,656 — 26,657 Operating income (loss) — (1 ) 2,398 — 2,397 Interest expense, net — (156 ) (1,209 ) — (1,365 ) Equity in earnings of unconsolidated affiliates 2,564 1,242 156 (3,806 ) 156 Impairment of investments in unconsolidated affiliate — — (313 ) — (313 ) Losses on interest rate derivatives — — (37 ) — (37 ) Other, net — — 168 (1 ) 167 Income before income tax benefit 2,564 1,085 1,163 (3,807 ) 1,005 Income tax benefit — — (1,496 ) — (1,496 ) Net income 2,564 1,085 2,659 (3,807 ) 2,501 Less: Net income attributable to noncontrolling interest — — 420 — 420 Net income attributable to partners $ 2,564 $ 1,085 $ 2,239 $ (3,807 ) $ 2,081 Other comprehensive income (loss) $ — $ — $ (5 ) $ — $ (5 ) Comprehensive income 2,564 1,085 2,654 (3,807 ) 2,496 Comprehensive income attributable to noncontrolling interest — — 420 — 420 Comprehensive income attributable to partners $ 2,564 $ 1,085 $ 2,234 $ (3,807 ) $ 2,076 Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 21,827 $ — $ 21,827 Operating costs, expenses, and other — 1 20,065 — 20,066 Operating income (loss) — (1 ) 1,762 — 1,761 Interest expense, net — (157 ) (1,160 ) — (1,317 ) Equity in earnings of unconsolidated affiliates 554 863 59 (1,417 ) 59 Impairment of investment in unconsolidated affiliate — — (308 ) — (308 ) Losses on interest rate derivatives — — (12 ) — (12 ) Other, net — — 214 — 214 Income before income tax benefit 554 705 555 (1,417 ) 397 Income tax benefit — — (186 ) — (186 ) Net income 554 705 741 (1,417 ) 583 Less: Net income attributable to noncontrolling interest — — 41 — 41 Net income attributable to partners $ 554 $ 705 $ 700 $ (1,417 ) $ 542 Other comprehensive income $ — $ — $ 4 $ — $ 4 Comprehensive income 554 705 745 (1,417 ) 587 Comprehensive income attributable to noncontrolling interest — — 41 — 41 Comprehensive income attributable to partners $ 554 $ 705 $ 704 $ (1,417 ) $ 546 Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Revenues $ — $ — $ 34,292 $ — $ 34,292 Operating costs, expenses, and other — 1 32,064 — 32,065 Operating income (loss) — (1 ) 2,228 — 2,227 Interest expense, net — (133 ) (1,158 ) — (1,291 ) Equity in earnings of unconsolidated affiliates 1,441 526 469 (1,967 ) 469 Losses on interest rate derivatives — — (18 ) — (18 ) Other, net — — (21 ) — (21 ) Income before income tax benefit 1,441 392 1,500 (1,967 ) 1,366 Income tax benefit — — (123 ) — (123 ) Net income 1,441 392 1,623 (1,967 ) 1,489 Less: Net income attributable to noncontrolling interest — — 53 — 53 Net income attributable to partners $ 1,441 $ 392 $ 1,570 $ (1,967 ) $ 1,436 Other comprehensive income $ — $ — $ 60 $ — $ 60 Comprehensive income 1,441 392 1,683 (1,967 ) 1,549 Comprehensive income attributable to noncontrolling interest — — 53 — 53 Comprehensive income attributable to partners $ 1,441 $ 392 $ 1,630 $ (1,967 ) $ 1,496
Condensed Cash Flow Statement [Table Text Block]	Year Ended December 31, 2017 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash flows from operating activities $ 2,564 $ 1,047 $ 4,681 $ (3,807 ) $ 4,485 Cash flows from investing activities (2,240 ) (1,368 ) (5,672 ) 3,807 (5,473 ) Cash flows from financing activities (324 ) 277 981 — 934 Change in cash — (44 ) (10 ) — (54 ) Cash at beginning of period — 41 319 — 360 Cash at end of period $ — $ (3 ) $ 309 $ — $ 306 Year Ended December 31, 2016 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash flows from operating activities $ 553 $ 675 $ 3,492 $ (1,417 ) $ 3,303 Cash flows from investing activities (976 ) (2,400 ) (4,431 ) 1,417 (6,390 ) Cash flows from financing activities 423 1,729 768 — 2,920 Change in cash — 4 (171 ) — (167 ) Cash at beginning of period — 37 490 — 527 Cash at end of period $ — $ 41 $ 319 $ — $ 360 Year Ended December 31, 2015 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership Cash flows from operating activities $ 1,441 $ 388 $ 2,886 $ (1,968 ) $ 2,747 Cash flows from investing activities (2,271 ) (1,815 ) (5,702 ) 1,968 (7,820 ) Cash flows from financing activities 830 1,363 2,744 — 4,937 Change in cash — (64 ) (72 ) — (136 ) Cash at beginning of period — 101 562 — 663 Cash at end of period $ — $ 37 $ 490 $ — $ 527

Operations and Organization (Na

Operations and Organization (Narrative) (Details) $ in Millions	1 Months Ended				12 Months Ended
	Apr. 30, 2017	Oct. 31, 2015USD ($)	Jul. 31, 2015shares	Apr. 30, 2015USD ($)shares	Dec. 31, 2017USD ($)	Dec. 31, 2015USD ($)
Payments to Acquire Businesses, Gross | $		$ 382
SXL and ETP Merger [Member]
Conversion Rate of Units in Merger, Per Unit	1.5
Dropdown of Sunoco LLC Interest [Member]
Payments to Acquire Businesses, Gross | $				$ 775
Business Combination, Consideration Transferred | $				$ 816
Sunoco LP Exchange [Member]
Stock Repurchased During Period, Shares			31,500,000
Sunoco LP Exchange [Member] | Sunoco GP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Regency Merger [Member]
Business Acquisition, Number Of Share Received In Exchange Of Each Share				0.6186
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares				258,300,000
Relinquishment of Incentive Distributions | $					$ 60	$ 80
ETP Subsidiaries [Member] | Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares				23,300,000
ETP Series A Preferred Units [Member] | Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares				1,900,000

Estimates, Significant Accoun42

Estimates, Significant Accounting Policies and Balance Sheet Detials (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation	$ 165	$ 170
Deferred Tax Liabilities, Gross	3,426	4,802
Tangible Asset Impairment Charges	127	133	$ 110
ARO Underlying Asset	2	14
Asset Retirement Obligation, Legally Restricted Assets, Fair Value	21	13
Impairment of Intangible Assets, Finite-lived			24
Impairment losses	793	670
Goodwill, Written off Related to Sale of Business Unit		(1,289)
Long-term Debt, Fair Value	34,280	33,850
Goodwill acquired	12	428
Goodwill	3,115	3,897	5,428
Long-term Debt	33,094	32,930
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	$ 0
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives	3 years
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives	46 years
Maximum [Member] | Patents [Member]
Useful Lives	10 years
Interstate Transportation and Storage [Member]
Impairment losses	$ (262)	(638)	99
Goodwill, Written off Related to Sale of Business Unit		0
Goodwill acquired	0	0
Goodwill	12	274	912
Midstream [Member]
Tangible Asset Impairment Charges		10
Impairment losses	0	(32)
Goodwill, Written off Related to Sale of Business Unit		0
Goodwill acquired	8	177
Goodwill	870	863	718
Retail Marketing [Member]
Excise Taxes Collected		1,850
NGL and refined products transportation and services [Member]
Impairment losses	(79)	0	106
Goodwill, Written off Related to Sale of Business Unit		0
Goodwill acquired	0	0
Goodwill	693	772	772
Other Segments [Member]
Impairment losses	(452)	0
Goodwill, Written off Related to Sale of Business Unit		(1,289)
Goodwill acquired	0	0
Goodwill	$ 363	$ 815	$ 2,104

Estimates, Significant Accoun43

Estimates, Significant Accounting Policies and Balance Sheet Detials (Change in Accounting Policy) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Cost of products sold (see Note 3)									$ 20,801	$ 15,080	$ 26,714
Operating Income (Loss)	$ 199	$ 779	$ 736	$ 683	$ (139)	$ 594	$ 708	$ 598	2,397	1,761	2,227
INCOME BEFORE INCOME TAX BENEFIT									1,005	397	1,366
Net income	$ 1,097	$ 715	$ 296	$ 393	$ (336)	$ 94	$ 465	$ 360	2,501	583	1,489
Income tax benefit									(1,496)	(186)	(123)
Net Income (Loss) Attributable to Parent									$ 2,081	$ 288	$ 1,389
Basic	$ 0.57	$ 0.29	$ (0.04)	$ 0.03	$ (0.97)	$ (0.34)	$ 0.06	$ (0.11)	$ 0.94	$ (1.38)	$ (0.07)
Diluted	$ 0.57	$ 0.29	$ (0.04)	$ 0.03	$ (0.97)	$ (0.34)	$ 0.06	$ (0.11)	$ 0.93	$ (1.38)	$ (0.08)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest									$ 2,496	$ 587	$ 1,549
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									2,076	292	1,449
Increase (Decrease) in Deferred Income Taxes									(1,531)	(169)	202
Inventory Valuation Reserves									0	0	(58)
Increase (Decrease) in Operating Capital									160	246	1,173
Inventories	$ 1,589				$ 1,626				1,589	1,626	1,168
Deferred income taxes	2,883				4,394				2,883	4,394
Partners' Capital	$ 28,269				18,621				$ 28,269	18,621	20,824
Restatement Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Cost of products sold (see Note 3)										41	32
Operating Income (Loss)										(41)	(32)
INCOME BEFORE INCOME TAX BENEFIT										(41)	(32)
Net income										(41)	(32)
Net Income (Loss) Attributable to Parent										$ (9)	$ (9)
Basic										$ (0.01)	$ (0.01)
Diluted										$ (0.01)	$ (0.01)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest										$ (41)	$ (32)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent										(9)	(9)
Inventory Valuation Reserves										170	(162)
Increase (Decrease) in Operating Capital										(129)	194
Inventories					(86)					(86)	(45)
Partners' Capital					(21)					(21)	(12)
Scenario, Previously Reported [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Cost of products sold (see Note 3)										15,039	26,682
Operating Income (Loss)										1,802	2,259
INCOME BEFORE INCOME TAX BENEFIT										438	1,398
Net income										624	1,521
Net Income (Loss) Attributable to Parent										$ 297	$ 1,398
Basic										$ (1.37)	$ (0.06)
Diluted										$ (1.37)	$ (0.07)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest										$ 628	$ 1,581
Comprehensive Income (Loss), Net of Tax, Attributable to Parent										301	1,458
Inventory Valuation Reserves										(170)	104
Increase (Decrease) in Operating Capital										(117)	(1,367)
Inventories					1,712					1,712	1,213
Partners' Capital					$ 18,642					$ 18,642	$ 20,836

Estimates, Significant Accoun44

Estimates, Significant Accounting Policies and Balance Sheet Detials (Net change in operating assets and liabilities (net of acquisitions) included in cash flows) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Accounts receivable	$ (950)	$ (919)	$ 819
Accounts receivable from related companies	67	30	(243)
Inventories	37	(497)	(157)
Other current assets	39	83	(178)
Other non-current assets, net	(94)	(78)	188
Accounts payable	758	972	(1,215)
Accounts payable to related companies	(3)	29	(160)
Accrued and other current liabilities	(47)	39	(83)
Other non-current liabilities	24	33	(219)
Price risk management assets and liabilities, net	9	62	75
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$ (160)	$ (246)	$ (1,173)

Estimates, Significant Accoun45

Estimates, Significant Accounting Policies and Balance Sheet Detials (Non-cash investing and financing activities and supplemental cash flow information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	$ 1,059	$ 822	$ 896
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP	0	194	0
Net gains from subsidiary common unit transactions	0	37	300
Contribution of assets from noncontrolling interest	988	0	34
Issuance of Common Units in connection with acquisitions	0	543
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	0	0	1,946
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	1,329	1,411	1,467
Cash paid for (refund of) income taxes	50		71
Cash paid for (refund of) income taxes		(229)
PennTex Acquisition [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Issuance of Common Units in connection with acquisitions	0	307	0
Regency Merger [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Issuance of Common Units in connection with acquisitions	0	0	9,250
Bakken Pipeline Transaction [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Redemption of common units in connection with transactions	0	0	999
Sunoco LP Exchange [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Redemption of common units in connection with transactions	$ 0	$ 0	$ 52

Estimates, Significant Accoun46

Estimates, Significant Accounting Policies and Balance Sheet Detials (Inventory) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Natural gas, NGLs, and refined products	$ 733	$ 758
Crude oil	551	651
Spare parts and other	305	217
Total inventories	$ 1,589	$ 1,626	$ 1,168

Estimates, Significant Accoun47

Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Deposits paid to vendors	$ 64	$ 74
Prepaid expenses and other	146	224
Total other current assets	$ 210	$ 298

Estimates, Significant Accoun48

Estimates, Significant Accounting Policies and Balance Sheet Detials (Components and useful lives of property, plant and equipment) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment, Gross	$ 67,699	$ 58,220
Less - Accumulated depreciation	(9,262)	(7,303)
Property, plant and equipment, net	58,437	50,917
Land and improvements
Property, Plant and Equipment, Gross	1,706	676
Buildings and improvements (1 to 45 years)
Property, Plant and Equipment, Gross	1,960	1,617
Pipelines and equipment (5 to 83 years)
Property, Plant and Equipment, Gross	44,050	36,356
Natural gas and NGL storage facilities (5 to 46 years)
Property, Plant and Equipment, Gross	1,681	1,452
Bulk storage, equipment and facilities (2 to 83 years)
Property, Plant and Equipment, Gross	3,036	3,701
Vehicles (1 to 25 years)
Property, Plant and Equipment, Gross	124	217
Right of way (20 to 83 years)
Property, Plant and Equipment, Gross	3,424	3,349
Natural resources
Property, Plant and Equipment, Gross	434	434
Other (1 to 40 years)
Property, Plant and Equipment, Gross	534	484
Construction Work-In-Process [Member]
Property, Plant and Equipment, Gross	$ 10,750	$ 9,934
Minimum [Member] | Buildings and improvements (1 to 45 years)
Property, plant and equipment useful life, minimum in years	1 year
Minimum [Member] | Pipelines and equipment (5 to 83 years)
Property, plant and equipment useful life, minimum in years	5 years
Minimum [Member] | Natural gas and NGL storage facilities (5 to 46 years)
Property, plant and equipment useful life, minimum in years	5 years
Minimum [Member] | Bulk storage, equipment and facilities (2 to 83 years)
Property, plant and equipment useful life, minimum in years	2 years
Minimum [Member] | Retail equipment (2 to 99 years)
Property, plant and equipment useful life, minimum in years	2 years
Minimum [Member] | Vehicles (1 to 25 years)
Property, plant and equipment useful life, minimum in years	1 year
Minimum [Member] | Right of way (20 to 83 years)
Property, plant and equipment useful life, minimum in years	20 years
Minimum [Member] | Other (1 to 40 years)
Property, plant and equipment useful life, minimum in years	1 year
Maximum [Member] | Buildings and improvements (1 to 45 years)
Property, plant and equipment useful life, minimum in years	45 years
Maximum [Member] | Pipelines and equipment (5 to 83 years)
Property, plant and equipment useful life, minimum in years	83 years
Maximum [Member] | Natural gas and NGL storage facilities (5 to 46 years)
Property, plant and equipment useful life, minimum in years	46 years
Maximum [Member] | Bulk storage, equipment and facilities (2 to 83 years)
Property, plant and equipment useful life, minimum in years	83 years
Maximum [Member] | Retail equipment (2 to 99 years)
Property, plant and equipment useful life, minimum in years	99 years
Maximum [Member] | Vehicles (1 to 25 years)
Property, plant and equipment useful life, minimum in years	25 years
Maximum [Member] | Right of way (20 to 83 years)
Property, plant and equipment useful life, minimum in years	83 years
Maximum [Member] | Other (1 to 40 years)
Property, plant and equipment useful life, minimum in years	40 years

Estimates, Significant Accoun49

Estimates, Significant Accounting Policies and Balance Sheet Detials (Schedule of Property, Plant and Equipment Depreciation and Capitalized Interest Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Depreciation and depletion expense	$ 2,060	$ 1,793	$ 1,713
Capitalized interest	$ 283	$ 199	$ 163

Estimates, Significant Accoun50

Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Non-Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Regulatory assets	$ 85	$ 86
Deferred charges	210	217
Restricted funds	192	190
Long-term affiliated receivable	85	90
Other	186	89
Total other non-current assets, net	$ 758	$ 672

Estimates, Significant Accoun51

Estimates, Significant Accounting Policies and Balance Sheet Detials (Intangible assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Gross Carrying Amount	$ 6,365	$ 5,478
Accumulated Amortization	(1,054)	(782)
Customer relationships, contracts and agreements (3 to 46 years)
Gross Carrying Amount	6,250	5,362
Accumulated Amortization	(1,003)	(737)
Patents (10 years)
Gross Carrying Amount	48	48
Accumulated Amortization	(26)	(21)
Trade Names (20 years)
Gross Carrying Amount	66	66
Accumulated Amortization	(25)	(22)
Other (5 to 20 years)
Gross Carrying Amount	1	2
Accumulated Amortization	$ 0	$ (2)
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives	46 years
Maximum [Member] | Patents (10 years)
Useful Lives	10 years
Maximum [Member] | Trade Names (20 years)
Useful Lives	20 years
Maximum [Member] | Other (5 to 20 years)
Useful Lives	15 years
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives	3 years
Minimum [Member] | Other (5 to 20 years)
Useful Lives	1 year

Estimates, Significant Accoun52

Estimates, Significant Accounting Policies and Balance Sheet Detials (Amortization expense of intangible assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Depreciation And Amortization [Member]
Reported in depreciation, depletion and amortization	$ 272	$ 193	$ 216

Estimates, Significant Accoun53

Estimates, Significant Accounting Policies and Balance Sheet Detials (Estimated aggregate amortization expense) (Details) $ in Millions	Dec. 31, 2017USD ($)
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
2,018	$ 280
2,019	278
2,020	278
2,021	268
2,022	$ 256

Estimates, Significant Accoun54

Estimates, Significant Accounting Policies and Balance Sheet Detials (Changes in the carrying amount of goodwill) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill, Beginning Balance	$ 3,897	$ 5,428
Goodwill acquired	12	428
Impairment losses	(793)	(670)
Goodwill, Written off Related to Sale of Business Unit		(1,289)
Other	(1)
Goodwill, Ending Balance	3,115	3,897	$ 5,428
Intrastate Transportation And Storage [Member]
Goodwill, Beginning Balance	10	10
Goodwill acquired	0	0
Impairment losses	0	0
Goodwill, Written off Related to Sale of Business Unit		0
Other	0
Goodwill, Ending Balance	10	10	10
Interstate Transportation and Storage [Member]
Goodwill, Beginning Balance	274	912
Goodwill acquired	0	0
Impairment losses	262	638	(99)
Goodwill, Written off Related to Sale of Business Unit		0
Other	0
Goodwill, Ending Balance	12	274	912
Midstream [Member]
Goodwill, Beginning Balance	863	718
Goodwill acquired	8	177
Impairment losses	0	32
Goodwill, Written off Related to Sale of Business Unit		0
Other	(1)
Goodwill, Ending Balance	870	863	718
Other Segments [Member]
Goodwill, Beginning Balance	815	2,104
Goodwill acquired	0	0
Impairment losses	452	0
Goodwill, Written off Related to Sale of Business Unit		(1,289)
Other	0
Goodwill, Ending Balance	363	815	2,104
NGL and refined products transportation and services [Member]
Goodwill, Beginning Balance	772	772
Goodwill acquired	0	0
Impairment losses	79	0	(106)
Goodwill, Written off Related to Sale of Business Unit		0
Other	0
Goodwill, Ending Balance	693	772	772
Crude oil transportation and services [Member]
Goodwill, Beginning Balance	1,163	912
Goodwill acquired	4	251
Impairment losses	0	0
Goodwill, Written off Related to Sale of Business Unit		0
Other	0
Goodwill, Ending Balance	$ 1,167	$ 1,163	$ 912

Estimates, Significant Accoun55

Estimates, Significant Accounting Policies and Balance Sheet Detials (Accrued and Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Information [Abstract]
Interest payable	$ 443	$ 440
Customer advances and deposits	59	56
Accrued capital expenditures	1,006	749
Accrued wages and benefits	208	212
Taxes payable other than income taxes	108	63
Exchanges payable	154	208
Other	165	177
Total accrued and other current liabilities	$ 2,143	$ 1,905

Estimates, Significant Accoun56

Estimates, Significant Accounting Policies and Balance Sheet Detials (Assets and liabilities measured and recorded at fair value on a recurring basis) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Assets, Fair Value Disclosure		$ 0
Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	$ 320	362
Other Assets, Fair Value Disclosure	21	13
Assets, Fair Value Disclosure, Recurring	341	375
Interest rate derivatives, Liabilities	(219)	(193)
Embedded derivatives in the ETP Preferred Units		(1)
Price Risk Derivative Liabilities, at Fair Value	(338)	(472)
Liabilities, Fair Value Disclosure, Recurring	(557)	(666)
Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	193	233
Price Risk Derivative Liabilities, at Fair Value	(192)	(273)
Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	23	4
Price Risk Derivative Liabilities, at Fair Value	(22)	(5)
Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value	(25)	(17)
Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(1)
Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	2	9
Price Risk Derivative Liabilities, at Fair Value	(1)	(13)
Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	8	1
Price Risk Derivative Liabilities, at Fair Value	(2)
Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	11	14
Price Risk Derivative Liabilities, at Fair Value	(24)	(11)
Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	13	2
Price Risk Derivative Liabilities, at Fair Value	(15)	(3)
Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	70	96
Price Risk Derivative Liabilities, at Fair Value	(57)	(149)
Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	276	355
Other Assets, Fair Value Disclosure	14	8
Assets, Fair Value Disclosure, Recurring	290	363
Interest rate derivatives, Liabilities	0	0
Embedded derivatives in the ETP Preferred Units		0
Price Risk Derivative Liabilities, at Fair Value	(300)	(464)
Liabilities, Fair Value Disclosure, Recurring	(300)	(464)
Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	193	233
Price Risk Derivative Liabilities, at Fair Value	(192)	(273)
Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value	(25)	(17)
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(1)
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	2	9
Price Risk Derivative Liabilities, at Fair Value	(1)	(13)
Fair Value, Inputs, Level 1 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0
Fair Value, Inputs, Level 1 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	11	14
Price Risk Derivative Liabilities, at Fair Value	(24)	(11)
Fair Value, Inputs, Level 1 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	(1)	0
Fair Value, Inputs, Level 1 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	70	96
Price Risk Derivative Liabilities, at Fair Value	(57)	(149)
Fair Value, Inputs, Level 1 [Member] | Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	44	7
Other Assets, Fair Value Disclosure	7	5
Assets, Fair Value Disclosure, Recurring	51	12
Interest rate derivatives, Liabilities	(219)	(193)
Embedded derivatives in the ETP Preferred Units		0
Price Risk Derivative Liabilities, at Fair Value	(38)	(8)
Liabilities, Fair Value Disclosure, Recurring	(257)	(201)
Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	23	4
Price Risk Derivative Liabilities, at Fair Value	(22)	(5)
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	8	1
Price Risk Derivative Liabilities, at Fair Value	(2)
Fair Value, Inputs, Level 2 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	13	2
Price Risk Derivative Liabilities, at Fair Value	(14)	(3)
Fair Value, Inputs, Level 2 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	$ 0	0
Fair Value, Inputs, Level 2 [Member] | Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Assets, Fair Value Disclosure, Recurring		0
Interest rate derivatives, Liabilities		0
Embedded derivatives in the ETP Preferred Units		(1)
Price Risk Derivative Liabilities, at Fair Value		0
Liabilities, Fair Value Disclosure, Recurring		(1)
Fair Value, Inputs, Level 3 [Member] | Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Inputs, Level 3 [Member] | Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Inputs, Level 3 [Member] | Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Inputs, Level 3 [Member] | Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Inputs, Level 3 [Member] | Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Inputs, Level 3 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Fair Value, Inputs, Level 3 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Inputs, Level 3 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Inputs, Level 3 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Inputs, Level 3 [Member] | Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		$ 0

Estimates, Significant Accoun57

Estimates, Significant Accounting Policies and Balance Sheet Detials (Unobservable Inputs and Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Amount of Gain (Loss) Recognized In Income On Derivatives	$ (2)	$ (216)	$ 6
Fair Value, Measurements, Recurring [Member]
Liabilities, Fair Value Disclosure, Recurring	(557)	(666)
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Liabilities, Fair Value Disclosure, Recurring		(1)
Embedded Derivatives in Preferred Units [Member] | Other Income (Expenses) [Member]
Amount of Gain (Loss) Recognized In Income On Derivatives	$ 1	$ 4	$ 12

Estimates, Significant Accoun58

Estimates, Significant Accounting Policies and Balance Sheet Detials (Costs and expenses) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Retail Marketing [Member]
Excise Taxes Collected	$ 1,850

Acquisitions, Divestitures an59

Acquisitions, Divestitures and Related Transactions (2018 Transactions) (Details) - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2018	Oct. 31, 2015
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 382
Subsequent Event [Member] | CDM Contribution [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 1,700
Payments to Acquire Businesses, Gross	$ 1,225
USA Compression Partners, LP [Member] | Subsequent Event [Member] | CDM Contribution [Member]
Business Acquisition [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	19,191,351
Equity Issued in Business Combination, Fair Value Disclosure	$ 335
USA Compression Partners, LP [Member] | Subsequent Event [Member] | CDM Contribution [Member] | Class B Units [Member]
Business Acquisition [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	6,397,965
Equity Issued in Business Combination, Fair Value Disclosure	$ 112
ETE | USA Compression Partners, LP [Member] | Subsequent Event [Member] | CDM Contribution [Member]
Business Acquisition [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	12,466,912
Equity Issued in Business Combination, Fair Value Disclosure	$ 250

Acquisitions, Divestitures an60

Acquisitions, Divestitures and Related Transactions (2017 Transactions) (Details) $ in Millions	1 Months Ended			9 Months Ended	12 Months Ended
	Oct. 31, 2017	Jul. 31, 2017	Apr. 30, 2017	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Capital contributions from noncontrolling interest					$ 2,202	$ 236	$ 875
Intangible assets, net					5,311	4,696
Property, plant and equipment					$ 67,699	$ 58,220
SXL and ETP Merger [Member]
Business Acquisition [Line Items]
Conversion Rate of Units in Merger, Per Unit			1.5
ETP [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.10%
ETP [Member] | Holdco [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		49.90%
Holdco [Member] | Rover Pipeline LLC [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		65.00%
Blackstone [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	49.90%
Permian Express Partners LLC [Member] | Sunoco Logistics [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		88.00%
Capital contributions from noncontrolling interest				$ 988
Intangible assets, net				547
Property, plant and equipment				$ 435
Dakota Access, LLC [Member] | Energy Transfer Crude Oil Company, LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		15.00%

Acquisitions, Divestitures an61

Acquisitions, Divestitures and Related Transactions (2016 Transactions) (Details) shares in Millions, barrels in Millions	1 Months Ended
	Feb. 28, 2017	Nov. 30, 2016USD ($)barrels	Apr. 30, 2016	Mar. 31, 2016USD ($)shares	Oct. 31, 2015USD ($)	Dec. 31, 2017USD ($)	Feb. 01, 2017	Dec. 31, 2016USD ($)	Nov. 01, 2016USD ($)	Aug. 01, 2016USD ($)	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Property, Plant and Equipment, Net						$ 58,437,000,000		$ 50,917,000,000
Payments to Acquire Businesses, Gross					$ 382,000,000
Goodwill						3,115,000,000		3,897,000,000			$ 5,428,000,000
Intangible assets, net						5,311,000,000		4,696,000,000
PennTex Acquisition [Member]
Business Acquisition [Line Items]
Business Acquisition, Goodwill, Expected Tax Deductible Amount									$ 0
Total consideration, net of cash received									$ 606,000,000
Business Combination, Consideration Transferred		$ 627,000,000
Vitol Acquisition [Member]
Business Acquisition [Line Items]
Total consideration, net of cash received		769,000,000
Net Working Capital		13,000,000
Property, Plant and Equipment, Net		286,000,000
Business Combination, Consideration Transferred		760,000,000
Goodwill		251,000,000
Intangible assets, net		$ 313,000,000
Crude Oil Terminal, Capacity, Bbls | barrels		2
Sunoco Retail to Sunoco LP [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred				$ 2,230,000,000
Payments to Acquire Businesses, Gross				$ 2,200,000,000
Sale of Stock, Number of Shares Issued in Transaction | shares				5.7
SunVit Pipeline LLC [Member] | Vitol Acquisition [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		50.00%
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Bakken Holdings Company LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					40.00%
Legacy Sunoco, Inc. [Member]
Business Acquisition [Line Items]
Goodwill						1,290,000,000
Intangible assets, net						294,000,000
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Pipeline [Member]
Business Acquisition [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity										$ 2,500,000,000
Bayou Bridge Pipeline LLC [Member] | ETP and Sunoco Logistics [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			30.00%
Dakota Access and ETCO [Member] | Phillips 66 Company [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	25.00%
Dakota Access and ETCO [Member] | Bakken Pipeline Investments LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	75.00%
ETP [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
Sunoco Logistics [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	49.00%
Bakken Pipeline Investments LLC [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired							200000000000.00%
Sunoco, LLC [Member] | ETP [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				68.42%
Legacy Sunoco, Inc. [Member] | ETP [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				100.00%
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]
Business Acquisition [Line Items]
Revolving credit facilities						$ 2,500,000,000		$ 1,100,000,000

Acquisitions, Divestitures an62

Acquisitions, Divestitures and Related Transactions (2015 Transactions) (Details) $ in Millions, gallons in Billions

1 Months Ended

3 Months Ended

12 Months Ended

Feb. 28, 2018shares

Feb. 28, 2017

Oct. 31, 2015USD ($)shares

Jul. 31, 2015USD ($)shares

Apr. 30, 2015USD ($)gallonsshares

Mar. 31, 2015USD ($)shares

Mar. 31, 2015USD ($)shares

Dec. 31, 2020USD ($)

Dec. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)shares

Dec. 31, 2016USD ($)shares

Dec. 31, 2015USD ($)shares

Feb. 07, 2018

Sep. 30, 2015shares

Jun. 30, 2015USD ($)

Dec. 31, 2014shares

[1]

Business Acquisition [Line Items]

Payments to Acquire Businesses, Gross | $

$ 382

Partners' Capital Account, Units, Redeemed | shares

0

26,700,000

[1]

77,800,000

[1]

Goodwill | $

$ 3,115

$ 3,897

$ 5,428

Intangible assets, net | $

$ 5,311

$ 4,696

Partners' Capital Account, Units | shares

1,164,100,000

794,800,000

[1]

758,500,000

[1]

533,400,000

Class H Units

Business Acquisition [Line Items]

Partners' Capital Account, Units | shares

50,200,000

50,200,000

Allocation of Profits, Losses and Other by Sunoco, Percent

90.05%

Class B Units [Member]

Business Acquisition [Line Items]

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares

9,400,000

Regency Merger [Member]

Business Acquisition [Line Items]

Business Acquisition, Number Of Share Received In Exchange Of Each Share | shares

0.6186

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares

258,300,000

Relinquishment of Incentive Distributions | $

$ 60

$ 80

Dropdown of Sunoco LLC Interest [Member]

Business Acquisition [Line Items]

Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage

31.58%

Business Combination, Consideration Transferred | $

$ 816

Gallons of motor fuel distributed | gallons

5.3

Payments to Acquire Businesses, Gross | $

$ 775

Equity Issued in Business Combination, Fair Value Disclosure | $

$ 41

Dropdown of Susser [Member]

Business Acquisition [Line Items]

Payments to Acquire Businesses, Gross | $

$ 970

Business Combination, Consideration Transferred, Equity Interests Issued and Issuable | $

$ 970

Sunoco LP Exchange [Member]

Business Acquisition [Line Items]

Stock Repurchased During Period, Shares | shares

31,500,000

IDR Subsidies | $

$ 35

Term of IDR Subsidy

10 years

Bakken Pipeline Transaction [Member]

Business Acquisition [Line Items]

Business Combination, Consideration Transferred | $

$ 879

Partners' Capital Account, Units, Redeemed | shares

46,200,000

Class I Distributions | $

$ 55

$ 30

Bakken Pipeline Transaction [Member] | Class H Units

Business Acquisition [Line Items]

Partners' Capital Account, Units, Redeemed | shares

30,800,000

Allocation of Profits, Losses and Other by Sunoco, Percent

90.05%

90.05%

Bakken Pipeline Transaction [Member] | Class I Units

Business Acquisition [Line Items]

Partners' Capital Account, Units | shares

100

100

Parent Company [Member] | Bakken Pipeline Transaction [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

45.00%

Susser [Member] | Dropdown of Susser [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

100.00%

Sunoco LP [Member]

Business Acquisition [Line Items]

Goodwill | $

$ 1,810

Intangible assets, net | $

$ 982

Investments in and Advances to Affiliates, Balance, Shares | shares

43,500,000

Equity Method Investment, Ownership Percentage

43.60%

Sunoco LP [Member] | Dropdown of Susser [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction | shares

22,000,000

Sunoco LP [Member] | Dropdown of Susser [Member] | Class A Units [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction | shares

79,308

Legacy Sunoco, Inc. [Member]

Business Acquisition [Line Items]

Goodwill | $

$ 1,290

Intangible assets, net | $

$ 294

Sunoco GP [Member] | Sunoco LP Exchange [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

100.00%

Bakken Holdings Company LLC [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

40.00%

Dakota Access and ETCO [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

75.00%

ETP [Member] | Sunoco LP [Member] | Dropdown of Susser [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction | shares

10,900,000

ETP [Member] | Bakken Holdings Company LLC [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

100.00%

ETP Subsidiaries [Member] | Regency Merger [Member]

Business Acquisition [Line Items]

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares

23,300,000

ETP Series A Preferred Units [Member] | Regency Merger [Member]

Business Acquisition [Line Items]

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares

1,900,000

Common Units | Sunoco LP [Member]

Business Acquisition [Line Items]

Investment Owned, Balance, Shares | shares

37,800,000

Subsequent Event [Member]

Business Acquisition [Line Items]

Relinquishment of Incentive Distributions | $

$ 33

$ 128

$ 153

Subsequent Event [Member] | Regency Merger [Member]

Business Acquisition [Line Items]

Relinquishment of Incentive Distributions | $

$ 320

Subsequent Event [Member] | Sunoco LP [Member]

Business Acquisition [Line Items]

Stock Repurchased During Period, Shares | shares

17,286,859

Equity Method Investment, Ownership Percentage

31.80%

[1]

The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.

Acquisitions, Divestitures an63

Acquisitions, Divestitures and Related Transactions (Summary of Preliminary Assets And LiabilityAcquired) (Details) - PennTex Acquisition [Member] $ in Millions	Nov. 01, 2016USD ($)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	$ 393
Business Acquisition, Purchase Price Allocation, Goodwill Expected to be Not Tax Deductible, Amount	177	[1]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill	446
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	1,050
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	6
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	164
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	17
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value	236
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	423
Business Combination, Cost of Acquired Entity, Purchase Price	627
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents	21
Total consideration, net of cash received	606
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets	$ 34
[1]	None of the goodwill is expected to be deductible for tax purposes.

Acquisitions, Divestitures an64

Acquisitions, Divestitures and Related Transactions Selected Financial Data (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues	$ 8,610	$ 6,973	$ 6,576	$ 6,895	$ 6,526	$ 5,531	$ 5,289	$ 4,481	$ 29,054	$ 21,827	$ 34,292
Cost of products sold (see Note 3)									20,801	15,080	26,714
Operating expenses (see Note 3)									2,170	1,839	2,608
Selling, general and administrative (see Note 3)									$ 434	348	$ 475
Sunoco LP and Legacy Sunoco Inc. [Member]
Revenues										12,482
Cost of products sold (see Note 3)										11,174
Operating expenses (see Note 3)										798
Selling, general and administrative (see Note 3)										$ 106

Advances to and Investments i65

Advances to and Investments in Unconsolidated Affiliates (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended			12 Months Ended
	Feb. 28, 2018	Oct. 31, 2015	Jul. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 07, 2018	Jun. 30, 2015
Schedule of Investments [Line Items]
Impairment of investments in unconsolidated affiliates				$ 313	$ 308	$ 0
Impairment losses				920	813	339
Payments to Acquire Businesses, Gross		$ 382
Advances to and investments in unconsolidated affiliates				3,816	4,280	5,003
Goodwill				3,115	3,897	5,428
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP				$ 0	194	$ 0
FGT
Schedule of Investments [Line Items]
Percentage Ownership Operating Facility				100.00%
Citrus [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Business Acquisition, Percentage of Voting Interests Acquired				50.00%
FEP [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Impairment of investments in unconsolidated affiliates				$ 141
MEP [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
RIGS Haynesville Partnership Co. [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				49.99%
Impairment of investments in unconsolidated affiliates				$ (172)
Impairment losses				$ 185
Sunoco LP [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				43.60%
Impairment losses				$ 176	$ 277
Goodwill								$ 1,810
Investments in and Advances to Affiliates, Balance, Shares				43,500,000
Sunoco LP Exchange [Member]
Schedule of Investments [Line Items]
Stock Repurchased During Period, Shares			31,500,000
Sunoco LP Exchange [Member] | Sunoco GP [Member]
Schedule of Investments [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Subsequent Event [Member] | Sunoco LP [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage							31.80%
Stock Repurchased During Period, Shares	17,286,859
Payments for Repurchase of Common Stock	$ 540

Advances to and Investments i66

Advances to and Investments in Unconsolidated Affiliates (Investments in Unconsolidated Affiliates) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Equity in earnings from unconsolidated affiliates	$ 156	$ 59	$ 469
Advances to and investments in unconsolidated affiliates	3,816	4,280	5,003
Citrus [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings from unconsolidated affiliates	144	102	97
Advances to and investments in unconsolidated affiliates	1,754	1,729
FEP [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings from unconsolidated affiliates	53	51	55
Advances to and investments in unconsolidated affiliates	121	101
MEP [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings from unconsolidated affiliates	38	40	45
Advances to and investments in unconsolidated affiliates	242	318
RIGS Haynesville Partnership Co. [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings from unconsolidated affiliates	(168)	31	32
Advances to and investments in unconsolidated affiliates	28	382
Sunoco, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings from unconsolidated affiliates	0	0	(10)
Sunoco LP [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings from unconsolidated affiliates	12	(211)	202
Advances to and investments in unconsolidated affiliates	1,095	1,225
Other Affiliates [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings from unconsolidated affiliates	77	46	$ 48
Advances to and investments in unconsolidated affiliates	$ 576	$ 525

Advances to and Investments i67

Advances to and Investments in Unconsolidated Affiliates (Summarized Financial Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Investments in and Advances to Affiliates [Line Items]
Revenue	$ 13,081	$ 11,150	$ 13,815
Operating income	636	859	1,052
Net income (loss)	294	(22)	$ 664
Current assets	4,750	1,532
Property, plant and equipment, net	9,893	10,310
Other assets	2,286	5,980
Total assets	16,929	17,822
Current liabilities	2,075	1,918
Non-current liabilities	9,375	10,343
Equity	5,479	5,561
Total liabilities and equity	$ 16,929	$ 17,822

Net Income Per Limited Partne68

Net Income Per Limited Partner Unit (A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net income	$ 1,097	$ 715	$ 296	$ 393	$ (336)	$ 94	$ 465	$ 360	$ 2,501	$ 583	$ 1,489
Less: Income attributable to noncontrolling interest									420	295	134
Less: Net loss attributable to predecessor									0	0	(34)
Net income, net of noncontrolling interest									2,081	288	1,389
General Partner’s interest in net income									(990)	(948)	(1,064)
Preferred Unitholders’ interest in net income									12	0	0
Class H Unitholder’s interest in net income									(93)	(351)	(258)
Class I Unitholder’s interest in net income									0	(8)	(94)
Common Unitholders’ interest in net income (loss)									986	(1,019)	(27)
Additional earnings allocated from (to) General Partner									9	(10)	(5)
Distributions on employee unit awards, net of allocation to General Partner									27	19	16
Net income (loss) available to Common Unitholders									968	(1,048)	(48)
Loss attributable to Legacy ETP Preferred Units									0	0	(6)
Net Income (Loss) Available to Common Stockholders, Diluted									$ 968	$ (1,048)	$ (54)
Weighted average Common Units – basic									1,032.7	758.2	649.2
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements									5.1	0	0
Basic net income (loss) per Common Unit									$ 0.94	$ (1.38)	$ (0.07)
Dilutive effect of Legacy ETP Preferred Units									0	0	1
Weighted average Common Units – diluted									1,037.8	758.2	650.2
Diluted income (loss) per Common Unit									$ 0.93	$ (1.38)	$ (0.08)

Net Income Per Limited Partne69

Net Income Per Limited Partner Unit (Narrative) (Details)	1 Months Ended
	Apr. 30, 2017
SXL and ETP Merger [Member]
Conversion Rate of Units in Merger, Per Unit	1.5

Debt Obligations (Narrative) (D

Debt Obligations (Narrative) (Details) $ in Millions		12 Months Ended
		Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Unamortized Discounts, Premiums, Fair Value Adjustments and Deferred Debt Issuance Costs		$ (118)
Long-term Debt		33,094	$ 32,930
Proceeds from borrowings		26,736	19,916	$ 22,462
Repayments of Long-term Debt		$ 26,494	15,799	$ 17,843
Supplementary Leverage Ratio		396.00%
ETP [Member]
Long-term Debt		$ 29,210	29,454
Senior note interest rate		6.50%
Senior note maturity date		May 15, 2021
Leverage Ratio Maximum		5
Maximum Leverage Ratio Permitted		5.5
Panhandle [Member]
Long-term Debt		$ 813	1,135
Junior Subordinated Notes, Noncurrent		54
Bakken Project [Member]
Long-term Debt		$ 2,492	1,087
Bakken Project $2.50 billion Credit Facility due August 2019 [Member]
Minimum debt service coverage ratio		1.20
2.50% Senior Notes due June 15, 2018 (1) | ETP [Member]
Senior note principal amount	[1]	$ 650	650
Senior note interest rate		2.50%
Senior note maturity date		Jun. 15, 2018
6.70% Senior Notes due July 1, 2018 (1) | ETP [Member]
Senior note principal amount	[1]	$ 600	600
Senior note interest rate		6.70%
Senior note maturity date		Jul. 1, 2018
5.75% Senior Notes due January 15, 2017 | Sunoco [Member]
Senior note principal amount		$ 0	400
Senior note interest rate		5.75%
Senior note maturity date		Jan. 15, 2017
4.40% Senior Notes due April 1, 2021 | ETP [Member]
Senior note interest rate		4.40%
Senior note maturity date		Apr. 1, 2021
5.30% Senior Notes due April 1, 2044 | ETP [Member]
Senior note interest rate		5.30%
Senior note maturity date		Apr. 1, 2044
3.45% Senior Notes due January 15, 2023 | ETP [Member]
Senior note interest rate		3.45%
Senior note maturity date		Jan. 15, 2023
4.95% Senior Notes due January 15, 2043 | ETP [Member]
Senior note interest rate		4.95%
Senior note maturity date		Jan. 15, 2043
3.60% Senior Notes due February 1, 2023 | ETP [Member]
Senior note principal amount		$ 800	800
Senior note interest rate		3.60%
Senior note maturity date		Feb. 1, 2023
5.15% Senior Notes due February 1, 2043 | ETP [Member]
Senior note principal amount		$ 450	450
Senior note interest rate		5.15%
Senior note maturity date		Feb. 1, 2043
5.35% Senior Notes due May 15, 2045 | ETP [Member]
Senior note interest rate		5.35%
Senior note maturity date		May 15, 2045
5.95% Senior Notes due December 1, 2025 | ETP [Member]
Senior note interest rate		5.95%
Senior note maturity date		Dec. 1, 2025
ETLP $3.75 billion Revolving Credit Facility due November 2019 | ETP [Member]
Revolving credit facility balance outstanding		$ 0	2,777
Line of Credit Facility, Current Borrowing Capacity		$ 3,750
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETP [Member]
Senior note maturity date		Nov. 1, 2066
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member]
Debt Instrument, Interest Rate Terms		variable rate based upon the three-month LIBOR rate plus 3.0175%
Senior note maturity date		Nov. 1, 2066
Debt Instrument, Interest Rate, Effective Percentage		4.39%
ETP Credit Facility due December 2022 [Member] | ETP [Member]
Revolving credit facility balance outstanding		$ 2,292	0
Long-term Commercial Paper, Noncurrent		$ 2,010
Weighted average interest rate on the total amount outstanding		2.48%
Line of Credit Facility, Current Borrowing Capacity		$ 1,560
Letters of Credit Outstanding, Amount		150
Line of Credit Facility, Maximum Borrowing Capacity		$ 4,000
3.90% Senior Notes due July 15, 2026 | ETP [Member]
Senior note interest rate		3.90%
Senior note maturity date		Jul. 15, 2026
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | Sunoco Logistics [Member]
Line of Credit Facility, Current Borrowing Capacity		$ 2,500
Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETP [Member]
Revolving credit facility balance outstanding	[2]	$ 50	0
Weighted average interest rate on the total amount outstanding		5.00%
Line of Credit Facility, Current Borrowing Capacity		$ 950
Line of Credit Facility, Maximum Borrowing Capacity		1,000
Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | Sunoco Logistics [Member]
Line of Credit Facility, Current Borrowing Capacity		1,000
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]
Revolving credit facility balance outstanding		$ 2,500	1,100
Weighted average interest rate on the total amount outstanding		3.00%
Line of Credit Facility, Current Borrowing Capacity		$ 2,500
PennTex $275 million Revolving Credit Facility due December 2019 | PennTex [Member]
Revolving credit facility balance outstanding		0	$ 168
Line of Credit Facility, Current Borrowing Capacity		$ 275
Maximum [Member] | ETP Credit Facility due December 2022 [Member] | ETP [Member]
Line of Credit Facility, Commitment Fee Percentage		0.30%
Maximum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETP [Member]
Line of Credit Facility, Commitment Fee Percentage		0.225%
Minimum [Member] | ETP Credit Facility due December 2022 [Member] | ETP [Member]
Line of Credit Facility, Commitment Fee Percentage		0.125%
Minimum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETP [Member]
Line of Credit Facility, Commitment Fee Percentage		0.125%
Accordion feature [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETP [Member]
Revolving credit facility balance outstanding	[2]	$ 6,000
Eurodollar [Member] | Maximum [Member]
Debt Instrument, Basis Spread on Variable Rate		2.00%
Eurodollar [Member] | Maximum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETP [Member]
Debt Instrument, Basis Spread on Variable Rate		1.75%
Eurodollar [Member] | Minimum [Member] | ETP Credit Facility due December 2022 [Member] | ETP [Member]
Debt Instrument, Basis Spread on Variable Rate		1.125%
Eurodollar [Member] | Minimum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETP [Member]
Debt Instrument, Basis Spread on Variable Rate		1.125%
Base Rate Loans [Member] | Maximum [Member] | ETP Credit Facility due December 2022 [Member] | ETP [Member]
Debt Instrument, Basis Spread on Variable Rate		1.00%
Base Rate Loans [Member] | Maximum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETP [Member]
Debt Instrument, Basis Spread on Variable Rate		0.75%
Base Rate Loans [Member] | Minimum [Member] | ETP Credit Facility due December 2022 [Member] | ETP [Member]
Debt Instrument, Basis Spread on Variable Rate		0.125%
Base Rate Loans [Member] | Minimum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETP [Member]
Debt Instrument, Basis Spread on Variable Rate		0.25%
[1]	As of December 31, 2017 management had the intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current.
[2]	Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.

Debt Obligations (Debt Instrume

Debt Obligations (Debt Instruments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Long-term Debt		$ 33,094	$ 32,930
Other		5	30
Less: Current maturities of long-term debt		(407)	(1,189)
Long-term debt, less current maturities		32,687	31,741
ETP [Member]
Unamortized premiums, discounts and fair value adjustments, net		33	66
Deferred Finance Costs, Noncurrent, Net		(170)	(166)
Long-term Debt		$ 29,210	29,454
Debt instrument interest rate		6.50%
Debt instrument maturity date		May 15, 2021
Transwestern [Member]
Deferred Finance Costs, Noncurrent, Net		$ (1)	(1)
Long-term Debt		574	656
Panhandle [Member]
Unamortized premiums, discounts and fair value adjustments, net		28	50
Long-term Debt		813	1,135
Bakken Project [Member]
Deferred Finance Costs, Noncurrent, Net		(8)	(13)
Long-term Debt		2,492	1,087
6.125% Senior Notes due February 15, 2017 | ETP [Member]
Senior Notes		$ 0	400
Debt instrument interest rate		6.125%
Debt instrument maturity date		Feb. 15, 2017
2.50% Senior Notes due June 15, 2018 (1) | ETP [Member]
Senior Notes	[1]	$ 650	650
Debt instrument interest rate		2.50%
Debt instrument maturity date		Jun. 15, 2018
6.70% Senior Notes due July 1, 2018 (1) | ETP [Member]
Senior Notes	[1]	$ 600	600
Debt instrument interest rate		6.70%
Debt instrument maturity date		Jul. 1, 2018
9.70% Senior Notes due March 15, 2019 | ETP [Member]
Senior Notes		$ 400	400
Debt instrument interest rate		9.70%
Debt instrument maturity date		Mar. 15, 2019
9.00% Senior Notes due April 15, 2019 | ETP [Member]
Senior Notes		$ 450	450
Debt instrument interest rate		9.00%
Debt instrument maturity date		Apr. 15, 2019
4.15% Senior Notes due October 1, 2020 | ETP [Member]
Senior Notes		$ 1,050	1,050
Debt instrument interest rate		4.15%
Debt instrument maturity date		Oct. 1, 2020
4.65% Senior Notes due June 1, 2021 | ETP [Member]
Senior Notes		$ 800	800
Debt instrument interest rate		4.65%
Debt instrument maturity date		Jun. 1, 2021
5.20% Senior Notes due February 1, 2022 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		5.20%
Debt instrument maturity date		Feb. 1, 2022
3.60% Senior Notes due February 1, 2023 | ETP [Member]
Senior Notes		$ 800	800
Debt instrument interest rate		3.60%
Debt instrument maturity date		Feb. 1, 2023
4.90% Senior Notes due February 1, 2024 | ETP [Member]
Senior Notes		$ 350	350
Debt instrument interest rate		4.90%
Debt instrument maturity date		Feb. 1, 2024
7.60% Senior Notes due February 1, 2024 | ETP [Member]
Senior Notes		$ 277	277
Debt instrument interest rate		7.60%
Debt instrument maturity date		Feb. 1, 2024
7.60% Senior Notes due February 1, 2024 | Panhandle [Member]
Senior Notes		$ 82	82
Debt instrument interest rate		7.60%
Debt instrument maturity date		Feb. 1, 2024
4.05% Senior Notes due March 15, 2025 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		4.05%
Debt instrument maturity date		Mar. 15, 2025
4.75% Senior Notes due January 15, 2026 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		4.75%
Debt instrument maturity date		Jan. 15, 2026
4.20% Senior Notes due April 2027 [Member] | ETP [Member]
Senior Notes		$ 600	0
Debt instrument interest rate		4.20%
Debt instrument maturity date		Apr. 15, 2027
8.25% Senior Notes due November 15, 2029 | ETP [Member]
Senior Notes		$ 267	267
Debt instrument interest rate		8.25%
Debt instrument maturity date		Nov. 15, 2029
8.25% Senior Notes due November 15, 2029 | Panhandle [Member]
Senior Notes		$ 33	33
Debt instrument interest rate		8.25%
Debt instrument maturity date		Nov. 14, 2029
4.90% Senior Notes due March 15, 2035 | ETP [Member]
Senior Notes		$ 500	500
Debt instrument interest rate		4.90%
Debt instrument maturity date		Mar. 15, 2035
6.625% Senior Notes due October 15, 2036 | ETP [Member]
Senior Notes		$ 400	400
Debt instrument interest rate		6.625%
Debt instrument maturity date		Oct. 15, 2036
7.50% Senior Notes due July 1, 2038 | ETP [Member]
Senior Notes		$ 550	550
Debt instrument interest rate		7.50%
Debt instrument maturity date		Jul. 1, 2038
6.05% Senior Notes due June 1, 2041 | ETP [Member]
Senior Notes		$ 700	700
Debt instrument interest rate		6.05%
Debt instrument maturity date		Jun. 1, 2041
6.50% Senior Notes due February 1, 2042 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		6.50%
Debt instrument maturity date		Feb. 1, 2042
5.15% Senior Notes due February 1, 2043 | ETP [Member]
Senior Notes		$ 450	450
Debt instrument interest rate		5.15%
Debt instrument maturity date		Feb. 1, 2043
5.95% Senior Notes due October 1, 2043 | ETP [Member]
Senior Notes		$ 450	450
Debt instrument interest rate		5.95%
Debt instrument maturity date		Oct. 1, 2043
5.15% Senior Notes due March 15, 2045 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		5.15%
Debt instrument maturity date		Mar. 15, 2045
6.125% Senior Notes due December 15, 2045 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		6.125%
Debt instrument maturity date		Dec. 15, 2045
5.30% Senior Notes due April 2047 [Member] | ETP [Member]
Senior Notes		$ 900	0
Debt instrument interest rate		5.30%
Debt instrument maturity date		Apr. 15, 2047
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETP [Member]
Junior Subordinated Notes		$ 546	546
Debt instrument maturity date		Nov. 1, 2066
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member]
Junior Subordinated Notes		$ 54	54
Debt instrument maturity date		Nov. 1, 2066
Debt Instrument, Interest Rate, Effective Percentage		4.39%
ETLP $3.75 billion Revolving Credit Facility due November 2019 | ETP [Member]
Revolving credit facilities		$ 0	2,777
ETP Credit Facility due December 2022 [Member] | ETP [Member]
Revolving credit facilities		2,292	0
5.64% Senior Notes due May 24, 2017 | Transwestern [Member]
Senior Notes		$ 0	82
Debt instrument interest rate		5.64%
Debt instrument maturity date		May 24, 2017
5.36% Senior Notes due December 9, 2020 | Transwestern [Member]
Senior Notes		$ 175	175
Debt instrument interest rate		5.36%
Debt instrument maturity date		Dec. 9, 2020
5.89% Senior Notes due May 24, 2022 | Transwestern [Member]
Senior Notes		$ 150	150
Debt instrument interest rate		5.89%
Debt instrument maturity date		May 24, 2022
5.66% Senior Notes due December 9, 2024 | Transwestern [Member]
Senior Notes		$ 175	175
Debt instrument interest rate		5.66%
Debt instrument maturity date		Dec. 9, 2024
6.16% Senior Notes due May 24, 2037 | Transwestern [Member]
Senior Notes		$ 75	75
Debt instrument interest rate		6.16%
Debt instrument maturity date		May 24, 2037
6.20% Senior Notes due November 1, 2017 | Panhandle [Member]
Senior Notes		$ 0	300
Debt instrument interest rate		6.20%
Debt instrument maturity date		Nov. 1, 2017
7.00% Senior Notes due June 15, 2018 | Panhandle [Member]
Senior Notes		$ 400	400
Debt instrument interest rate		7.00%
Debt instrument maturity date		Jun. 15, 2018
8.125% Senior Notes due June 1, 2019 | Panhandle [Member]
Senior Notes		$ 150	150
Debt instrument interest rate		8.125%
Debt instrument maturity date		Jun. 1, 2019
7.00% Senior Notes due July 15, 2029 | Panhandle [Member]
Senior Notes		$ 66	66
Debt instrument interest rate		7.00%
Debt instrument maturity date		Jul. 15, 2029
5.75% Senior Notes due January 15, 2017 | Sunoco [Member]
Senior Notes		$ 0	400
Debt instrument interest rate		5.75%
Debt instrument maturity date		Jan. 15, 2017
9.00% Debentures due November 1, 2024 | Sunoco [Member]
Subordinated Debt		$ 65	65
5.50% Senior Notes due February 15, 2020 | ETP [Member]
Debt instrument interest rate		5.50%
Debt instrument maturity date		Feb. 15, 2020
5.50% Senior Notes due February 15, 2020 | Sunoco Logistics [Member]
Senior Notes		$ 250	250
4.40% Senior Notes due April 1, 2021 | ETP [Member]
Debt instrument interest rate		4.40%
Debt instrument maturity date		Apr. 1, 2021
4.40% Senior Notes due April 1, 2021 | Sunoco Logistics [Member]
Senior Notes		$ 600	600
4.65% Senior Notes due February 15, 2022 | ETP [Member]
Debt instrument interest rate		4.65%
Debt instrument maturity date		Feb. 15, 2022
4.65% Senior Notes due February 15, 2022 | Sunoco Logistics [Member]
Senior Notes		$ 300	300
3.45% Senior Notes due January 15, 2023 | ETP [Member]
Debt instrument interest rate		3.45%
Debt instrument maturity date		Jan. 15, 2023
3.45% Senior Notes due January 15, 2023 | Sunoco Logistics [Member]
Senior Notes		$ 350	350
4.25% Senior Notes due April 1, 2024 | Sunoco Logistics [Member]
Senior Notes		$ 500	500
5.95% Senior Notes due December 1, 2025 | ETP [Member]
Debt instrument interest rate		5.95%
Debt instrument maturity date		Dec. 1, 2025
5.95% Senior Notes due December 1, 2025 | Sunoco Logistics [Member]
Senior Notes		$ 400	400
3.90% Senior Notes due July 15, 2026 | ETP [Member]
Debt instrument interest rate		3.90%
Debt instrument maturity date		Jul. 15, 2026
3.90% Senior Notes due July 15, 2026 | Sunoco Logistics [Member]
Senior Notes		$ 550	550
4.00% Senior Notes due October 1, 2027 [Member] | ETP [Member]
Debt instrument interest rate		4.00%
Debt instrument maturity date		Oct. 1, 2027
4.00% Senior Notes due October 1, 2027 [Member] | Sunoco Logistics [Member]
Senior Notes		$ 750	0
6.85% Senior Notes due February 15, 2040 | ETP [Member]
Debt instrument interest rate		6.85%
Debt instrument maturity date		Feb. 15, 2040
6.85% Senior Notes due February 15, 2040 | Sunoco Logistics [Member]
Senior Notes		$ 250	250
6.10% Senior Notes due February 15, 2042 | ETP [Member]
Debt instrument interest rate		6.10%
Debt instrument maturity date		Feb. 15, 2042
6.10% Senior Notes due February 15, 2042 | Sunoco Logistics [Member]
Senior Notes		$ 300	300
4.95% Senior Notes due January 15, 2043 | ETP [Member]
Debt instrument interest rate		4.95%
Debt instrument maturity date		Jan. 15, 2043
4.95% Senior Notes due January 15, 2043 | Sunoco Logistics [Member]
Senior Notes		$ 350	350
5.30% Senior Notes due April 1, 2044 | ETP [Member]
Debt instrument interest rate		5.30%
Debt instrument maturity date		Apr. 1, 2044
5.30% Senior Notes due April 1, 2044 | Sunoco Logistics [Member]
Senior Notes		$ 700	700
5.35% Senior Notes due May 15, 2045 | ETP [Member]
Debt instrument interest rate		5.35%
Debt instrument maturity date		May 15, 2045
5.35% Senior Notes due May 15, 2045 | Sunoco Logistics [Member]
Senior Notes		$ 800	800
5.40% Senior Notes due October 1, 2047 [Member] | ETP [Member]
Debt instrument interest rate		5.40%
Debt instrument maturity date		Oct. 1, 2047
5.40% Senior Notes due October 1, 2047 [Member] | Sunoco Logistics [Member]
Senior Notes		$ 1,500	0
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | Sunoco Logistics [Member]
Revolving credit facilities		0	1,292
5.75% Senior Notes due September 1, 2020 | ETP [Member]
Senior Notes		$ 400	400
Debt instrument interest rate		5.75%
Debt instrument maturity date		Sep. 1, 2020
6.50% Senior Notes due July 15, 2021 | ETP [Member]
Senior Notes		$ 0	500
5.875% Senior Notes due March 1, 2022 | ETP [Member]
Senior Notes		$ 900	900
Debt instrument interest rate		5.875%
Debt instrument maturity date		Mar. 1, 2022
5.00% Senior Notes due October 1, 2022 | ETP [Member]
Senior Notes		$ 700	700
Debt instrument interest rate		5.00%
Debt instrument maturity date		Oct. 1, 2022
5.50% Senior Notes due April 15, 2023 | ETP [Member]
Senior Notes		$ 0	700
Debt instrument interest rate		5.50%
Debt instrument maturity date		Apr. 15, 2023
4.50% Senior Notes due November 1, 2023 | ETP [Member]
Senior Notes		$ 600	600
Debt instrument interest rate		4.50%
Debt instrument maturity date		Nov. 1, 2023
Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETP [Member]
Revolving credit facilities	[2]	$ 50	0
Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | Sunoco Logistics [Member]
Revolving credit facilities		0	630
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]
Revolving credit facilities		2,500	1,100
PennTex $275 million Revolving Credit Facility due December 2019 | PennTex [Member]
Revolving credit facilities		$ 0	$ 168
[1]	As of December 31, 2017 management had the intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current.
[2]	Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.

Debt Obligations Debt Instrumen

Debt Obligations Debt Instruments (Parenthetical) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
ETP [Member]
Senior note interest rate	6.50%
Debt instrument maturity date	May 15, 2021
Deferred Finance Costs, Noncurrent, Net	$ 170	$ 166
Transwestern [Member]
Deferred Finance Costs, Noncurrent, Net	$ 1	$ 1
5.95% Senior Notes due December 1, 2025 | ETP [Member]
Senior note interest rate	5.95%
Debt instrument maturity date	Dec. 1, 2025
3.90% Senior Notes due July 15, 2026 | ETP [Member]
Senior note interest rate	3.90%
Debt instrument maturity date	Jul. 15, 2026
4.00% Senior Notes due October 1, 2027 [Member] | ETP [Member]
Senior note interest rate	4.00%
Debt instrument maturity date	Oct. 1, 2027
6.85% Senior Notes due February 15, 2040 | ETP [Member]
Senior note interest rate	6.85%
Debt instrument maturity date	Feb. 15, 2040
5.30% Senior Notes due April 1, 2044 | ETP [Member]
Senior note interest rate	5.30%
Debt instrument maturity date	Apr. 1, 2044
5.35% Senior Notes due May 15, 2045 | ETP [Member]
Senior note interest rate	5.35%
Debt instrument maturity date	May 15, 2045
6.125% Senior Notes due February 15, 2017 | ETP [Member]
Senior note interest rate	6.125%
Debt instrument maturity date	Feb. 15, 2017
2.50% Senior Notes due June 15, 2018 (1) | ETP [Member]
Senior note interest rate	2.50%
Debt instrument maturity date	Jun. 15, 2018
6.70% Senior Notes due July 1, 2018 (1) | ETP [Member]
Senior note interest rate	6.70%
Debt instrument maturity date	Jul. 1, 2018
9.70% Senior Notes due March 15, 2019 | ETP [Member]
Senior note interest rate	9.70%
Debt instrument maturity date	Mar. 15, 2019
9.00% Senior Notes due April 15, 2019 | ETP [Member]
Senior note interest rate	9.00%
Debt instrument maturity date	Apr. 15, 2019
5.75% Senior Notes due September 1, 2020 | ETP [Member]
Senior note interest rate	5.75%
Debt instrument maturity date	Sep. 1, 2020
4.15% Senior Notes due October 1, 2020 [Member] | ETP [Member]
Senior note interest rate	4.15%
Debt instrument maturity date	Oct. 1, 2020
4.65% Senior Notes due June 1, 2021 | ETP [Member]
Senior note interest rate	4.65%
Debt instrument maturity date	Jun. 1, 2021
5.20% Senior Notes due February 1, 2022 | ETP [Member]
Senior note interest rate	5.20%
Debt instrument maturity date	Feb. 1, 2022
5.875% Senior Notes due March 1, 2022 | ETP [Member]
Senior note interest rate	5.875%
Debt instrument maturity date	Mar. 1, 2022
5.00% Senior Notes due October 1, 2022 | ETP [Member]
Senior note interest rate	5.00%
Debt instrument maturity date	Oct. 1, 2022
3.60% Senior Notes due February 1, 2023 | ETP [Member]
Senior note interest rate	3.60%
Debt instrument maturity date	Feb. 1, 2023
5.50% Senior Notes due April 15, 2023 | ETP [Member]
Senior note interest rate	5.50%
Debt instrument maturity date	Apr. 15, 2023
4.50% Senior Notes due November 1, 2023 | ETP [Member]
Senior note interest rate	4.50%
Debt instrument maturity date	Nov. 1, 2023
4.90% Senior Notes due February 1, 2024 | ETP [Member]
Senior note interest rate	4.90%
Debt instrument maturity date	Feb. 1, 2024
7.60% Senior Notes due February 1, 2024 | ETP [Member]
Senior note interest rate	7.60%
Debt instrument maturity date	Feb. 1, 2024
7.60% Senior Notes due February 1, 2024 | Panhandle [Member]
Senior note interest rate	7.60%
Debt instrument maturity date	Feb. 1, 2024
4.05% Senior Notes due March 15, 2025 | ETP [Member]
Senior note interest rate	4.05%
Debt instrument maturity date	Mar. 15, 2025
4.75% Senior Notes due January 15, 2026 | ETP [Member]
Senior note interest rate	4.75%
Debt instrument maturity date	Jan. 15, 2026
4.20% Senior Notes due April 2027 [Member] | ETP [Member]
Senior note interest rate	4.20%
Debt instrument maturity date	Apr. 15, 2027
8.25% Senior Notes due November 15, 2029 | ETP [Member]
Senior note interest rate	8.25%
Debt instrument maturity date	Nov. 15, 2029
8.25% Senior Notes due November 15, 2029 | Panhandle [Member]
Senior note interest rate	8.25%
Debt instrument maturity date	Nov. 14, 2029
6.625% Senior Notes due October 15, 2036 | ETP [Member]
Senior note interest rate	6.625%
Debt instrument maturity date	Oct. 15, 2036
4.90% Senior Notes due March 15, 2035 | ETP [Member]
Senior note interest rate	4.90%
Debt instrument maturity date	Mar. 15, 2035
7.50% Senior Notes due July 1, 2038 | ETP [Member]
Senior note interest rate	7.50%
Debt instrument maturity date	Jul. 1, 2038
6.05% Senior Notes due June 1, 2041 | ETP [Member]
Senior note interest rate	6.05%
Debt instrument maturity date	Jun. 1, 2041
6.50% Senior Notes due February 1, 2042 | ETP [Member]
Senior note interest rate	6.50%
Debt instrument maturity date	Feb. 1, 2042
5.15% Senior Notes due February 1, 2043 | ETP [Member]
Senior note interest rate	5.15%
Debt instrument maturity date	Feb. 1, 2043
5.95% Senior Notes due October 1, 2043 | ETP [Member]
Senior note interest rate	5.95%
Debt instrument maturity date	Oct. 1, 2043
5.15% Senior Notes due March 15, 2045 | ETP [Member]
Senior note interest rate	5.15%
Debt instrument maturity date	Mar. 15, 2045
6.125% Senior Notes due December 15, 2045 | ETP [Member]
Senior note interest rate	6.125%
Debt instrument maturity date	Dec. 15, 2045
5.30% Senior Notes due April 2047 [Member] | ETP [Member]
Senior note interest rate	5.30%
Debt instrument maturity date	Apr. 15, 2047
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETP [Member]
Debt instrument maturity date	Nov. 1, 2066
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member]
Debt instrument maturity date	Nov. 1, 2066
Debt Instrument, Interest Rate, Effective Percentage	4.39%
5.64% Senior Notes due May 24, 2017 | Transwestern [Member]
Senior note interest rate	5.64%
Debt instrument maturity date	May 24, 2017
5.36% Senior Notes due December 9, 2020 | Transwestern [Member]
Senior note interest rate	5.36%
Debt instrument maturity date	Dec. 9, 2020
5.89% Senior Notes due May 24, 2022 | Transwestern [Member]
Senior note interest rate	5.89%
Debt instrument maturity date	May 24, 2022
5.66% Senior Notes due December 9, 2024 | Transwestern [Member]
Senior note interest rate	5.66%
Debt instrument maturity date	Dec. 9, 2024
6.16% Senior Notes due May 24, 2037 | Transwestern [Member]
Senior note interest rate	6.16%
Debt instrument maturity date	May 24, 2037
6.20% Senior Notes due November 1, 2017 | Panhandle [Member]
Senior note interest rate	6.20%
Debt instrument maturity date	Nov. 1, 2017
7.00% Senior Notes due June 15, 2018 | Panhandle [Member]
Senior note interest rate	7.00%
Debt instrument maturity date	Jun. 15, 2018
8.125% Senior Notes due June 1, 2019 | Panhandle [Member]
Senior note interest rate	8.125%
Debt instrument maturity date	Jun. 1, 2019
7.00% Senior Notes due July 15, 2029 | Panhandle [Member]
Senior note interest rate	7.00%
Debt instrument maturity date	Jul. 15, 2029
5.50% Senior Notes due February 15, 2020 | ETP [Member]
Senior note interest rate	5.50%
Debt instrument maturity date	Feb. 15, 2020
4.40% Senior Notes due April 1, 2021 | ETP [Member]
Senior note interest rate	4.40%
Debt instrument maturity date	Apr. 1, 2021
4.65% Senior Notes due February 15, 2022 | ETP [Member]
Senior note interest rate	4.65%
Debt instrument maturity date	Feb. 15, 2022
3.45% Senior Notes due January 15, 2023 | ETP [Member]
Senior note interest rate	3.45%
Debt instrument maturity date	Jan. 15, 2023
6.10% Senior Notes due February 15, 2042 | ETP [Member]
Senior note interest rate	6.10%
Debt instrument maturity date	Feb. 15, 2042
4.95% Senior Notes due January 15, 2043 | ETP [Member]
Senior note interest rate	4.95%
Debt instrument maturity date	Jan. 15, 2043
5.75% Senior Notes due January 15, 2017 | Sunoco [Member]
Senior note interest rate	5.75%
Debt instrument maturity date	Jan. 15, 2017
5.40% Senior Notes due October 1, 2047 [Member] | ETP [Member]
Senior note interest rate	5.40%
Debt instrument maturity date	Oct. 1, 2047

Debt Obligations (Future maturi

Debt Obligations (Future maturities of long-term debt) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debt Obligations [Abstract]
2,018	$ 1,700
2,019	3,500
2,020	1,875
2,021	1,400
2,022	5,346
Thereafter	19,391
Long-term Debt	33,094	$ 32,930
Long-term Debt, Gross	$ 33,212

Series A Preferred Units (Detai

Series A Preferred Units (Details) shares in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2017USD ($)shares	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares		Dec. 31, 2015USD ($)shares		Apr. 30, 2015USD ($)$ / commonunit
Preferred Units Redemption Amount | $							$ 35
Preferred Units Quarterly Cash Distribution Per Unit | $ / commonunit							0.445
Partners' Capital Account, Units, Redeemed | shares		0	26.7	[1]	77.8	[1]
Payments for Repurchase of Preferred Stock and Preference Stock | $	$ 53	$ 53	$ 0		$ 0
ETP Series A Preferred Units [Member]
Partners' Capital Account, Units, Redeemed | shares	1.9
[1]	The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.

Equity (Narrative) (Details)

Equity (Narrative) (Details)	1 Months Ended									3 Months Ended																6 Months Ended		12 Months Ended					36 Months Ended
	Nov. 30, 2017USD ($)$ / sharesshares	Aug. 31, 2017USD ($)	May 31, 2017USD ($)	Apr. 30, 2017	Feb. 28, 2017	Jan. 31, 2017USD ($)shares	Oct. 31, 2015USD ($)	Apr. 30, 2015USD ($)	Mar. 31, 2015USD ($)shares	Dec. 31, 2017USD ($)$ / sharesshares	Sep. 30, 2017$ / shares	Jun. 30, 2017$ / shares	Mar. 31, 2017$ / shares	Dec. 31, 2016$ / sharesshares		Sep. 30, 2016$ / shares	Jun. 30, 2016$ / shares	Mar. 31, 2016$ / shares	Dec. 31, 2015$ / sharesshares		Sep. 30, 2015$ / shares	Jun. 30, 2015$ / shares	Mar. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014$ / sharesshares		Dec. 31, 2016USD ($)shares		Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)shares		Dec. 31, 2015USD ($)shares		Dec. 31, 2017USD ($)$ / sharesshares	Feb. 01, 2017	Oct. 05, 2012shares
Distribution Made to Limited Partner, Date of Record										Feb. 8, 2018	Nov. 7, 2017	Aug. 7, 2017	May 10, 2017
Beneficial ownership limit for voting rights										20.00%																		20.00%					20.00%
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares										$ 0.5650	$ 0.5650	$ 0.5500	$ 0.5350
Common Units issued for cash | $		$ 997,000,000																										$ 2,283,000,000	$ 1,098,000,000		$ 1,428,000,000
Partners' Capital Account, Units, Sold in Private Placement						23,700,000																							0	[1]
Class H Unitholder’s interest in net income | $																												$ 93,000,000	$ 351,000,000		$ 258,000,000
Partners' Capital Account, Units										1,164,100,000				794,800,000	[1]				758,500,000	[1]				533,400,000	[1]	794,800,000	[1]	1,164,100,000	794,800,000	[1]	758,500,000	[1]	1,164,100,000
Common Units issued in connection with the Distribution Reinvestment Plan																												12,000,000	9,900,000	[1]	11,700,000	[1]
Class E Units entitled to aggregate cash distributions										11.10%																		11.10%					11.10%
Class E unit maximum distribution | $ / shares										$ 1.41																		$ 1.41					$ 1.41
Partners' Capital Account, Units, Redeemed																												0	26,700,000	[1]	77,800,000	[1]
Common Units issued in connection with the equity distribution program																												22,600,000	39,000,000	[1]	31,700,000	[1]
Partners' Capital Account, Units, Sold in Public Offering																												54,000,000	0	[1]	0	[1]
Partners' Capital Account, Sale of Units | $																												$ 3,762,000,000	$ 1,098,000,000		$ 1,428,000,000
Payments to Acquire Businesses, Gross | $							$ 382,000,000
Class G Unit Distribution Rate										35.00%																		35.00%					35.00%
Class G Unit Maximum Distribution | $ / shares										$ 3.75																		$ 3.75					$ 3.75
Distribution Made to Limited Partner, Distribution Date										Feb. 14, 2018	Nov. 14, 2017	Aug. 15, 2017	May 16, 2017
PennTex [Member]
Sale of Stock, Price Per Share | $ / shares												$ 20
ETP [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares														$ 0.7033		$ 0.7033	$ 0.7033	$ 0.7033	$ 0.7033		$ 0.7033	$ 0.6900	$ 0.6767	$ 0.6633
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold | $																												$ 1,000,000,000
Proceeds from Issuance of Private Placement | $						$ 568,000,000
Common Units issued in connection with the equity distribution program																												22,600,000					25,500,000
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan										20,800,000																		20,800,000					20,800,000
Equity Distribution Agreements, Value of Units Available to be Issued | $										$ 752,000,000																		$ 752,000,000					$ 752,000,000
Stock Issued During Period, Value, Dividend Reinvestment Plan | $																												228,000,000	216,000,000		360,000,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | $																												503,000,000
Fees and Commissions | $																												5,000,000
Sunoco Logistics [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares														$ 0.5200		$ 0.5100	$ 0.5000	$ 0.4890	$ 0.4790		$ 0.4580	$ 0.4380	$ 0.4190	$ 0.4000
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold | $																													1,250,000,000
Partners' Capital Account, Units, Sale of Units									15,500,000																	24,200,000
Proceeds from Issuance of Common Stock | $									$ 629,000,000																	$ 644,000,000
Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest							40.00%
BP Products North America [Member]
Loss Contingency, Damages Awarded, Value | $			$ 13,000,000					$ 62,000,000																							41,000,000
Accumulated Other Comprehensive Income (Loss)
Partners' Capital Account, Sale of Units | $																												$ 0	0		$ 0
SXL and ETP Merger [Member]
Conversion Rate of Units in Merger, Per Unit				1.5
Bakken Pipeline Transaction [Member]
Class I Distributions | $																							$ 55,000,000						$ 30,000,000
Partners' Capital Account, Units, Redeemed									46,200,000
Business Combination, Consideration Transferred | $									$ 879,000,000
Bakken Pipeline Transaction [Member] | Parent Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest									45.00%
Preferred Units [Member]
Distribution Made to Limited Partner, Date of Record										Feb. 1, 2018
Distribution Made to Limited Partner, Distribution Date										Feb. 15, 2018
Class I Units
Limited Partners' Capital Account, Units Outstanding										100				100												100		100	100				100
Limited Partners' Capital Account, Units Authorized										100				100												100		100	100				100
Class I Units | Bakken Pipeline Transaction [Member]
Partners' Capital Account, Units									100														100
Class E Units
Limited Partners' Capital Account, Units Outstanding										8,853,832				8,853,832												8,853,832		8,853,832	8,853,832				8,853,832
Limited Partners' Capital Account, Units Authorized										8,853,832				8,853,832												8,853,832		8,853,832	8,853,832				8,853,832
Class G Units
Limited Partners' Capital Account, Units Outstanding										90,706,000				90,706,000												90,706,000		90,706,000	90,706,000				90,706,000
Limited Partners' Capital Account, Units Authorized										90,706,000				90,706,000												90,706,000		90,706,000	90,706,000				90,706,000
Class G Units | ETP Holdco Transaction (see Note 3)
Partners' Capital Account, Units																																			90,700,000
Class H Units
Partners' Capital Account, Units									50,200,000														50,200,000
Limited Partners' Capital Account, Units Outstanding										0				81,001,069												81,001,069		0	81,001,069				0
Limited Partners' Capital Account, Units Authorized										0				81,001,069												81,001,069		0	81,001,069				0
Allocation of Profits, Losses and Other by Sunoco, Percent										90.05%																		90.05%					90.05%
Class H Units | Bakken Pipeline Transaction [Member]
Allocation of Profits, Losses and Other by Sunoco, Percent									90.05%														90.05%
Partners' Capital Account, Units, Redeemed									30,800,000
Class K Units [Member]
Limited Partners' Capital Account, Units Outstanding										101,525,429				101,525,429												101,525,429		101,525,429	101,525,429				101,525,429
Limited Partners' Capital Account, Units Authorized										101,525,429				101,525,429												101,525,429		101,525,429	101,525,429				101,525,429
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ / shares														$ 0.67275
Common Stock Held by Subsidiary | $										$ 101,525,429																		$ 101,525,429					$ 101,525,429
Series A Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares										$ 15.451
Preferred Stock, Shares Issued	950,000
Preferred Units, Offering Costs | $	$ 1,000
Preferred Stock, Dividend Rate, Percentage	6.25%
Preferred Stock, Liquidation Preference Per Share | $ / shares	$ 1,000
Preferred Units, Liquidation Spread, Percent	4.028%
Series B Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares										$ 16,378,000
Preferred Stock, Shares Issued	550,000
Preferred Units, Offering Costs | $	$ 1,000
Preferred Stock, Dividend Rate, Percentage	6.625%
Preferred Stock, Liquidation Preference Per Share | $ / shares	$ 1,000
Preferred Units, Liquidation Spread, Percent	4.155%
Second Target Distribution [Member]
Distribution Payment Targets										0.0833
Class E Units | ETP [Member]
Limited Partners' Capital Account, Units Outstanding										8,900,000																		8,900,000					8,900,000
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | Sunoco Logistics [Member]
Line of Credit Facility, Current Borrowing Capacity | $										$ 2,500,000,000																		$ 2,500,000,000					$ 2,500,000,000
Dakota Access and ETCO [Member] | Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					25.00%
Dakota Access and ETCO [Member] | Bakken Pipeline Investments LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					75.00%
Bakken Pipeline Investments LLC [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired																																		200000000000.00%
Sunoco Logistics [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					49.00%
ETP [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					100.00%
Maximum [Member] | IDRs [Member]
Marginal Percentage Interest in Distributions										48.00%																		48.00%					48.00%
[1]	The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.

Equity (Change in Common Units)

Equity (Change in Common Units) (Details) - shares shares in Millions		1 Months Ended	12 Months Ended					36 Months Ended
		Jan. 31, 2017	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2017
Number of Common Units, beginning of period	[1]	794.8	794.8	758.5		533.4		533.4
Partners' Capital Account, Units, Redeemed			0	(26.7)	[1]	(77.8)	[1]
Partners' Capital Account, Units, Acquisitions			0	13.3	[1]	258.2	[1]
Common Units issued in connection with the Distribution Reinvestment Plan			12	9.9	[1]	11.7	[1]
Common Units issued in connection with the equity distribution program			22.6	39	[1]	31.7	[1]
Partners' Capital Account, Units, Sold in Private Placement		23.7		0	[1]
Issuance of Common Units under equity incentive plans			1.6	0.8	[1]	1.3	[1]
Number of Common Units, end of period			1,164.1	794.8	[1]	758.5	[1]	1,164.1
Sunoco Logistics Merger [Member]
Partners' Capital Account, Units, Acquisitions	[2]		255.4	0	[1]
[1]	The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
[2]	Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger.

Equity (Public Offerings of Com

Equity (Public Offerings of Common Units) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Aug. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net Proceeds	$ 997	$ 2,283	$ 1,098	$ 1,428

Equity (Quarterly Distributions

Equity (Quarterly Distributions of Available Cash) (Details) - $ / shares	3 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Date of Record	Feb. 8, 2018	Nov. 7, 2017	Aug. 7, 2017	May 10, 2017
Distribution Made to Limited Partner, Distribution Date	Feb. 14, 2018	Nov. 14, 2017	Aug. 15, 2017	May 16, 2017
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.5650	$ 0.5650	$ 0.5500	$ 0.5350
ETP [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Paid, Per Unit					$ 0.7033	$ 0.7033	$ 0.7033	$ 0.7033	$ 0.7033	$ 0.7033	$ 0.6900	$ 0.6767	$ 0.6633
Sunoco Logistics [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Paid, Per Unit					$ 0.5200	$ 0.5100	$ 0.5000	$ 0.4890	$ 0.4790	$ 0.4580	$ 0.4380	$ 0.4190	$ 0.4000

Equity (Incentive Distribution

Equity (Incentive Distribution Relinquishments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Subsequent Event [Member]
Subsequent Event [Line Items]
Relinquishment of Incentive Distributions	$ 33	$ 128	$ 153

Equity (Accumulated other compr

Equity (Accumulated other comprehensive income, net of tax) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	$ 8	$ 2
Foreign currency translation adjustment	(5)	(5)
Actuarial gain (loss) related to pensions and other postretirement benefits	(5)	7
AOCI attributable to equity method investments	5	4
Total AOCI, net of tax	$ 3	$ 8

Equity (Tax amounts attributabl

Equity (Tax amounts attributable to Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Equity [Abstract]
Other Comprehensive Income (Loss), Available-for-sale Securities, Tax	$ (2)	$ (2)
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax	3	3
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	3	0
Other Comprehensive Income (Loss), Tax	$ 4	$ 1

Equity Distribution Targets (De

Equity Distribution Targets (Details)	12 Months Ended
	Dec. 31, 2017
Minimum Quarterly Distribution [Member]
Distribution Payment Targets	0.0750
Minimum Quarterly Distribution [Member] | IDRs [Member]
Marginal Percentage Interest in Distributions	0.00%
Minimum Quarterly Distribution [Member] | Limited Partner [Member]
Marginal Percentage Interest in Distributions	100.00%	[1]
First Target Distribution [Member]
Distribution Payment Targets	up to $0.0833
First Target Distribution [Member] | IDRs [Member]
Marginal Percentage Interest in Distributions	0.00%
First Target Distribution [Member] | Limited Partner [Member]
Marginal Percentage Interest in Distributions	100.00%	[1]
Second Target Distribution [Member]
Distribution Payment Targets	above $0.0833 up to $0.0958
Second Target Distribution [Member] | IDRs [Member]
Marginal Percentage Interest in Distributions	13.00%
Second Target Distribution [Member] | Limited Partner [Member]
Marginal Percentage Interest in Distributions	87.00%	[1]
Third Target Distribution [Member]
Distribution Payment Targets	above $0.0958 up to $0.2638
Third Target Distribution [Member] | IDRs [Member]
Marginal Percentage Interest in Distributions	35.00%
Third Target Distribution [Member] | Limited Partner [Member]
Marginal Percentage Interest in Distributions	65.00%	[1]
Thereafter [Member]
Distribution Payment Targets	$0.2638
Thereafter [Member] | IDRs [Member]
Marginal Percentage Interest in Distributions	48.00%
Thereafter [Member] | Limited Partner [Member]
Marginal Percentage Interest in Distributions	52.00%	[1]
[1]	Includes general partner and limited partner interests, based on the proportionate ownership of each.

Unit-Based Compensation Plans83

Unit-Based Compensation Plans (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	8.4
Employee [Member]
Share based compensation, vesting term	5 years
Director [Member]
Share based compensation, vesting term	5 years
ETP Unit-Based Compensation Plans [Member]
Awards granted	$ 17.69	$ 23.82	$ 23.47
Total fair value of awards vested	$ 40	$ 40	$ 57
Unvested unit awards outstanding	14.1	9.4
Awards remaining unvested compensation expense	$ 189
Awards remaining unvested weighted average period, in years	2 years 8 months

Unit-Based Compensation Plans84

Unit-Based Compensation Plans (Activity of the awards granted to employees and non-employee directors) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
ETP Unit-Based Compensation Plans [Member]
Unvested unit awards outstanding	14.1	9.4
Awards granted	4.9
Awards vested	(2.3)
Unvested awards as of December 31, 2016	$ 27.68
Awards granted	17.69	$ 23.82	$ 23.47
Awards vested	34.22
Awards forfeited	$ 25.03
Awards forfeited	$ (1.1)
Unvested awards as of December 31, 2017	$ 23.18	$ 27.68
Legacy Sunoco Logistics Unit-Based Compensation Plans [Member]
Unvested unit awards outstanding		3.2
Unvested awards as of December 31, 2016	$ 28.57
Unvested awards as of December 31, 2017		$ 28.57

Income Taxes Narrative (Details

Income Taxes Narrative (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Dec. 31, 2017	Nov. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Deferred Tax Liabilities, Gross	$ 3,426		$ 3,426	$ 4,802
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, Ater Tax	576		576
Unrecognized Tax Benefits, Interest on Income Taxes Expense			3
Income Tax Examination, Penalties and Interest Accrued	9		$ 9
Operating Loss Carryforwards, Expiration Date			Jan. 1, 2031
Net operating losses and alternative minimum tax credit	604		$ 604	380
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	605		605
Deferred Tax Assets, Valuation Allowance	189		189	118
Pending Tax Refund	530		530
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	$ 530		530
State			(18)	(35)	$ (51)
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%
Tax Credit Carryforward, Valuation Allowance	$ 186		186
Operating Loss Carryforwards, Valuation Allowance	3		3
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount			(1,559)	$ 0	$ 0
ETP Holdco and other corporate subsidiaries [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	1,570		1,570
Corporate Subsidiaries [Member]
Income Tax Contingency [Line Items]
Net operating losses and alternative minimum tax credit	62		62
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	210		210
Net of federal tax [Member]
Income Tax Contingency [Line Items]
State			$ 53
Minimum [Member] | Corporate Subsidiaries [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards, Expiration Date			Jan. 1, 2018
Maximum [Member] | ETP Holdco and other corporate subsidiaries [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards, Expiration Date			Dec. 31, 2037
Maximum [Member] | Corporate Subsidiaries [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards, Expiration Date			Dec. 31, 2036
Pennsylvania Constitution [Member]
Income Tax Contingency [Line Items]
State			$ 67
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	27		27
Pennsylvania Constitution [Member] | Net of federal tax [Member]
Income Tax Contingency [Line Items]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	21		21
Reclassed to current income tax receivable within 12 months [Member]
Income Tax Contingency [Line Items]
Net operating losses and alternative minimum tax credit	$ 29		$ 29

Income Taxes Compoenents of Fed

Income Taxes Compoenents of Federal and State Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current expense (benefit):
Federal	$ 53	$ 18	$ (274)
State	(18)	(35)	(51)
Current expense (benefit) - Total	35	(17)	(325)
Deferred expense (benefit):
Federal	(1,723)	(173)	231
State	192	4	(29)
Deferred expense (benefit) - Total	(1,531)	(169)	202
Income tax benefit	$ (1,496)	$ (186)	$ (123)

Income Taxes Statutory Income T

Income Taxes Statutory Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income tax expense at United States statutory rate of 35 percent	$ 352	$ 139	$ 479
Partnership earnings not subject to tax	(457)	(504)	(504)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	(1,559)	0	0
Goodwill impairments	172	223	0
Foreign	131	(17)	(37)
Dividend received deduction	(14)	(15)	(24)
Audit settlement	0	0	(7)
Other	3	(12)	(30)
Income tax benefit	(1,496)	(186)	(123)
Effective Income Tax Rate Reconciliation, Change in Tax Status of Subsidiary	$ (124)	$ 0	$ 0

Income Taxes Tax Effects of Tem

Income Taxes Tax Effects of Temporary Differences (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Deferred income tax assets:
Net operating losses and alternative minimum tax credit	$ 604	$ 380
Pension and other postretirement benefits	21	30
Long-term debt	14	32
Other	93	84
Total deferred income tax assets	732	526
Valuation allowance	(189)	(118)
Net deferred income tax assets	543	408
Deferred income tax liabilities:
Property, plant and equipment	(664)	(1,054)
Investment in unconsolidated affiliates	(2,664)	(3,728)
Other	(98)	(20)
Total deferred income tax liabilities	(3,426)	(4,802)
Net deferred income taxes	(2,883)	(4,394)	$ (4,082)
Accumulated deferred income taxes	$ (2,883)	$ (4,394)

Income Taxes Components of Net

Income Taxes Components of Net Deferred Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Net deferred income tax liability, beginning of year	$ (4,394)	$ (4,082)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)	0	(460)
Tax provision	1,531	169
Other	(20)	(21)
Net deferred income tax liability, end of year	$ (2,883)	$ (4,394)

Income Taxes Changes in Unrecog

Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Balance at beginning of year	$ 615	$ 610	$ 440
Additions attributable to tax positions taken in the current year	0	8	0
Additions attributable to tax positions taken in prior years	28	18	178
Reduction attributable to tax positions taken in prior years	(25)	(20)	0
Lapse of statute	(9)	(1)	(8)
Balance at end of year	$ 609	$ 615	$ 610

Regulatory Matters, Commitmen91

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Narrative) (Details)	1 Months Ended			12 Months Ended
	Jan. 31, 2018USD ($)	Oct. 31, 2015USD ($)	Apr. 30, 2015USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)		Dec. 31, 2015USD ($)		Aug. 31, 2017USD ($)	Oct. 31, 2016USD ($)	Jul. 31, 2016USD ($)	Apr. 30, 2016USD ($)
Lease Expiration Date				Dec. 31, 2034
Rental expense(1)				$ 90,000,000	$ 81,000,000	[1]	$ 176,000,000	[1]
Operating Leases, Rent Expense, Sublease Rentals				0	(1,000,000)		(16,000,000)
Rental expense, net				$ 90,000,000	80,000,000		160,000,000
Operating Leases, Rent Expense, Contingent Rentals							$ 26,000,000
Site Contingency, Number of Sites Needing Remediation				43
Amounts recorded in balance sheets for contingencies and current litigation not disclosed				$ 0
Accrual for Environmental Loss Contingencies				350,000,000	309,000,000
Payments for Environmental Liabilities				23,000,000	43,000,000
Payments to Acquire Businesses, Gross		$ 382,000,000
Proposed Environmental Penalty				0					$ 100,000	$ 100,000	$ 100,000
Long-term Debt				33,094,000,000	32,930,000,000
Permian Express 2 [Member]
Proposed Environmental Penalty												$ 100,000
Related To Deductibles [Member]
Loss Contingency Accrual, at Carrying Value				$ 33,000,000	$ 77,000,000
Dropdown of Sunoco LLC Interest [Member]
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage			31.58%
Payments to Acquire Businesses, Gross			$ 775,000,000
Equity Issued in Business Combination, Fair Value Disclosure			$ 41,000,000
6.375% Senior Notes due April 2023 [Member] | Sunoco LP [Member]
Debt instrument interest rate				6.375%
Senior Notes				$ 800,000,000
6.25% Senior Notes due 2021 [Member] | Sunoco LP [Member]
Debt instrument interest rate				6.25%
Senior Notes				$ 800,000,000
Term loan due 2019 [Member] | Sunoco LP [Member]
Long-term Debt				2,035,000,000
Federal [Member] | Sunoco Pipeline L.P. [Member]
Proposed Environmental Penalty				7,000,000
State and Local Jurisdiction [Member] | Sunoco Pipeline L.P. [Member]
Proposed Environmental Penalty				1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount				536,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount				1,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount				595,000,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount				$ 319,000,000
Subsequent Event [Member] | 4.875% senior notes due 2023 [Member] | Sunoco LP [Member]
Debt instrument interest rate	4.875%
Senior Notes	$ 1,000,000,000
Subsequent Event [Member] | 5.500% senior notes due 2026 [Member] | Sunoco LP [Member]
Debt instrument interest rate	5.50%
Senior Notes	$ 800,000,000
Subsequent Event [Member] | 5.875% senior notes due 2028 [Member] | Sunoco LP [Member]
Debt instrument interest rate	5.875%
Senior Notes	$ 400,000,000
Subsequent Event [Member] | PENNSYLVANIA
Civil penalties	$ 12,600,000
[1]	(1) Includes contingent rentals totaling $26 million for the year ended December 31, 2015

Regulatory Matters, Commitmen92

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Rent Expense and Future minimum lease commitments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Rental expense(1)	$ 90	$ 81	[1]	$ 176	[1]
Less: Sublease rental income	0	1		16
Rental expense, net	90	$ 80		$ 160
2,018	39
2,019	36
2,020	37
2,021	30
2,022	23
Thereafter	92
Future minimum lease commitments	257
Less: Sublease rental income	(8)
Net future minimum lease commitments	$ 249
[1]	(1) Includes contingent rentals totaling $26 million for the year ended December 31, 2015

Regulatory Matters, Commitmen93

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Liabilities Related to Environmental Matters) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Environmental Remediation Obligations [Abstract]
Accrued Environmental Loss Contingencies, Current	$ 36	$ 26
Accrued Environmental Loss Contingencies, Noncurrent	314	283
Accrual for Environmental Loss Contingencies	$ 350	$ 309

Derivative assets and liabilt94

Derivative assets and liabilties (Outstanding commodity-related derivatives) (Details)		12 Months Ended
		Dec. 31, 2017MB_blsMWBBtu	Dec. 31, 2016barrelsMB_blsMWBBtuMMbtu
Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,018
Forward Swaps [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,018
Future [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,018
Natural Gas [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Notional Volume		4,700	52,653
Natural Gas [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,018
Natural Gas [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Short [Member]
Term Of Commodity Derivatives			2,017
Natural Gas [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,019
Natural Gas [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Short [Member]
Term Of Commodity Derivatives			2,019
Natural Gas [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Notional Volume		1,078
Natural Gas [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Notional Volume			683
Term Of Commodity Derivatives		2,018	2,017
Natural Gas [Member] | Fixed Swaps Futures [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Short [Member]
Notional Volume		39,770	36,370
Term Of Commodity Derivatives		2,018	2,017
Natural Gas [Member] | Forward Physical Contracts [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Notional Volume		145,105	22,492
Term Of Commodity Derivatives			2,017
Natural Gas [Member] | Forward Physical Contracts [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,018
Natural Gas [Member] | Forward Physical Contracts [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,020
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Long [Member]
Notional Volume		4,650	10,750
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,018
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Long [Member]
Term Of Commodity Derivatives			2,017
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,020
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Long [Member]
Term Of Commodity Derivatives			2,018
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Notional Volume	[1]	48,510	2,243
Term Of Commodity Derivatives			2,017
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,020
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Short [Member]
Notional Volume		39,770	36,370
Term Of Commodity Derivatives		2,018	2,017
Natural Gas [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Long [Member]
Notional Volume		87,253
Natural Gas [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Notional Volume			5,663
Term Of Commodity Derivatives			2,017
Natural Gas [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,018
Natural Gas [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,019
Natural Gas [Member] | Call Option [Member] | Mark to Market Derivatives [Member] | Trading [Member]
Term Of Commodity Derivatives		2,018
Natural Gas [Member] | Call Option [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Notional Volume		13,000	0
Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Long [Member]
Notional Volume		39,770	36,370
Term Of Commodity Derivatives		2,018	2,017
Power [Member] | Call Option [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Notional Volume | MW		137,600	186,400
Term Of Commodity Derivatives		2,018	2,017
Power [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Notional Volume | MW		435,960	391,880
Power [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,018
Power [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Minimum [Member] | Long [Member]
Term Of Commodity Derivatives			2,017
Power [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,019
Power [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Maximum [Member] | Long [Member]
Term Of Commodity Derivatives			2,018
Power [Member] | Future [Member] | Mark to Market Derivatives [Member] | Trading [Member]
Term Of Commodity Derivatives		2,018
Power [Member] | Future [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Notional Volume | MW			109,564
Power [Member] | Future [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Notional Volume | MW		25,760
Power [Member] | Future [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Minimum [Member] | Long [Member]
Term Of Commodity Derivatives			2,017
Power [Member] | Future [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Maximum [Member] | Long [Member]
Term Of Commodity Derivatives			2,018
Power [Member] | Put Option [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Term Of Commodity Derivatives			2,017
Power [Member] | Put Option [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Notional Volume | MW		153,600	50,400
Term Of Commodity Derivatives		2,018
WTI Crude Oil [Member] | Future [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Notional Volume | MB_bls		0	617
Term Of Commodity Derivatives			2,017
Natural Gas Liquids [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Long [Member]
Notional Volume | MB_bls		6,679
Natural Gas Liquids [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Notional Volume | barrels			5,787
Term Of Commodity Derivatives			2,017
Natural Gas Liquids [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,019
Refined Products [Member] | Future [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Notional Volume		3,783	2,240
Term Of Commodity Derivatives			2,017
Refined Products [Member] | Future [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,019
[1]	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Derivative assets and liabilt95

Derivative assets and liabilties (Interest rate swaps outstanding) (Details) - ETP [Member] - Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
December 2018 [Member]
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%
Notional amount outstanding		$ 1,200	$ 1,200
March 2019 [Member]
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
Notional amount outstanding		$ 300	300
Forward-Starting Swaps [Member] | July 2017 [Member]
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate
Notional amount outstanding	[2]	$ 0	500
Forward-Starting Swaps [Member] | July 2018 [Member]
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate
Notional amount outstanding	[2]	$ 300	200
Forward-Starting Swaps [Member] | July 2019 [Member]
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate
Notional amount outstanding	[2]	$ 300	200
Forward-Starting Swaps [Member] | July 2020 [Member]
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate
Notional amount outstanding	[2]	$ 400	$ 0
[1]	Floating rates are based on 3-month LIBOR.
[2]	Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

Derivative assets and liabilt96

Derivative assets and liabilties (Fair Value of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Total derivative assets	$ 320	$ 362
Total derivative liabilities	(557)	(666)
Derivative Asset, Fair Value, Net	37	20
Derivative Liability, Fair Value, Net	274	324
Designated as Hedging Instrument [Member]
Total derivative assets	14	0
Total derivative liabilities	(2)	(4)
Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) [Member]
Total derivative assets	14	0
Total derivative liabilities	(2)	(4)
Not Designated as Hedging Instrument [Member]
Total derivative assets	306	362
Total derivative liabilities	(555)	(662)
Not Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) [Member]
Total derivative assets	262	338
Total derivative liabilities	(281)	(416)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivative assets	44	24
Total derivative liabilities	(55)	(52)
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivative assets	0	0
Total derivative liabilities	(219)	(193)
Embedded Derivatives in Preferred Units [Member] | Not Designated as Hedging Instrument [Member]
Total derivative assets	0	0
Total derivative liabilities	$ 0	$ (1)

Derivative assets and liabilt97

Derivative assets and liabilties (Netting table) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 320	$ 362
Derivative Liability, Fair Value, Gross Liability	(557)	(666)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(20)	(4)
Derivative Liability, Fair Value, Amount Offset Against Collateral	20	4
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(263)	(338)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	263	338
Derivative Asset, Fair Value, Net	37	20
Derivative Liability, Fair Value, Net	(274)	(324)
Without offsetting agreements [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(219)	(194)
OTC Contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	44	24
Derivative Liability, Fair Value, Gross Liability	(55)	(52)
Broker cleared derivative contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	276	338
Derivative Liability, Fair Value, Gross Liability	$ (283)	$ (420)

Derivative assets and liabilt98

Derivative assets and liabilties (Partnership's derivative assets and liabilities, recognized OCI on derivatives (effective portion)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 26	$ 14	$ 21
Cost of Sales [Member] | Commodity [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 26	$ 14	$ 21

Derivative assets and liabilt99

Derivative assets and liabilties (Partnership's derivative assets and liabilities, amount of gain/(loss) reclassified from AOCI into income (effective portion)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Amount of Gain (Loss) Recognized in Income on Ineffective Portion	$ 26	$ 14	$ 21
Amount of Gain (Loss) Recognized In Income On Derivatives	(2)	(216)	6
Losses on interest rate derivatives	(37)	(12)	(18)
Embedded Derivatives in Preferred Units [Member] | Other Income (Expenses) [Member]
Amount of Gain (Loss) Recognized In Income On Derivatives	1	4	12
Commodity [Member] | Cost of Sales [Member]
Amount of Gain (Loss) Recognized in Income on Ineffective Portion	26	14	21
Trading [Member] | Commodity [Member] | Cost of Sales [Member]
Amount of Gain (Loss) Recognized In Income On Derivatives	31	(35)	(11)
Non Trading [Member] | Commodity [Member] | Cost of Sales [Member]
Amount of Gain (Loss) Recognized In Income On Derivatives	$ 3	$ (173)	$ 23

Retirement Benefits (Narratives

Retirement Benefits (Narratives) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	8.4
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Large Cap US Equitiies	100.00%	100.00%
2,018	$ 8
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Large Cap US Equitiies	48.00%
Fixed Income Securities	51.00%
Cash Fund Investments	1.00%
2,018	$ 10
ETP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to the 401(k) savings plan	38	$ 44	$ 39
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Large Cap US Equitiies		31.00%
Fixed Income Securities		66.00%
Cash Fund Investments		3.00%
Sunoco [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Liability, Other Postretirement Defined Benefit Plan, Noncurrent	$ 200
ETP Unit-Based Compensation Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Awards remaining unvested weighted average period, in years	2 years 8 months
Awards granted	$ 17.69	$ 23.82	$ 23.47
Unvested unit awards outstanding	14.1	9.4
Minimum [Member] | Equity [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage	0.25
Minimum [Member] | Fixed Income Investments [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage	0.65
Maximum [Member] | Equity [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage	0.35
Maximum [Member] | Fixed Income Investments [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage	0.75
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,018	$ 1

Retirement Benefits Obligations

Retirement Benefits Obligations and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Change in benefit obligation and Plan Assets:
Settlements	$ 0	$ 0
Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Interest cost	2	3
Benefit obligation		18
Fair value of plan assets	1	12
Amount underfunded		6
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position		(6)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax		0
Other Postretirement Benefit Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Defined Benefit Plan, Benefit Obligation, Benefits Paid	20	21
Interest cost	4	4
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	7	0
Actuarial (gain) loss and other	(1)	2
Benefits paid, net	20	21
Return on plan assets and other	11	6
Employer contributions	10	10
Benefit obligation	155	165	$ 180
Fair value of plan assets	249	248	253
Amount underfunded	(94)	(83)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	120	108
Current liabilities	(2)	(2)
Non-current liabilities	(24)	(23)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	94	83
Net actuarial gain	(17)	(12)
Prior service cost	20	14
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	3	2
Funded Plans [Member]
Change in benefit obligation and Plan Assets:
Settlements	(18)
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	1	18
Defined Benefit Plan, Benefit Obligation, Benefits Paid	2	1
Interest cost	1	1
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Actuarial (gain) loss and other	2	(2)
Benefits paid, net	2	1
Settlements		0
Return on plan assets and other	3	(2)
Employer contributions	6	0
Benefit obligation	1	18	20
Fair value of plan assets	1	12	15
Amount underfunded	0
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Current liabilities	0	0
Non-current liabilities	0	(6)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	0
Net actuarial gain	0	0
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	0
Unfunded Plans [Member]
Change in benefit obligation and Plan Assets:
Settlements	0	0
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	47	51
Defined Benefit Plan, Benefit Obligation, Benefits Paid	6	7
Interest cost	1	2
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Actuarial (gain) loss and other	1	(1)
Benefits paid, net	0	0
Return on plan assets and other	0	0
Employer contributions	0	0
Benefit obligation	47	51	57
Fair value of plan assets		0	$ 0
Amount underfunded	47	51
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Current liabilities	(8)	(7)
Non-current liabilities	(39)	(44)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	(47)	(51)
Net actuarial gain	5	0
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	5	0
Unfunded Plans [Member] | Change in Plan Assets [Member] | Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Fair value of plan assets	$ 0	$ 0

Retirement Benefits Summary for

Retirement Benefits Summary for Plans with an Accumulated Benefit Obligation in Excess of Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Accumulated Benefit Obligation	$ 155	$ 165
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Fair Value of Plan Assets	249	248
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	1	18
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Accumulated Benefit Obligation	1	18
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Fair Value of Plan Assets	1	12
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	47	51
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Accumulated Benefit Obligation	47	51
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Fair Value of Plan Assets	$ 0	$ 0

Retirement Benefits Components

Retirement Benefits Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	$ 2	$ 3
Expected return on plan assets	0	(1)
Prior service cost amortization	0	0
Net periodic benefit cost	2	2
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	4	4
Expected return on plan assets	(9)	(8)
Prior service cost amortization	2	1
Net periodic benefit cost	$ (3)	$ (3)

Retirement Benefits Weighted-Av

Retirement Benefits Weighted-Average Assumptions Used in Determining Benefit Obligations (Details)	Dec. 31, 2017	Dec. 31, 2016
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.27%	3.65%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.34%	2.34%

Retirement Benefits Assumed Hea

Retirement Benefits Assumed Health Care Cost Trend Rates (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year	7.20%	6.73%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	4.99%	4.96%
Defined Benefit Plan, Year Health Care Cost Trend Rate Reaches Ultimate Trend Rate	2,023	2,021

Retirement Benefits Schedule Of

Retirement Benefits Schedule Of Weighted-Average Assumptions To Determine Defined Benefit Plans And Postretirement Benefit Plans Expense (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.52%	3.60%
Expected long term return on assets, tax exempt accounts	3.50%	3.50%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.10%	3.06%
Expected long term return on assets, tax exempt accounts	7.00%	7.00%
Expected long term return on assets, taxable accounts	4.50%	4.50%

Retirement Benefits Fair Value

Retirement Benefits Fair Value of Plan Assets (Details) - USD ($) $ in Millions		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		$ 249	$ 248	$ 253
Large Cap US Equitiies		48.00%
Fixed Income Securities		51.00%
Cash Fund Investments		1.00%
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		$ 1	$ 12
Large Cap US Equitiies		100.00%	100.00%
Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		$ 33	$ 23
Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets	[1]	146	134
Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets	[2]	1	12
Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		70	91
Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		179	157
Fair Value, Inputs, Level 1 [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		1	12
Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		33	23
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		146	134
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		1	12
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		70	91
Fair Value, Inputs, Level 2 [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		70	91
Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 3 [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		$ 0	$ 0
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Large Cap US Equitiies			31.00%
Fixed Income Securities			66.00%
Cash Fund Investments			3.00%
[1]	Primarily comprised of approximately 48% equities, 51% fixed income securities and 1% cash as of December 31, 2017.
[2]	Comprised of approximately 100% equities as of December 31, 2017.

Retirement Benefits Expected Fu

Retirement Benefits Expected Future Benefit Payments (Details) $ in Millions	Dec. 31, 2017USD ($)
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,018	$ 24
2,019	23
2,020	21
2,021	19
2,022	17
2023 - 2027	37
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,018	10
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,018	8
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,018	8	[1]
2,019	6	[1]
2,020	6	[1]
2,021	5	[1]
2,022	4	[1]
2023 - 2027	$ 15	[1]
[1]	Expected benefit payments of funded pension plans are less than $1 million for the next ten years.

Related Party Transactions Rela

Related Party Transactions Related Party - Affiliated Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Affiliated revenues	$ 697	$ 377	$ 417

Related Party Transactions R110

Related Party Transactions Related Party - Affiliate AR and Affiliate AP (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Long-term notes payable – related company	$ 0	$ (250)
Accounts Receivable, Related Parties, Current	318	209
Accounts Payable, Related Parties, Current	209	43
Net Related Party Receivable (Payable)	85	(163)
ETE
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	0	22
FGT
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	11	15
Other
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	88	76
Accounts Payable, Related Parties, Current	14	23
Sunoco LP [Member]
Related Party Transaction [Line Items]
Notes Receivable, Related Parties, Noncurrent	85	87
Accounts Receivable, Related Parties, Current	219	96
Accounts Payable, Related Parties, Current	195	20
Phillips 66 Company [Member]
Related Party Transaction [Line Items]
Long-term notes payable – related company	$ 0	$ (250)

Reportable Segments (Narrative)

Reportable Segments (Narrative) (Details) - Sunoco LP [Member] - shares shares in Millions	Feb. 07, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Investments in and Advances to Affiliates, Balance, Shares		43.5
Equity Method Investment, Ownership Percentage		43.60%
Subsequent Event [Member]
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	31.80%

Reportable Segments (Segment Ad

Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Adjusted EBITDA	$ 6,712	$ 5,733	$ 5,517
Depreciation, depletion and amortization	(2,332)	(1,986)	(1,929)
Interest expense, net	(1,365)	(1,317)	(1,291)
Gains on acquisitions	0	(83)	0
Impairment losses	920	813	339
Impairment losses	(793)	(670)
Losses on interest rate derivatives	(37)	(12)	(18)
Non-cash unit-based compensation expense	(74)	(80)	(79)
Unrealized gains (losses) on commodity risk management activities	56	(131)	(65)
Inventory valuation adjustments	0	0	58
Losses on extinguishments of debt	(42)	0	(43)
Adjusted EBITDA related to unconsolidated affiliates	(984)	(946)	(937)
Equity in earnings from unconsolidated affiliates	156	59	469
Impairment of investments in unconsolidated affiliates	313	308	0
Other, net	148	115	23
INCOME BEFORE INCOME TAX BENEFIT	1,005	397	1,366
Intrastate Transportation And Storage [Member]
Segment Adjusted EBITDA	626	613	543
Depreciation, depletion and amortization	(147)	(144)	(129)
Impairment losses	0	0
Equity in earnings from unconsolidated affiliates	(156)	35	32
Interstate Transportation and Storage [Member]
Segment Adjusted EBITDA	1,098	1,117	1,155
Depreciation, depletion and amortization	(214)	(207)	(210)
Impairment losses	262	638	(99)
Equity in earnings from unconsolidated affiliates	236	193	197
Midstream [Member]
Segment Adjusted EBITDA	1,481	1,133	1,237
Depreciation, depletion and amortization	(954)	(840)	(720)
Impairment losses	0	32
Equity in earnings from unconsolidated affiliates	20	19	(19)
NGL and refined products transportation and services [Member]
Segment Adjusted EBITDA	1,641	1,496	1,179
Depreciation, depletion and amortization	(401)	(355)	(290)
Impairment losses	79	0	(106)
Equity in earnings from unconsolidated affiliates	33	41	29
Crude oil transportation and services [Member]
Segment Adjusted EBITDA	1,379	834	521
Depreciation, depletion and amortization	(402)	(251)	(218)
Impairment losses	0	0
Equity in earnings from unconsolidated affiliates	4	(4)	(9)
Other Segments [Member]
Segment Adjusted EBITDA	487	540	882
Depreciation, depletion and amortization	(214)	(189)	(362)
Impairment losses	452	0
Equity in earnings from unconsolidated affiliates	$ 19	$ (225)	$ 239

Reportable Segments (Financial

Reportable Segments (Financial Information by Segment) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Advances to and investments in unconsolidated affiliates	$ 3,816				$ 4,280				$ 3,816	$ 4,280	$ 5,003
Property, Plant and Equipment, Additions									5,901	5,810	8,167
Total assets	77,965				70,105				77,965	70,105	65,128
Equity in earnings from unconsolidated affiliates									156	59	469
Depreciation, depletion and amortization									2,332	1,986	1,929
Cost of products sold (see Note 3)									20,801	15,080	26,714
Revenues	8,610	$ 6,973	$ 6,576	$ 6,895	6,526	$ 5,531	$ 5,289	$ 4,481	29,054	21,827	34,292
Intrastate Transportation And Storage [Member]
Advances to and investments in unconsolidated affiliates	85				399				85	399	406
Property, Plant and Equipment, Additions									175	76	105
Total assets	5,020				5,176				5,020	5,176	4,882
Equity in earnings from unconsolidated affiliates									(156)	35	32
Depreciation, depletion and amortization									147	144	129
Cost of products sold (see Note 3)									2,327	1,897	1,554
Revenues									3,083	2,613	2,250
Interstate Transportation and Storage [Member]
Advances to and investments in unconsolidated affiliates	2,118				2,149				2,118	2,149	2,516
Property, Plant and Equipment, Additions									726	280	866
Total assets	13,518				10,833				13,518	10,833	11,345
Equity in earnings from unconsolidated affiliates									236	193	197
Depreciation, depletion and amortization									214	207	210
Revenues									934	969	1,025
Midstream [Member]
Advances to and investments in unconsolidated affiliates	126				111				126	111	117
Property, Plant and Equipment, Additions									1,308	1,255	2,174
Total assets	20,004				17,873				20,004	17,873	17,039
Equity in earnings from unconsolidated affiliates									20	19	(19)
Depreciation, depletion and amortization									954	840	720
Cost of products sold (see Note 3)									4,761	3,381	3,264
Revenues									6,943	5,179	5,056
NGL and refined products transportation and services [Member]
Advances to and investments in unconsolidated affiliates	234				235				234	235	258
Property, Plant and Equipment, Additions									2,971	2,198	2,853
Total assets	17,600				14,074				17,600	14,074	11,568
Equity in earnings from unconsolidated affiliates									33	41	29
Depreciation, depletion and amortization									401	355	290
Cost of products sold (see Note 3)									6,508	4,553	3,431
Revenues									8,648	6,409	4,997
Crude oil transportation and services [Member]
Advances to and investments in unconsolidated affiliates	22				18				22	18	21
Property, Plant and Equipment, Additions									453	1,841	1,358
Total assets	17,736				15,909				17,736	15,909	10,941
Equity in earnings from unconsolidated affiliates									4	(4)	(9)
Depreciation, depletion and amortization									402	251	218
Cost of products sold (see Note 3)									9,826	6,416	8,158
Revenues									11,703	7,539	8,980
Other Segments [Member]
Advances to and investments in unconsolidated affiliates	1,231				1,368				1,231	1,368	1,685
Property, Plant and Equipment, Additions									268	160	811
Total assets	$ 4,087				$ 6,240				4,087	6,240	9,353
Equity in earnings from unconsolidated affiliates									19	(225)	239
Depreciation, depletion and amortization									214	189	362
Cost of products sold (see Note 3)									2,509	2,942	14,029
Revenues									2,901	3,272	15,774
Intersegment Eliminations [Member]
Cost of products sold (see Note 3)									(5,130)	(4,109)	(3,722)
Revenues									(5,158)	(4,154)	(3,790)
External Customers [Member] | Intrastate Transportation And Storage [Member]
Revenues									2,891	2,155	1,912
External Customers [Member] | Interstate Transportation and Storage [Member]
Revenues									915	946	1,008
External Customers [Member] | Midstream [Member]
Revenues									2,510	2,342	2,607
External Customers [Member] | NGL and refined products transportation and services [Member]
Revenues									8,326	5,973	4,569
External Customers [Member] | Crude oil transportation and services [Member]
Revenues									11,672	7,539	8,980
External Customers [Member] | Other Segments [Member]
Revenues									2,740	2,872	15,216
Intersegment [Member] | Intrastate Transportation And Storage [Member]
Revenues									192	458	338
Intersegment [Member] | Interstate Transportation and Storage [Member]
Revenues									19	23	17
Intersegment [Member] | Midstream [Member]
Revenues									4,433	2,837	2,449
Intersegment [Member] | NGL and refined products transportation and services [Member]
Revenues									322	436	428
Intersegment [Member] | Crude oil transportation and services [Member]
Revenues									31	0	0
Intersegment [Member] | Other Segments [Member]
Revenues									$ 161	$ 400	$ 558

Quarterly Financial Data Qarter

Quarterly Financial Data Qarterly Financial Data Table(Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Revenues	$ 8,610	$ 6,973	$ 6,576	$ 6,895	$ 6,526	$ 5,531	$ 5,289	$ 4,481	$ 29,054	$ 21,827	$ 34,292
Operating income	199	779	736	683	(139)	594	708	598	2,397	1,761	2,227
Net income	1,097	715	296	393	(336)	94	465	360	2,501	583	1,489
Common Unitholders’ interest in net income (loss)	$ 668	$ 335	$ (49)	$ 32	$ (754)	$ (252)	$ 58	$ (71)	$ 986	$ (1,019)	$ (27)
Basic net income (loss) per Common Unit	$ 0.57	$ 0.29	$ (0.04)	$ 0.03	$ (0.97)	$ (0.34)	$ 0.06	$ (0.11)	$ 0.94	$ (1.38)	$ (0.07)
Diluted net income (loss) per Common Unit	$ 0.57	$ 0.29	$ (0.04)	$ 0.03	$ (0.97)	$ (0.34)	$ 0.06	$ (0.11)	$ 0.93	$ (1.38)	$ (0.08)

Quarterly Financial Data Quarte

Quarterly Financial Data Quarterly Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Inventory Valuation Reserves	$ 0	$ 0	$ (58)
Impairment losses	920	813	339
Impairment losses	793	670
Impairment of investments in unconsolidated affiliates	$ 313	$ 308	$ 0

Guarantor Financial Informat116

Guarantor Financial Information (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Training Section [Abstract]
Net Cash Provided by (Used in) Operating Activities									$ 4,485	$ 3,303	$ 2,747
Revenues	$ 8,610	$ 6,973	$ 6,576	$ 6,895	$ 6,526	$ 5,531	$ 5,289	$ 4,481	29,054	21,827	34,292
Cash and cash equivalents	306				360				306	360	527	$ 663
Other current assets	210				298				210	298
Property, Plant and Equipment, Net	58,437				50,917				58,437	50,917
Advances to and investments in unconsolidated affiliates	3,816				4,280				3,816	4,280	5,003
Other non-current assets, net	758				672				758	672
Assets	77,965				70,105				77,965	70,105	65,128
Liabilities, Current	6,994				6,203				6,994	6,203
Noncontrolling interest	5,882				7,820				5,882	7,820
Partners' Capital	28,269				18,621				28,269	18,621	20,824
Liabilities and Equity	77,965				70,105				77,965	70,105
Costs and Expenses									26,657	20,066	32,065
Operating Income (Loss)	199	779	736	683	(139)	594	708	598	2,397	1,761	2,227
Interest Expense									(1,365)	(1,317)	(1,291)
Equity in earnings from unconsolidated affiliates									156	59	469
Impairment of investments in unconsolidated affiliates									(313)	(308)	0
Losses on extinguishments of debt									(42)	0	(43)
Losses on interest rate derivatives									(37)	(12)	(18)
Other, net									209	131	22
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest									1,005	397	1,366
Income tax benefit									(1,496)	(186)	(123)
Net income	1,097	$ 715	$ 296	$ 393	(336)	$ 94	$ 465	$ 360	2,501	583	1,489
Less: Net income attributable to noncontrolling interest									420	295	134
Net Income (Loss) Attributable to Parent									2,081	288	1,389
Other Comprehensive Income (Loss), Net of Tax									(5)	4	60
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest									2,496	587	1,549
Less: Comprehensive income attributable to noncontrolling interest									420	295	134
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									2,076	292	1,449
Net Cash Provided by (Used in) Investing Activities									(5,473)	(6,390)	(7,820)
Net Cash Provided by (Used in) Financing Activities									934	2,920	4,937
Cash and Cash Equivalents, Period Increase (Decrease)									(54)	(167)	(136)
Pro Forma [Member]
Training Section [Abstract]
Net Cash Provided by (Used in) Operating Activities									4,485	3,303	2,747
Revenues									29,054	21,827	34,292
Cash and cash equivalents	306				360				306	360	527	663
Other current assets	6,222				5,283				6,222	5,283
Property, Plant and Equipment, Net	58,437				50,917				58,437	50,917
Advances to and investments in unconsolidated affiliates	3,816				4,280				3,816	4,280
Other non-current assets, net	9,184				9,265				9,184	9,265
Assets	77,965				70,105				77,965	70,105
Liabilities, Current	6,994				6,203				6,994	6,203
Liabilities, Noncurrent	36,820				37,461				36,820	37,461
Noncontrolling interest	5,882				1,232				5,882	1,232
Partners' Capital	28,269				25,209				28,269	25,209
Liabilities and Equity	77,965				70,105				77,965	70,105
Costs and Expenses									26,657	20,066	32,065
Operating Income (Loss)									2,397	1,761	2,227
Interest Expense									(1,365)	(1,317)	(1,291)
Equity in earnings from unconsolidated affiliates									156	59	469
Impairment of investments in unconsolidated affiliates									(313)	(308)
Losses on interest rate derivatives									(37)	(12)	(18)
Other, net									167	214	(21)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest									1,005	397	1,366
Income tax benefit									(1,496)	(186)	(123)
Net income									2,501	583	1,489
Less: Net income attributable to noncontrolling interest									420	41	53
Net Income (Loss) Attributable to Parent									2,081	542	1,436
Other Comprehensive Income (Loss), Net of Tax									(5)	4	60
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest									2,496	587	1,549
Less: Comprehensive income attributable to noncontrolling interest									420	41	53
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									2,076	546	1,496
Net Cash Provided by (Used in) Investing Activities									(5,473)	(6,390)	(7,820)
Net Cash Provided by (Used in) Financing Activities									934	2,920	4,937
Cash and Cash Equivalents, Period Increase (Decrease)									(54)	(167)	(136)
Non-Guarantor Subsidiaries [Member] | Pro Forma [Member]
Training Section [Abstract]
Net Cash Provided by (Used in) Operating Activities									4,681	3,492	2,886
Revenues									29,054	21,827	34,292
Cash and cash equivalents	309				319				309	319	490	562
Other current assets	6,063				5,281				6,063	5,281
Property, Plant and Equipment, Net	58,437				50,917				58,437	50,917
Advances to and investments in unconsolidated affiliates	3,816				4,280				3,816	4,280
Other non-current assets, net	9,184				9,260				9,184	9,260
Assets	77,809				70,057				77,809	70,057
Liabilities, Current	12,150				11,764				12,150	11,764
Liabilities, Noncurrent	7,609				30,148				7,609	30,148
Noncontrolling interest	5,882				1,232				5,882	1,232
Partners' Capital	52,168				26,913				52,168	26,913
Liabilities and Equity	77,809				70,057				77,809	70,057
Costs and Expenses									26,656	20,065	32,064
Operating Income (Loss)									2,398	1,762	2,228
Interest Expense									(1,209)	(1,160)	(1,158)
Equity in earnings from unconsolidated affiliates									156	59	469
Impairment of investments in unconsolidated affiliates									(313)	(308)
Losses on interest rate derivatives									(37)	(12)	(18)
Other, net									168	214	(21)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest									1,163	555	1,500
Income tax benefit									(1,496)	(186)	(123)
Net income									2,659	741	1,623
Less: Net income attributable to noncontrolling interest									420	41	53
Net Income (Loss) Attributable to Parent									2,239	700	1,570
Other Comprehensive Income (Loss), Net of Tax									(5)	4	60
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest									2,654	745	1,683
Less: Comprehensive income attributable to noncontrolling interest									420	41	53
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									2,234	704	1,630
Net Cash Provided by (Used in) Investing Activities									(5,672)	(4,431)	(5,702)
Net Cash Provided by (Used in) Financing Activities									981	768	2,744
Cash and Cash Equivalents, Period Increase (Decrease)									(10)	(171)	(72)
Subsidiary Issuer [Member] | Pro Forma [Member]
Training Section [Abstract]
Net Cash Provided by (Used in) Operating Activities									1,047	675	388
Revenues									0	0	0
Cash and cash equivalents	(3)				41				(3)	41	37	101
Other current assets	159				2				159	2
Property, Plant and Equipment, Net	0				0				0	0
Advances to and investments in unconsolidated affiliates	11,648				10,664				11,648	10,664
Other non-current assets, net	0				5				0	5
Assets	11,804				10,712				11,804	10,712
Liabilities, Current	(3,660)				(3,800)				(3,660)	(3,800)
Liabilities, Noncurrent	7,607				7,313				7,607	7,313
Noncontrolling interest	0				0				0	0
Partners' Capital	7,857				7,199				7,857	7,199
Liabilities and Equity	11,804				10,712				11,804	10,712
Costs and Expenses									1	1	1
Operating Income (Loss)									(1)	(1)	(1)
Interest Expense									(156)	(157)	(133)
Equity in earnings from unconsolidated affiliates									1,242	863	526
Impairment of investments in unconsolidated affiliates									0	0
Losses on interest rate derivatives									0	0	0
Other, net									0	0	0
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest									1,085	705	392
Income tax benefit									0	0	0
Net income									1,085	705	392
Less: Net income attributable to noncontrolling interest									0	0	0
Net Income (Loss) Attributable to Parent									1,085	705	392
Other Comprehensive Income (Loss), Net of Tax									0	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest									1,085	705	392
Less: Comprehensive income attributable to noncontrolling interest									0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									1,085	705	392
Net Cash Provided by (Used in) Investing Activities									(1,368)	(2,400)	(1,815)
Net Cash Provided by (Used in) Financing Activities									277	1,729	1,363
Cash and Cash Equivalents, Period Increase (Decrease)									(44)	4	(64)
Adjustments And Eliminations [Member] | Pro Forma [Member]
Training Section [Abstract]
Net Cash Provided by (Used in) Operating Activities									(3,807)	(1,417)	(1,968)
Revenues									0	0	0
Cash and cash equivalents	0				0				0	0	0	0
Other current assets	0				0				0	0
Property, Plant and Equipment, Net	0				0				0	0
Advances to and investments in unconsolidated affiliates	(60,026)				(34,014)				(60,026)	(34,014)
Other non-current assets, net	0				0				0	0
Assets	(60,026)				(34,014)				(60,026)	(34,014)
Liabilities, Current	0				0				0	0
Liabilities, Noncurrent	0				(299)				0	(299)
Noncontrolling interest	0				0				0	0
Partners' Capital	(60,026)				(33,715)				(60,026)	(33,715)
Liabilities and Equity	(60,026)				(34,014)				(60,026)	(34,014)
Costs and Expenses									0	0	0
Operating Income (Loss)									0	0	0
Interest Expense									0	0	0
Equity in earnings from unconsolidated affiliates									(3,806)	(1,417)	(1,967)
Impairment of investments in unconsolidated affiliates									0	0
Losses on interest rate derivatives									0	0	0
Other, net									(1)	0	0
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest									(3,807)	(1,417)	(1,967)
Income tax benefit									0	0	0
Net income									(3,807)	(1,417)	(1,967)
Less: Net income attributable to noncontrolling interest									0	0	0
Net Income (Loss) Attributable to Parent									(3,807)	(1,417)	(1,967)
Other Comprehensive Income (Loss), Net of Tax									0	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest									(3,807)	(1,417)	(1,967)
Less: Comprehensive income attributable to noncontrolling interest									0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									(3,807)	(1,417)	(1,967)
Net Cash Provided by (Used in) Investing Activities									3,807	1,417	1,968
Net Cash Provided by (Used in) Financing Activities									0	0	0
Cash and Cash Equivalents, Period Increase (Decrease)									0	0	0
Parent Guarantor [Member] | Pro Forma [Member]
Training Section [Abstract]
Net Cash Provided by (Used in) Operating Activities									2,564	553	1,441
Revenues									0	0	0
Cash and cash equivalents	0				0				0	0	0	$ 0
Other current assets	0				0				0	0
Property, Plant and Equipment, Net	0				0				0	0
Advances to and investments in unconsolidated affiliates	48,378				23,350				48,378	23,350
Other non-current assets, net	0				0				0	0
Assets	48,378				23,350				48,378	23,350
Liabilities, Current	(1,496)				(1,761)				(1,496)	(1,761)
Liabilities, Noncurrent	21,604				299				21,604	299
Noncontrolling interest	0				0				0	0
Partners' Capital	28,270				24,812				28,270	24,812
Liabilities and Equity	$ 48,378				$ 23,350				48,378	23,350
Costs and Expenses									0	0	0
Operating Income (Loss)									0	0	0
Interest Expense									0	0	0
Equity in earnings from unconsolidated affiliates									2,564	554	1,441
Impairment of investments in unconsolidated affiliates									0	0
Losses on interest rate derivatives									0	0	0
Other, net									0	0	0
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest									2,564	554	1,441
Income tax benefit									0	0	0
Net income									2,564	554	1,441
Less: Net income attributable to noncontrolling interest									0	0	0
Net Income (Loss) Attributable to Parent									2,564	554	1,441
Other Comprehensive Income (Loss), Net of Tax									0	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest									2,564	554	1,441
Less: Comprehensive income attributable to noncontrolling interest									0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									2,564	554	1,441
Net Cash Provided by (Used in) Investing Activities									(2,240)	(976)	(2,271)
Net Cash Provided by (Used in) Financing Activities									(324)	423	830
Cash and Cash Equivalents, Period Increase (Decrease)									$ 0	$ 0	$ 0