Energy Transfer (ET) 8-K 2 Oct 17 2016 FY Management’s Discussion and Analysis of Financial Condition and Results of Operations Financial data

Document and Entity Information

Document and Entity Information Document	12 Months Ended
	Dec. 31, 2016
Entity Information [Line Items]
Entity Registrant Name	Energy Transfer Equity, L.P.
Entity Central Index Key	1,276,187
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	8-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
ASSETS
Cash and cash equivalents	$ 463	$ 581
Accounts receivable, net	3,557	2,400
Accounts receivable from related companies	47	119
Inventories	2,103	1,465
Derivative assets	21	46
Other current assets	503	593
Disposal Group, Including Discontinued Operation, Assets, Current	291	206
Total current assets	6,985	5,410
Property, plant and equipment	61,158	52,851
Accumulated depreciation and depletion	(7,905)	(6,067)
Property, Plant and Equipment, Net	53,253	46,784
Advances to and investments in unconsolidated affiliates	3,040	3,462
Goodwill	5,170	5,485
Disposal Group, Including Discontinued Operation, Assets, Noncurrent	4,258	4,441
Intangible assets, net	5,489	4,896
Other non-current assets, net	816	711
Total assets	79,011	71,189
LIABILITIES AND EQUITY
Accounts payable	3,502	2,274
Accounts payable to related companies	42	28
Exchanges payable	208	106
Derivative liabilities	172	69
Accrued and other current liabilities	2,367	2,408
Current maturities of long-term debt	1,194	131
Total current liabilities	7,277	4,910
Long-term debt, less current maturities	42,608	36,837
Long-term notes payable - related companies	250	0
Deferred income taxes	5,112	4,590
Non-current derivative liabilities	76	137
Other non-current liabilities	1,055	1,002
Disposal Group, Including Discontinued Operation, Liabilities	68	67
Commitments and contingencies
Redeemable noncontrolling interests	15	15
PREFERRED UNITS OF SUBSIDIARY (Note 7)	33	33
Partners' Capital
General Partner	(3)	(2)
Limited Partners:
Common Unitholders (1,046,947,157 and 1,044,767,336 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively)	(1,871)	(952)
Class D Units (2,156,000 units authorized, issued and outstanding as of December 31, 2015)	0	22
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016)	180	0
Total partners’ deficit	(1,694)	(932)
Noncontrolling interest	24,211	24,530
Total equity	22,517	23,598
Total liabilities and equity	$ 79,011	$ 71,189

Consolidated Balance Sheets Bal

Consolidated Balance Sheets Balance Sheet (Paranthetical) - shares	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Authorized	1,046,947,157	1,044,767,336
Issued	1,046,947,157	1,044,767,336
Outstanding	1,046,947,157	1,044,767,336	1,077,500,000	1,119,800,000
Preferred Units, Authorized	329,299,267	0
Preferred Units, Issued	329,299,267	0
Preferred Units, Outstanding	329,299,267	0
Class D Units [Member]
Class of Stock [Line Items]
Authorized	0	2,156,000
Issued	0	2,156,000
Outstanding	0	2,156,000

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Gains on acquisitions	$ 83	$ 0	$ 0
REVENUES:
Natural gas sales	3,619	3,671	5,386
NGL sales	4,841	3,935	5,845
Crude sales	6,766	8,378	16,416
Gathering, transportation and other fees	4,172	4,200	3,733
Refined product sales	8,896	9,933	17,068
Other	1,808	4,087	4,191
Total revenues	30,102	34,204	52,639
COSTS AND EXPENSES:
Cost of products sold	22,636	27,435	45,861
Operating expenses	1,727	1,728	1,811
Depreciation, depletion and amortization	2,166	1,904	1,669
Selling, general and administrative	693	548	556
Impairment losses	970	339	370
Total costs and expenses	28,192	31,954	50,267
OPERATING INCOME	1,910	2,250	2,372
OTHER INCOME (EXPENSE):
Interest expense, net	(1,803)	(1,621)	(1,368)
Equity in earnings from unconsolidated affiliates	270	276	332
Impairment of investment in an unconsolidated affiliate	(308)	0	0
Gains on acquisitions	83	0	0
Gain on sale of AmeriGas common units	0	0	177
Losses on extinguishments of debt	0	(43)	(25)
Losses on interest rate derivatives	(12)	(18)	(157)
Other, net	132	20	(12)
Income from continuing operations before income tax expense	272	864	1,319
Income tax expense (benefit) from continuing operations	(248)	(148)	325
INCOME FROM CONTINUING OPERATIONS	520	1,012	994
Income (loss) from discontinued operations, net of income taxes	(479)	81	130
NET INCOME	41	1,093	1,124
Less: Net income (loss) attributable to noncontrolling interest	(954)	(96)	491
NET INCOME ATTRIBUTABLE TO PARTNERS	995	1,189	633
General Partner’s interest in net income	3	3	2
Convertible Unitholders’ interest in income	9	0	0
Class D Unitholder’s interest in net income	0	3	2
Limited Partners’ interest in net income	$ 983	$ 1,183	$ 629
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT (USD $ per unit):
Basic	$ 0.95	$ 1.11	$ 0.57
Diluted	0.93	1.11	0.57
NET INCOME PER LIMITED PARTNER UNIT (USD $ per Unit):
Basic	0.94	1.11	0.58
Diluted	$ 0.92	$ 1.11	$ 0.58

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net income	$ 41	$ 1,093	$ 1,124
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	0	0	3
Change in value of available-for-sale securities	2	(3)	1
Actuarial gain (loss) relating to pension and other postretirement benefits	(1)	65	(113)
Foreign currency translation adjustment	(1)	(1)	(2)
Change in other comprehensive income from unconsolidated affiliates	4	(1)	(6)
Other comprehensive income (loss), net of tax, total	4	60	(117)
Comprehensive income	45	1,153	1,007
Less: Comprehensive income (loss) attributable to noncontrolling interest	(950)	(41)	388
Comprehensive income attributable to partners	$ 995	$ 1,194	$ 619

Consolidated Statement Of Equit

Consolidated Statement Of Equity - USD ($) $ in Millions	Total	General Partner [Member]	Limited Partner [Member]	Class D Units [Member]	Series A Convertible Preferred Units [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2013	$ 16,279	$ (3)	$ 1,066	$ 6	$ 0	$ 9	$ 15,201
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(821)	(2)	(817)	(2)	0	0	0
Distributions to noncontrolling interest	(1,905)	0	0	0	0	0	(1,905)
Subsidiary unit transactions | Subsidiary units issued in certain acquisitions [Member]	5,815	0	211	0	0	0	5,604
Subsidiary unit transactions | Subsidiary units issued to Parent [Member]	0	0	99	0	0	0	99
Subsidiary unit transactions | Subsidiary units issued for cash [Member]	3,057	0	148	2	0	0	2,907
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests | Lake Charles LNG Transaction [Member]	0	2	480	0	0	0	(482)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	(319)	0	0	0	0	0	(319)
Capital contributions received from noncontrolling interest	139	0	0	0	0	0	139
Non-cash compensation expense, net of units tendered by employees for tax withholdings	65	0	0	14	0	0	51
Other, net	(3)	0	30	0	0	0	(33)
Units repurchased under buyback program	(1,000)	0	(1,000)	0	0	0	0
Other comprehensive income, net of tax	(117)	0	0	0	0	(14)	(103)
Net income	1,124	2	629	2	0	0	491
Balance at Dec. 31, 2014	22,314	(1)	648	22	0	(5)	21,650
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(1,090)	(3)	(1,084)	(3)	0	0	0
Distributions to noncontrolling interest	(2,335)	0	0	0	0	0	(2,335)
Subsidiary unit transactions	3,889	1	(524)	(1)	0	0	4,415
Capital contributions received from noncontrolling interest	875	0	0	0	0	0	875
Non-cash compensation expense, net of units tendered by employees for tax withholdings	70	0	0	8	0	0	62
Other, net	(149)	0	(118)	0	0	0	(31)
Units repurchased under buyback program	(1,064)	0	(1,064)	0	0	0	0
Issuance of common units	0	0	7	(7)	0	0	0
Acquisition and disposition of noncontrolling interest	(65)	0	0	0	0	0	(65)
Other comprehensive income, net of tax	60	0	0	0	0	5	55
Net income	1,093	3	1,183	3	0	0	(96)
Balance at Dec. 31, 2015	23,598	(2)	(952)	22	0	0	24,530
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(1,022)	(3)	(1,019)	0	0	0	0
Distributions to noncontrolling interest	(2,795)	0	0	0	0	0	(2,795)
Distributions reinvested	0	0	(173)	0	173	0	0
Subsidiary unit transactions | Subsidiary units issued in certain acquisitions [Member]	307	0	0	0	0	0	307
Subsidiary unit transactions | Subsidiary units issued for cash [Member]	2,559	0	0	0	0	0	2,559
Capital contributions received from noncontrolling interest	236	0	0	0	0	0	236
Non-cash compensation expense, net of units tendered by employees for tax withholdings	52	0	0	(22)	0	0	74
Other, net	43	(1)	30	0	0	0	14
Issuance of common units	37	0	39		(2)	0	0
Acquisition and disposition of noncontrolling interest	(779)	0	(779)	0	0	0	0
Partners' Capital Account, Acquisitions	(236)	0	0	0	0	0	236
Other comprehensive income, net of tax	4	0	0	0	0	0	4
Net income	41	3	983	0	9	0	(954)
Balance at Dec. 31, 2016	$ 22,517	$ (3)	$ (1,871)	$ 0	$ 180	$ 0	$ 24,211

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 41	$ 1,093	$ 1,124
Reconciliation of net income to net cash provided by operating activities:
Income (loss) from discontinued operations, net of income taxes	479	(81)	(130)
Depreciation, depletion and amortization	2,166	1,904	1,669
Deferred income taxes	(225)	221	(4)
Amortization included in interest expense	3	(21)	(51)
Unit-based compensation expense	70	91	82
Impairment losses	970	339	370
Gains on acquisitions	(83)	0	0
Gain on sale of AmeriGas common units	0	0	(177)
Losses on extinguishments of debt	0	43	25
Impairment of investment in an unconsolidated affiliate	308	0	0
(Gains) losses on disposal of assets	2	(6)	0
Equity in earnings of unconsolidated affiliates	(270)	(276)	(332)
Distributions from unconsolidated affiliates	268	409	291
Inventory valuation adjustments	(267)	229	445
Other non-cash	(229)	(8)	(89)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	36	(1,032)	(338)
Net cash provided by operating activities	3,269	2,905	2,885
INVESTING ACTIVITIES:
Proceeds from sale of noncontrolling interest	0	64	0
Proceeds from the sale of AmeriGas common units	0	0	814
Cash paid for acquisitions, net of cash received	(1,398)	(777)	(2,367)
Cash paid for acquisition of a noncontrolling interest	0	(129)	0
Capital expenditures, excluding allowance for equity funds used during construction	(7,719)	(9,021)	(5,369)
Contributions in aid of construction costs	71	80	45
Contributions to unconsolidated affiliates	(68)	(45)	(334)
Distributions from unconsolidated affiliates in excess of cumulative earnings	135	128	136
Proceeds from the sale of other assets	35	14	54
Change in restricted cash	14	19	172
Other	0	(16)	(19)
Net cash used in investing activities	(8,930)	(9,683)	(6,868)
FINANCING ACTIVITIES:
Proceeds from borrowings	25,785	26,455	18,375
Repayments of long-term debt	(19,076)	(19,828)	(13,886)
Cash received from affiliate notes	5,317	0	0
Cash paid on affiliate notes	(5,051)	0	0
Subsidiary units issued for cash	2,559	3,889	3,057
Distributions to partners	(1,022)	(1,090)	(821)
Distributions to noncontrolling interests	(2,766)	(2,335)	(1,905)
Debt issuance costs	(52)	(75)	(77)
Capital contributions from noncontrolling interest	0	(34)	0
Capital contributions from noncontrolling interest	236	841	139
Units repurchased under buyback program	0	(1,064)	(1,000)
Other, net	(3)	(8)	(5)
Net cash provided by financing activities	5,927	6,785	3,877
Cash Provided by (Used in) Operating Activities, Discontinued Operations	146	162	290
Cash Provided by (Used in) Investing Activities, Discontinued Operations	(535)	(410)	74
Increase (Decrease) in Assets Held-for-sale	5	(14)	(1)
Net Cash Provided by (Used in) Discontinued Operations	(384)	(262)	363
Increase (decrease) in cash and cash equivalents	(118)	(255)	257
Cash and cash equivalents, beginning of period	581	836	579
Cash and cash equivalents, end of period	$ 463	$ 581	$ 836

Operations And Organization

Operations And Organization	12 Months Ended
	Dec. 31, 2016
Operations And Organization [Abstract]
Operations And Organization	OPERATIONS AND ORGANIZATION : Financial Statement Presentation The consolidated financial statements of Energy Transfer Equity, L.P. (the “Partnership,” “we” or “ETE”) presented herein for the years ended December 31, 2016, 2015, and 2014 , have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, ETE Common Holdings, LLC, Panhandle (or Southern Union prior to its merger into Panhandle in January 2014), Sunoco Logistics, Sunoco LP and ETP Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis. As discussed in Note 8 , in January 2014 and July 2015, the Partnership completed two-for-one splits of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effects of the unit splits for all periods presented. The historical common units for ETP 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, defined below. At December 31, 2016 , our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as 3.9 million ETP common units, 81.0 million ETP Class H units and 2.3 million Sunoco LP common units held by us or our wholly-owned subsidiaries. We also own 0.1% of Sunoco Partners LLC, the entity that owns the general partner interest and IDRs of Sunoco Logistics, while ETP owns the remaining 99.9% of Sunoco Partners LLC. Additionally, ETE owns 100 ETP Class I Units, the distributions from which offset a portion of IDR subsidies ETE has previously provided to ETP. In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P. Under the terms of the transaction, the unitholders received 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit 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. Based on the number of Energy Transfer Partners, L.P. common units outstanding at the closing of the merger, Sunoco Logistics issued approximately 832 million Sunoco Logistics common units to Energy Transfer Partners, L.P. unitholders. In connection with the merger, the Energy Transfer Partners, L.P. Class H units were cancelled. The outstanding Energy Transfer Partners, L.P. 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 Energy Transfer Partners, L.P. 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 Energy Transfer Partners, L.P. at the effective time of the merger were cancelled. Prior to the Sunoco Logistics Merger, ETE owned 18.4 million Energy Transfer Partners, L.P. common units (representing 3.3% of the total outstanding common units), 81 million Energy Transfer Partners, L.P. Class H units and 100 Energy Transfer Partners, L.P. Class I units. In connection with the Sunoco Logistics Merger, the Class H units were cancelled, and ETE now owns 27.5 million ETP common units (representing 2.5% of the total outstanding common units) and 100 ETP Class I units. The ETP Class I units have the same rights, privileges, duties and obligations as those historically associated with the Class I units prior to the Sunoco Logistics Merger. At the time of 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.” Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. For purposes of maintaining clarity, the following references are used herein: • References to “ETLP” refer to the entity named 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 consolidated financial statements of ETE presented herein include the results of operations of: • the Parent Company; • our controlled subsidiaries, ETP and Sunoco LP; • consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that own general partner interests and IDR interests in ETP and Sunoco LP; and • our wholly-owned subsidiary, Lake Charles LNG. Our subsidiaries also own 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, we apply proportionate consolidation for our interests in these entities. Certain prior period amounts have been reclassified to conform to the 2016 presentation. These reclassifications had no impact on net income or total equity. Business Operations The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein. ETP is a publicly traded partnership whose operations comprise the following: • 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; • 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; • interstate pipelines that are owned and operated, either directly or through equity method investments, that transport natural gas to various markets in the United States; and • a controlling interest in Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of crude oil, NGL and refined products pipelines. Sunoco LP is a publicly traded partnership engaged in retail sale of motor fuels and merchandise through its company-operated convenience stores and retail fuel sites, as well as the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers and distributors. Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC. Our financial statements reflect the following reportable business segments: • Investment in ETP, including the consolidated operations of ETP; • Investment in Sunoco LP, including the consolidated operations of Sunoco LP; • Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and • Corporate and Other including the following: • activities of the Parent Company; and • the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

Estimates, Significant Accounti

Estimates, Significant Accounting Policies and Balance Sheet Detail	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Estimates, Significant Accounting Policies and Balance Sheet Detail	ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL : 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, 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 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. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catchup transition method). The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method. We are in the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standards. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts may be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We continue to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us. 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. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. In October 2016, the FASB issued 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. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that adoption of this standard will have on the consolidated financial statements and related disclosures. On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-09, Stock Compensation (Topic 718) (“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures. On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-17, Consolidation (Topic 810): Interests Held Through Related Parties That Are Under Common Control (“ASU 2016-17”), which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (VIE) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under the amendments, a single decision maker is required to include indirect interests on a proportionate basis consistent with indirect interests held through other related parties. Adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures. 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 does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We expect that our adoption of this standard will change our approach for testing goodwill for impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. Revenue Recognition Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments. Investment in ETP 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 or installation. 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. The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, 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. ETP’s intrastate transportation and storage operations also generate 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, ETP purchases natural gas from the market, including purchases from ETP’s marketing operations, and from producers at the wellhead. In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects 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, ETP 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 ETP operate, competitive factors in the energy industry, and other issues. Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and segment margins principally under fee-based or other arrangements in which ETP receives 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 ETP’s systems and is not directly dependent on commodity prices. ETP also utilizes other types of arrangements in ETP’s midstream operations, 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 ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells 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 ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s 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 ETP’s 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. ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells 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. Investment in Sunoco LP Revenues from Sunoco LP’s two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Revenue recognition on consignment sales differ from this and are discussed in greater detail below. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Through PropCo, Sunoco LP’s wholly owned corporate subsidiary, Sunoco LP may sell motor fuel to wholesale customers on a consignment basis, in which Sunoco LP retains title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. Sunoco LP derives other income from rental income, propane and lubricating oils and other ancillary product and service offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals and other ancillary product and service offerings. Sunoco LP records revenue on a net commission basis when the product is sold and/or services are rendered. Rental income from operating leases is recognized on a straight line basis over the term of the lease. Investment in Lake Charles LNG Lake Charles LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Lake Charles LNG’s terminal. Regulatory Accounting – Regulatory Assets and Liabilities ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations 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 ETP’s 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, ETP ceases 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 NGA and NGPA, 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 which 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, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows: Years Ended December 31, 2016 2015 2014 Accounts receivable $ (1,126 ) $ 856 $ 600 Accounts receivable from related companies 42 (5 ) 30 Inventories (345 ) (410 ) 52 Other current assets 149 (225 ) 151 Other non-current assets, net (148 ) 250 (6 ) Accounts payable 1,214 (1,043 ) (893 ) Accounts payable to related companies (64 ) 400 5 Exchanges payable — — — Accrued and other current liabilities 89 (697 ) (158 ) Other non-current liabilities 158 (233 ) (138 ) Derivative assets and liabilities, net 67 75 19 Net change in operating assets and liabilities, net of effects of acquisitions $ 36 $ (1,032 ) $ (338 ) Non-cash investing and financing activities and supplemental cash flow information were as follows: Years Ended December 31, 2016 2015 2014 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 930 $ 910 $ 643 Net gains (losses) from subsidiary common unit transactions 16 (526 ) 744 NON-CASH FINANCING ACTIVITIES: Issuance of Common Units in connection with the PennTex Acquisition 307 — — Contribution of property, plant and equipment from noncontrolling interest — 34 — Subsidiary issuances of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions — — 4,281 Subsidiary issuances of common units in connection with the Susser Merger — — 908 Long-term debt assumed in PVR Acquisition — — 1,887 Long-term debt exchanged in Eagle Rock Midstream Acquisition — — 499 SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized 1,922 1,800 1,416 Cash paid for (refund of) income taxes (229 ) 72 345 Accounts Receivable Our subsidiaries assess the credit risk of their customers and take steps to mitigate risk as necessary. Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and identification of specific customers with payment issues. Inventories Inventories consist principally of natural gas held in storage, crude oil, refined products and spare parts. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and refined products is determined using the last-in, first out method. The cost of spare parts is determined by the first-in, first-out method. Inventories consisted of the following: December 31, 2016 2015 Natural gas and NGLs $ 699 $ 415 Crude oil 683 424 Refined products 483 378 Spare parts and other 238 248 Total inventories $ 2,103 $ 1,465 During the year ended December 31, 2015, the Partnership’s income from continuing operations included a write-down of $229 million on its crude oil, refined products and NGL inventories as a result of declines in the market price of these products. The write-down was calculated based upon current replacement costs. ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations. Other Current Assets Other current assets consisted of the following: December 31, 2016 2015 Deposits paid to vendors $ 74 $ 74 Income taxes receivable 128 326 Prepaid expenses and other 301 193 Total other current assets $ 503 $ 593 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. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. For the Lake Charles LNG project, a portion of the management fees are capitalized. 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 2016, ETP recorded a $133 million fixed asset impairment related to the interstate transportation and storage operations 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 ETP’s midstream operations. In 2015, we recorded $110 million fixed asset impairments related to ETP’s NGL and refined products transportation and services operations 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 facilities 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, 2016 2015 Land and improvements $ 1,160 $ 1,008 Buildings and improvements (1 to 45 years) 2,197 1,629 Pipelines and equipment (5 to 83 years) 35,593 32,677 Natural gas and NGL storage facilities (5 to 46 years) 1,515 390 Bulk storage, equipment and facilities (2 to 83 years) 3,677 2,853 Tanks and other equipment (5 to 40 years) 1,286 1,488 Retail equipment (2 to 99 years) 427 436 Vehicles (1 to 25 years) 241 220 Right of way (20 to 83 years) 3,374 2,573 Natural resources 434 484 Other (1 to 40 years) 1,031 1,296 Construction work-in-process 10,223 7,797 61,158 52,851 Less – Accumulated depreciation and depletion (7,905 ) (6,067 ) Property, plant and equipment, net $ 53,253 $ 46,784 We recognized the following amounts for the periods presented: Years Ended December 31, 2016 2015 2014 Depreciation and depletion expense $ 1,904 $ 1,616 $ 1,409 Capitalized interest, excluding AFUDC 200 163 101 Advances to and Investments in Affiliates Certain of our subsidiaries 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. 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, 2016 2015 Unamortized financing costs (1) $ 13 $ 29 Regulatory assets 86 90 Deferred charges 217 198 Restricted funds 190 192 Other 310 202 Total other non-current assets, net $ 816 $ 711 (1) Includes unamortized financing costs related to the Partnership’s revolving credit facilities. 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, 2016 December 31, 2015 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 6,050 $ (971 ) $ 5,199 $ (712 ) Trade names (15 years) 352 (22 ) 66 (18 ) Patents (9 years) 25 (21 ) 48 (16 ) Other (1 to 15 years) 42 (9 ) 14 — Total amortizable intangible assets 6,469 (1,023 ) 5,327 (746 ) Non-amortizable intangible assets: Trademarks — — 281 — Contractual rights 43 — 34 — Liquor licenses — — — — Total intangible assets $ 6,512 $ (1,023 ) $ 5,642 $ (746 ) Aggregate amortization expense of intangibles assets was as follows: Years Ended December 31, 2016 2015 2014 Reported in depreciation, depletion and amortization $ 262 $ 288 $ 212 Estimated aggregate amortization expense of intangible assets for the next five years was as follows: Years Ending December 31: 2017 $ 279 2018 277 2019 273 2020 268 2021 251 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 ETP’s NGL and refined products transportation and services operations 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: Investment in ETP Investment in Sunoco LP Investment in Lake Charles LNG Corporate, Other and Eliminations Total Balance, December 31, 2014 $ 7,642 $ 1,149 $ 184 $ (3,104 ) $ 5,871 Goodwill acquired — 23 — — 23 Sunoco LP Exchange (2,018 ) — — 2,018 — Goodwill impairment (205 ) — — — (205 ) Other 9 (49 ) — (164 ) (204 ) Balance, December 31, 2015 5,428 1,123 184 (1,250 ) 5,485 Goodwill acquired 428 81 — — 509 Contribution of retail business (1,289 ) — — 1,289 — Goodwill impairment (670 ) (156 ) — — (826 ) Other — 2 — — 2 Balance, December 31, 2016 $ 3,897 $ 1,050 $ 184 $ 39 $ 5,170 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 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage operations and $32 million in the midstream operations 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. Sunoco LP recognized goodwill impairments of $642 million , of which $156 million was allocated to continuing operations, 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 2015, ETP performed goodwill impairment tests on its reporting units and recognized goodwill impairments of: (i) $99 million in the Transwestern reporting unit due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015, and (ii) $106 million in the Lone Star Refinery Services reporting unit due primarily to changes in assumptions related to potential future revenues decrease as well as the market declines in current and expected future commodity prices. 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 whethe

Acquisitions and Related Transa

Acquisitions and Related Transactions	12 Months Ended
	Dec. 31, 2016
Acquisitions and Dispositions [Abstract]
Acquisitions and Related Transactions	Transactions Sunoco LP Convenience Store Sale On April 6, 2017, Sunoco LP entered into a definitive asset purchase agreement for the sale of a portfolio of approximately 1,112 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, to 7-Eleven, Inc. (“7-Eleven”) for an aggregate purchase price of $3.3 billion (the “7-Eleven Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur in the fourth quarter of 2017. With the assistance of a third-party brokerage firm, Sunoco LP began marketing efforts with respect to approximately 208 sites under the Stripes brand (“Stripes Sites”) located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the 7-Eleven purchase agreement. There can be no assurance of Sunoco LP’s success in selling the remaining company-operated retail assets, nor the price or terms of such sale, and even if a sale is consummated, Sunoco LP may remain contingently responsible for certain risks and obligations related to the divested retail assets. On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties will be sold through a sealed-bid sale. Of the 97 properties, 16 have been sold and an additional 20 are under contract to be sold. 31 are being sold to 7-Eleven and 9 are being sold in another transaction. The remaining 21 continue to be marketed by the third-party brokerage firm. The Partnership has concluded that it meets the accounting requirements for reporting results of operations and cash flows of Sunoco LP’s continental United States retail convenience stores as discontinued operations and the related assets and liabilities as held for sale. The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet: December 31, 2016 December 31, 2015 Carrying amount of assets classified as held for sale: Cash and cash equivalents $ 20 $ 25 Inventories 188 171 Other current assets 83 10 Property, plant and equipment, net 2,185 1,899 Goodwill 1,568 1,988 Intangible assets, net 503 535 Other non-current assets, net 2 19 Total assets classified as held for sale in the Consolidated Balance Sheet $ 4,549 $ 4,647 Carrying amount of liabilities classified as held for sale: Other non-current liabilities 68 67 Total liabilities classified as held for sale in the Consolidated Balance Sheet $ 68 $ 67 The results of operations associated with discontinued operations are presented in the following table: Years Ended 2016 2015 2014 REVENUES $ 7,402 $ 7,922 $ 3,052 COSTS AND EXPENSES Cost of products sold 6,020 6,574 2,553 Operating expenses 1,486 933 291 Depreciation and amortization 193 175 55 Selling, general and administrative 114 91 55 Total costs and expenses 7,813 7,773 2,954 OPERATING INCOME (411 ) 149 98 Interest expense, net 29 22 1 Other, net 8 (2 ) (1 ) INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (448 ) 129 98 Income tax expense 31 48 32 INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES $ (479 ) $ 81 $ 66 INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE ATTRIBUTABLE TO ETE $ (12 ) $ 1 $ 3 2016 Transactions WMB Merger On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that ETE was contractually entitled to terminate its Merger Agreement with WMB in the event Latham & Watkins LLP (“Latham”) were unable to deliver a required tax opinion on or prior to June 28, 2016. Latham advised ETE that it was unable to deliver the tax opinion as of June 28, 2016. Consistent with its rights and obligations under the merger agreement, ETE subsequently provided written notice terminating the merger agreement due to the failure of conditions under the merger agreement, including Latham’s inability to deliver the tax opinion, as well as the other bases detailed in ETE’s filings in the Delaware lawsuit referenced above. WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court. 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. 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 . Sunoco Logistics’ Permian Express Partners In February 2017, Sunoco Logistics formed Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil Corp. Sunoco Logistics contributed its Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil Corp. contributed its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. Sunoco Logistics’ ownership percentage is approximately 85% . Upon commencement of operations on the Bakken Pipeline, Sunoco Logistics will contribute its investment in the project, with a corresponding increase in its ownership percentage in PEP. Sunoco Logistics maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP will be reflected as a consolidated subsidiary of Sunoco Logistics. ExxonMobil Corp.’s interest will be reflected as noncontrolling interest in Sunoco Logistics’ consolidated balance sheet. Bakken Equity Sale On August 2, 2016, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 60% membership interest and Sunoco Logistics indirectly owns a 40% membership interest, agreed to sell a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P. for $2.00 billion in cash. This transaction closed in February 2017. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”). The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP will continue to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, ETP and Sunoco Logistics collectively own a 38.25% interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the "Bakken Pipeline"), and MarEn Bakken Company owns 36.75% and Phillips 66 owns 25.00% in the Bakken Pipeline. 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 is anticipated to provide substantially all of the remaining capital necessary to complete the projects. As of December 31, 2016 , $1.10 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 Partners LP, 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. Sunoco LP Acquisitions In August 2016, Sunoco LP acquired the fuels business from Emerge Energy Services LP for $171 million , including tax deductible goodwill of $78 million and intangible assets of $23 million . Additionally, during 2016, Sunoco LP made other acquisitions primarily consisting of convenience stores, totaling $114 million plus the value of inventory on hand at closing and increasing goodwill by $61 million . In October 2016, Sunoco LP completed the acquisition of a convenience store, wholesale motor fuel distribution, and commercial fuels distribution business for approximately $55 million plus inventory on hand at closing, subject to closing adjustments. 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 of motor fuel per year to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued $41 million of 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. 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 will provide ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. Bakken Pipeline In March 2015, ETE transferred 46.2 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle 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, ETP also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. In October 2015, Sunoco Logistics completed the previously announced 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, LLC and Energy Transfer Crude Oil Company, LLC, 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 ETP merged with Regency, with Regency surviving as a wholly-owned subsidiary of ETP (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.6186 common units of ETP. ETP issued 258.3 million ETP common units to Regency unitholders, including 23.3 million units issued to ETP subsidiaries. The 1.9 million outstanding Regency Preferred Units were converted into corresponding new ETP Series A Preferred Units on a one-for-one basis. In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from ETP 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. 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. 2014 Transactions MACS to Sunoco LP In October 2014, Sunoco LP acquired MACS from a subsidiary of ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS, which had originally been acquired by ETP in October 2013. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014 and November 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with aggregate net proceeds of $405 million from a public offering of 9.1 million Sunoco LP common units. Susser Merger In August 2014, ETP and Susser completed the merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 23.7 million ETP Common Units. The Susser Merger broadens ETP’s retail geographic footprint and provides synergy opportunities and a platform for future growth. In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations. Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE. Summary of Assets Acquired and Liabilities Assumed ETP accounted for the Susser Merger 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 following table summarizes the assets acquired and liabilities assumed recognized as of the merger date: Susser Total current assets $ 446 Property, plant and equipment 1,069 Goodwill (1) 1,734 Intangible assets 611 Other non-current assets 17 3,877 Total current liabilities 377 Long-term debt, less current maturities 564 Deferred income taxes 488 Other non-current liabilities 39 Noncontrolling interest 626 2,094 Total consideration 1,783 Cash received 67 Total consideration, net of cash received $ 1,716 (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. ETP incurred merger related costs related to the Susser Merger of $25 million during the year ended December 31, 2015 . Our consolidated statements of operations for the year ended December 31, 2015 reflected revenue and net income related to Susser of $2.32 billion and $105 million , respectively. No pro forma information has been presented for the Susser Merger, as the impact of this acquisition was not material in relation to our consolidated results of operations. Regency’s Acquisition of Eagle Rock’s Midstream Business On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion , including the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to Eagle Rock’s operations of $903 million and $30 million , respectively. The total purchase price was allocated as follows: Assets At July 1, 2014 Current assets $ 120 Property, plant and equipment 1,295 Other non-current assets 4 Goodwill 49 Total assets acquired 1,468 Liabilities Current liabilities 116 Long-term debt 499 Other non-current liabilities 12 Total liabilities assumed 627 Net assets acquired $ 841 The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. Regency’s Acquisition of PVR Partners, L.P. On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per Regency Common Unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (the “PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million , which was funded through borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to PVR’s operations of $956 million and $166 million , respectively. Regency completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows: Assets At March 21, 2014 Current assets $ 149 Property, plant and equipment 2,716 Investment in unconsolidated affiliates 62 Intangible assets (average useful life of 30 years) 2,717 Goodwill (1) 370 Other non-current assets 18 Total assets acquired 6,032 Liabilities Current liabilities 168 Long-term debt 1,788 Premium related to senior notes 99 Non-current liabilities 30 Total liabilities assumed 2,085 Net assets acquired $ 3,947 (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. Lake Charles LNG Transaction On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 28.1 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). The transaction was effective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG. In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 8 . Panhandle Merger On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% senior notes due 2024, 8.25% senior notes due 2029 and the junior subordinated notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency ( 31.4 million Regency Common Units and 6.3 million Regency Class F Units), and ETP ( 3.3 million ETP Common Units).

Advances to and Investments in

Advances to and Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2016
Investment In Affiliates [Abstract]
Investments In Affiliates	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES : The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2016 and 2015 , were as follows: December 31, 2016 2015 Citrus $ 1,729 $ 1,739 AmeriGas 82 80 FEP 101 115 MEP 318 660 HPC 382 402 Others 428 466 Total $ 3,040 $ 3,462 Citrus ETP owns CrossCountry, which owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. AmeriGas In 2012, ETP received 29.6 million AmeriGas common units in connection with the contribution of its propane operations. During the year ended December 31, 2014, ETP sold 18.9 million AmeriGas common units for net proceeds of $814 million . As of December 31, 2016, the Partnership’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company and is reflected in the Investment in ETP segment. FEP ETP has 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. MEP ETP owns 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. ETP 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 ETP owns 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. Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented: December 31, 2016 2015 Current assets $ 720 $ 632 Property, plant and equipment, net 9,982 10,213 Other assets 2,618 2,649 Total assets $ 13,320 $ 13,494 Current liabilities $ 1,358 $ 841 Non-current liabilities 7,583 7,950 Equity 4,379 4,703 Total liabilities and equity $ 13,320 $ 13,494 Years Ended December 31, 2016 2015 2014 Revenue $ 3,509 $ 4,026 $ 4,925 Operating income 1,181 1,302 1,071 Net income 602 807 577 In addition to the equity method investments described above our subsidiaries 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	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Net Income Per Limited Partner Unit	NET INCOME PER LIMITED PARTNER UNIT : Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversion of our Preferred Units, see Note 7 . For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP or Sunoco LP that would have resulted assuming the incremental units related to ETP’s or Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method. A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows: Years Ended December 31, 2016 2015 2014 Income from continuing operations $ 520 $ 1,012 $ 994 Less: Income (loss) from continuing operations attributable to noncontrolling interest (487 ) (176 ) 371 Income from continuing operations, net of noncontrolling interest 1,007 1,188 623 Less: General Partner’s interest in income from continuing operations 3 3 2 Less: Convertible Unitholders’ interest in net income from continuing operations 8 — — Less: Class D Unitholder’s interest in income from continuing operations — 3 2 Income from continuing operations available to Limited Partners $ 996 $ 1,182 $ 619 Basic Income from Continuing Operations per Limited Partner Unit: Weighted average limited partner units 1,045.5 1,062.8 1,088.6 Basic income from continuing operations per Limited Partner unit $ 0.95 $ 1.11 $ 0.57 Basic income (loss) from discontinued operations per Limited Partner unit $ (0.01 ) $ — $ 0.01 Diluted Income from Continuing Operations per Limited Partner Unit: Income from continuing operations available to Limited Partners $ 996 $ 1,182 $ 619 Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units 8 3 (2 ) Diluted income from continuing operations available to Limited Partners 1,004 1,185 617 Weighted average limited partner units 1,045.5 1,062.8 1,088.6 Dilutive effect of unconverted unit awards and Convertible Units 33.1 1.6 2.2 Weighted average limited partner units, assuming dilutive effect of unvested unit awards 1,078.6 1,064.4 1,090.8 Diluted income from continuing operations per Limited Partner unit $ 0.93 $ 1.11 $ 0.57 Diluted income (loss) from discontinued operations per Limited Partner unit $ (0.01 ) $ — $ 0.01

Debt Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2016
Debt Obligations [Abstract]
Debt Disclosure [Text Block]	DEBT OBLIGATIONS: Our debt obligations consist of the following: December 31, 2016 2015 Parent Company Indebtedness: 7.50% Senior Notes, due October 15, 2020 $ 1,187 $ 1,187 5.875% Senior Notes, due January 15, 2024 1,150 1,150 5.50% Senior Notes due June 1, 2027 1,000 1,000 ETE Senior Secured Term Loan, due December 2, 2019 2,190 2,190 ETE Senior Secured Revolving Credit Facility due December 18, 2018 875 860 Unamortized premiums, discounts and fair value adjustments, net (15 ) (17 ) Deferred debt issuance costs (30 ) (38 ) 6,357 6,332 Subsidiary Indebtedness: ETP Debt 6.125% Senior Notes due February 15, 2017 400 400 2.50% Senior Notes due June 15, 2018 650 650 6.70% Senior Notes due July 1, 2018 600 600 9.70% Senior Notes due March 15, 2019 400 400 9.00% Senior Notes due April 15, 2019 450 450 5.75% Senior Notes due September 1, 2020 400 400 4.15% Senior Notes due October 1, 2020 1,050 1,050 6.50% Senior Notes due July 15, 2021 500 500 4.65% Senior Notes due June 1, 2021 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 5.875% Senior Notes due March 1, 2022 900 900 5.00% Senior Notes due October 1, 2022 700 700 3.60% Senior Notes due February 1, 2023 800 800 5.50% Senior Notes due April 15, 2023 700 700 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 4.05% Senior Notes due March 15, 2025 1,000 1,000 4.75% Senior Notes due January 15, 2026 1,000 1,000 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 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.15% Senior Notes due March 15, 2045 1,000 1,000 6.125% Senior Notes due December 15, 2045 1,000 1,000 Floating Rate Junior Subordinated Notes due November 1, 2066 546 545 ETP $3.75 billion Revolving Credit Facility due November 2019 2,777 1,362 Unamortized premiums, discounts and fair value adjustments, net (18 ) (21 ) Deferred debt issuance costs (132 ) (147 ) 22,067 20,633 Transwestern Debt 5.54% Senior Notes due November 17, 2016 — 125 5.64% Senior Notes due May 24, 2017 82 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 Unamortized premiums, discounts and fair value adjustments, net — (1 ) Deferred debt issuance costs (1 ) (2 ) 656 779 Panhandle Debt 6.20% Senior Notes due November 1, 2017 300 300 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 14, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 50 75 1,135 1,160 Sunoco, Inc. Debt 5.75% Senior Notes due January 15, 2017 400 400 9.00% Debentures due November 1, 2024 65 65 Unamortized premiums, discounts and fair value adjustments, net 9 20 474 485 Sunoco Logistics Debt 6.125% Senior Notes due May 15, 2016 — 175 5.50% Senior Notes due February 15, 2020 250 250 4.40% Senior Notes due April 1, 2021 600 600 4.65% Senior Notes due February 15, 2022 300 300 3.45% Senior Notes due January 15, 2023 350 350 4.25% Senior Notes due April 1, 2024 500 500 5.95% Senior Notes due December 1, 2025 400 400 3.90% Senior Notes due July 15, 2026 550 — 6.85% Senior Notes due February 15, 2040 250 250 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.30% Senior Notes due April 1, 2044 700 700 5.35% Senior Notes due May 15, 2045 800 800 Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 1,292 562 Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017 (1) 630 — Unamortized premiums, discounts and fair value adjustments, net 75 85 Deferred debt issuance costs (34 ) (32 ) 7,313 5,590 Bakken Project Debt Bakken Project $2.50 billion Credit Facility due August 2019 1,100 — Deferred debt issuance costs (13 ) — 1,087 — PennTex Debt PennTex $275 million Revolving Credit Facility due December 2019 168 — Sunoco LP Debt 5.50% Senior Notes Due August 1, 2020 600 600 6.375% Senior Notes due April 1, 2023 800 800 6.25% Senior Notes due April 15, 2021 800 — Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019 1,000 450 Sunoco LP Term Loan due October 1, 2019 1,243 — Lease-related obligations 118 126 Deferred debt issuance costs (47 ) (18 ) 4,514 1,958 Other 31 31 43,802 36,968 Less: current maturities 1,194 131 $ 42,608 $ 36,837 (1) Sunoco Logistics’ $1.0 billion 364-Day Credit Facility, including its $630 million term loan, were classified as long-term debt as of December 31, 2016 as Sunoco Logistics has the 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 $156 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: 2017 $ 1,817 2018 2,530 2019 9,483 2020 4,960 2021 2,706 Thereafter 22,462 Total $ 43,958 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. Notes and Debentures ETE Senior Notes The ETE Senior Notes are the Parent Company’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Parent Company’s obligations under the ETE Senior Notes are secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the ETE Term Loan Facility, by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Senior Notes are not guaranteed by any of the Parent Company’s subsidiaries. The covenants related to the ETE Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Parent Company’s assets. As discussed above, the Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP are required under Rule 3-16 to be included in the Partnership’s Annual Report on Form 10-K and have been included herein. The Parent Company’s interests in ETP GP and ETE Common Holdings, LLC, (collectively, the “Non-Reporting Entities”) also constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of the Non-Reporting Entities would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. None of the Non-Reporting Entities has substantive operations of its own; rather, each of the Non-Reporting Entities holds only direct or indirect interests in ETP and/or the consolidated subsidiaries of ETP. Following is a summary of the interests held by each of the Non-Reporting Entities, as well as a summary of the significant differences between each of the Non-Reporting Entities compared to ETP: • ETP GP owns 100% of the general partner interest in ETP. ETP GP does not own limited partner interests in ETP; therefore, the limited partner interests in ETP, which had a carrying value of $18.43 billion and $ 20.53 billion as of December 31, 2016 and 2015, respectively, would be reflected as noncontrolling interests on ETP GP’s balance sheets. Likewise, ETP’s income (loss) attributable to limited partners (including common unitholders, Class H unitholders and Class I unitholders) of $(651) million , $334 million and $823 million for the years ended December 31, 2016, 2015 and 2014, respectively, would be reflected as income attributable to noncontrolling interest in ETP GP’s statements of operations. • As of December 31, 2014, ETE Common Holdings, LLC (“ETE Common Holdings”) owned 5.2 million ETP Common Units, representing approximately 1.5% of the total outstanding ETP Common Units, and 50.2 million ETP Class H Units, representing 100% of the total outstanding ETP Class H Units. ETE Common Holdings also owned 30.9 million Regency Common Units, representing approximately 7.5% of the total outstanding Regency Common Units; ETE Common Holdings’ interest in Regency was acquired in 2014. During 2015, all of the units held by ETE Common Holdings were redeemed by ETP. ETE Common Holdings does not own the general partner interests in ETP; therefore, the financial statements of ETE Common Holdings would only reflect equity method investments in ETP. The carrying values of ETE Common Holdings’ investments in ETP was $1.72 billion as of December 31, 2014, and ETE Common Holdings’ equity in earnings from its investments in ETP was $292 million for the year ended December 31, 2014. ETP’s general partner interest, Common Units and Class H Units are reflected separately in ETP’s financial statements. As a result, the financial statements of the Non-Reporting Entities would substantially duplicate information that is available in the financial statements of ETP. Therefore, the financial statements of the Non-Reporting Entities have been excluded from the Partnership’s Annual Report on Form 10-K. ETP as Co-Obligor of Sunoco, Inc. Debt In connection with the Sunoco Merger and ETP Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $465 million as of December 31, 2016 , and $400 million matured and was repaid in January 2017. 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 3.77% at December 31, 2016 . ETP Senior Notes Offerings In January 2017, ETP issued $600 million aggregate principal amount of 4.20% senior notes due April 2027 and $900 million aggregate principal amount of 5.30% senior notes due April 2047. ETP used the $1.48 billion net proceeds from the offering to refinance current maturities and to repay borrowings outstanding under the ETP Credit Facility. The ETP senior notes were registered under the Securities Act of 1933 (as amended). ETP 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 ETP and the obligation of ETP to repay the ETP senior notes is not guaranteed by us or any of ETP’s subsidiaries. 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 in part, 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 payable semi-annually. Sunoco Logistics Senior Notes Offerings In July 2016, Sunoco Logistics issued $550 million aggregate principal amount of 3.90% senior notes due in July 2026. The net proceeds from this offering were used to repay outstanding credit facility borrowings and for general partnership purposes. Sunoco LP Senior Notes In April 2016, Sunoco LP issued $800 million aggregate principal amount of 6.25% Senior Notes due 2021. The net proceeds of $789 million were used to repay a portion of the borrowings under its term loan facility. Term Loans, Credit Facilities and Commercial Paper ETE Term Loan Facility As of December 31, 2016 , the Parent Company had outstanding a Senior Secured Term Loan Agreement, dated as of March 5, 2015, both with scheduled maturities on December 2, 2019. In connection with the Parent Company’s entry into a Senior Secured Term loan Agreement on February 2, 2017, as discussed below, the Parent Company terminated both agreements. On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof. Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the MLP Merger, ETP , and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics ; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the MLP Merger, ETP, and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million. Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 18.4 million common units representing limited partner interests in ETP and approximately 81.0 million Class H units of ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in, immediately prior to the consummation of the MLP Merger, ETP and, immediately after the consummation of the MLP Merger, Sunoco Logistics . The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries. Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75% . Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto. ETE Revolving Credit Facility The Parent Company has the Revolver Credit Agreement which has a scheduled maturity date of December 2, 2018, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advances up to an aggregate principal amount of $1.50 billion at any one time outstanding. The Revolver Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit. Under the Revolver Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets. Borrowings under the Revolver Credit Agreement are not guaranteed by any of the Parent Company’s subsidiaries. Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50% . The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. ETP Credit Facility The ETP Credit Facility allows for borrowings of up to $3.75 billion and matures on November 18, 2019. The indebtedness under the ETP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt. We use the ETP Credit Facility to provide temporary financing for our growth projects, as well as for general partnership purposes. As of December 31, 2016 , the ETP Credit Facility had $2.78 billion outstanding, and the amount available for future borrowings was $813 million after taking into account letters of credit of $160 million and commercial paper of $777 million . The weighted average interest rate on the total amount outstanding as of December 31, 2016 was 2.20% . Sunoco Logistics Credit Facilities Sunoco Logistics maintains a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions. The Sunoco Logistics Credit Facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The Sunoco Logistics Credit Facility bears interest at LIBOR or the Base Rate, based on Sunoco Logistics’ election for each interest period, plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2016 , the Sunoco Logistics Credit Facility had $1.29 billion of outstanding borrowings, which included commercial paper of $50 million . The weighted average interest rate on the total amount outstanding as of December 31, 2016 was 1.76% . In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility ("364-Day Credit Facility"), due to mature in December 2017, with a total lending capacity of $1.00 billion , including a $630 million term loan. The terms of the 364-Day Credit Facility are similar to those of the $2.50 billion Sunoco Logistics Credit Facility, including limitations on the creation of indebtedness, liens and financial covenants. The 364-Day Credit Facility is expected to be terminated and repaid in connection with the completion of the ETP and Sunoco Logistics merger. Bakken Credit Facility In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, 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, 2016 , the Bakken Credit Facility had $1.10 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2016 was 2.13% . PennTex Revolving Credit Facility On December 19, 2014, PennTex entered into a senior secured revolving credit facility with Royal Bank of Canada, as administrative agent, and a syndicate of lenders that became effective upon the closing of PennTex’s initial public offering and matures in December 2019 (the “PennTex Revolving Credit Facility”). The agreement provides for a $275 million commitment that is expandable up to $400 million under certain conditions. The funds have been used for general purposes, including the funding of capital expenditures. PennTex’s assets have been pledged as collateral for this credit facility. As of December 31, 2016 , PennTex had $106 million of available borrowing capacity under the PennTex Revolving Credit Facility. As of December 31, 2016 , the weighted average interest rate on outstanding borrowings was 2.90% . Sunoco LP Term Loan In March 2016, Sunoco LP entered into a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. Amounts borrowed under the term loan bear interest at either LIBOR or base rate, based on Sunoco LP’s election for each interest period, plus an applicable margin. The proceeds were used to fund a portion of the ETP dropdown and to pay fees and expenses incurred in connection with the ETP dropdown and the term loan. In December, 2016, Sunoco LP entered into an amendment to the term loan to, among other matters, increase the maximum applicable margin for LIBOR rate loans, increase the maximum ratio of funded debt, and add new obligations to maintain a maximum ratio of secured funded debt to EBITDA of the Sunoco LP. As of December 31, 2016, the balance on the term loan was $1.24 billion . In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. Sunoco LP Credit Facility Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. As of December 31, 2016 , the Sunoco LP Credit Facility had $1.00 billion of outstanding borrowings. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the revolving credit facility. Covenants Related to Our Credit Agreements Covenants Related to the Parent Company The Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements. The Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows: • Maximum Leverage Ratio – Consolidated Funded Debt (as defined therein) of the Parent Company to Consolidated EBITDA (as defined therein) of the Parent Company of not more than 6.0 to 1 , with a permitted increase to 7 to 1 during a specified acquisition period following the close of a specified acquisition; and • Consolidated EBITDA (as defined therein) to interest expense of not less than 1.5 to 1 . 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 Facility 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 Facility) during certain Defaults (as defined in the ETP Credit Facility) and during any Event of Default (as defined in the ETP Credit Facility); • 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 credit agreement relating to the ETP Credit Facility also contains a financial covenant that provides that the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1 as of the end of each quarter, with a permitted increase to 5.5 to 1 during a Specified Acquisition Period, as defined in the ETP Credit Facility. 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 Sunoco Logistics The Sunoco Logistics $2.50 billion Credit Facility contains various covenants, including limitations on the creation of indebtedness and liens, and other covenants related to the operation and conduct of the business of Sunoco Logistics and its subsidiaries. The Sunoco Logistics Credit Facility also limits Sunoco Logistics, on a rolling four-quarter basis, to a maximum total Consolidated Funded Indebtedness to Consolidated EBITDA ratio, each as defined in the Sunoco Logistics Credit Facility, of 5.0 to 1 , which can generally be increased to 5.5 to 1 during an acquisition period. Sunoco Logistics’ ratio of total Consolidated Funded Indebtedness, excluding net unamortized fair value adjustments, to Consolidated EBITDA was 4.4 to 1 at December 31, 2016 , as calculated in accordance with the credit agreements. 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. Covenants Related to PennTex The PennTex Revolving Credit Facility contains various covenants and restrictive provisions that, among other things, limit or restrict PennTex’s ability to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of PennTex’s business, engage in certain mergers or make certain investments and acquisitions, enter into non-arm’s-length transactions with affiliates and designate certain subsidiaries of PennTex as “Unrestricted Subsidiaries” for purposes of the credit agreement. Currently, no subsidiaries have been designated as Unrestricted Subsidiaries. PennTex is required to comply with a minimum consolidated interest coverage ratio of 2.50 x and a maximum consolidated leverage ratio of 4.75 x under the PennTex Revolving Credit Facility. The borrowed amounts accrue interest at a LIBOR rate or a base rate, based on PennTex’s election for each interest period, plus an applicable margin. The applicable margin used in connection with the interest rates and fees is based on the then applicable Consolidated Total Leverage Ratio (as defined therein). The applicable margin for LIBOR rate loans and letter of credit fees range from 2.00% and 3.25% based on the Consolidated Total Leverage Ratio and the applicable margin for ABR loans ranges from 1.00% to 2.25% based on the Consolidated Total Leverage Ratio. The unused portion of the credit facility is subject to a commitment fee, which is based on the Consolidated Total Leverage Ratio and ranges from 0.35% to 0.50% multiplied by the amount of the unused commitment. Covenants R

Redeemable Preferred Units

Redeemable Preferred Units	12 Months Ended
	Dec. 31, 2016
Preferred Units, Preferred Partners' Capital Account [Abstract]
Redeemable Preferred Units	REDEEMABLE PREFERRED UNITS: The ETP Preferred Units are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and are reflected as long-term liabilities in our consolidated balance sheets. The ETP Preferred Units are entitled to a preferential quarterly cash distribution of $0.445 per ETP Preferred Unit if outstanding on the record dates of ETP’s common unit distributions. Holders of the ETP Preferred Units can elect to convert the ETP Preferred Units to ETP Common Units at any time in accordance with ETP’s partnership agreement. The number of ETP common units issuable upon conversion of the ETP Preferred Units is equal to the issue price of $18.30 , plus all accrued but unpaid distributions and interest thereon, divided by the conversion price of $44.37 . As of December 31, 2016 , the ETP Preferred Units were convertible into 1.3 million ETP Common Units. In January 2017, ETP repurchased all of its 1.9 million outstanding Series A Preferred Units for cash in the aggregate amount of $53 million .

Equity

Equity	12 Months Ended
	Dec. 31, 2016
Partners' Capital Notes [Abstract]
Equity	EQUITY: Limited Partner Units Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s 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 the Partnership’s 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 “Parent Company Quarterly Distributions of Available Cash.” As of December 31, 2016 , there were issued and outstanding 1.05 billion Common Units representing an aggregate 97.71% limited partner interest in the Partnership. Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures. Common Units The change in ETE Common Units during the years ended December 31, 2016 , 2015 and 2014 was as follows: Years Ended December 31, 2016 2015 2014 Number of Common Units, beginning of period 1,044.8 1,077.5 1,119.8 Conversion of Class D Units to ETE Common Units — 0.9 — Repurchase of common units under buyback program — (33.6 ) (42.3 ) Issuance of common units 2.1 — — Number of Common Units, end of period 1,046.9 1,044.8 1,077.5 ETE Series A Preferred Units Years Ended December 31, 2016 2015 2014 Number of Series A Convertible Preferred Units, beginning of period — — — Issuance of Series A Convertible Preferred Units 329.3 — — Number of Series A Convertible Preferred Units, end of period 329.3 — — On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56 . The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285 , which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $180 million carrying value as of December 31, 2016. ETE issued 329,295,770 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units, which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates. ETE January 2017 Private Placement and ETP Unit Purchase In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million , which ETE used to purchase 23.7 million newly issued ETP common units for approximately $568 million . Common Unit Split On December 23, 2013, ETE announced that the board of directors of its general partner approved a two-for-one split of the Partnership’s outstanding common units (the “2014 Split”). The 2014 Split was completed on January 27, 2014. The 2014 Split was effected by a distribution of one ETE Common Unit for each common unit outstanding and held by unitholders of record at the close of business on January 13, 2014. On May 28, 2015, ETE announced that the board of directors its general partner approved a two-for-one split of the Partnership’s outstanding common units (the “2015 Split”). The 2015 Split was completed on July 27, 2015. The 2015 Split was effected by a distribution of one ETE common unit for each common unit outstanding and held by unitholders of record at the close of business on July 15, 2015. Repurchase Program In December 2013, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $1 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 42.3 million ETE Common Units under this program through May 23, 2014, and the program was completed. In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 33.6 million ETE Common Units under this program in 2015. No units were repurchased in 2016, and there was $936 million available to use under the program as of December 31, 2016. Class D Units On May 1, 2013, Jamie Welch was appointed Group Chief Financial Officer and Head of Corporate Development of LE GP, LLC, the general partner of ETE, effective June 24, 2013. Pursuant to an equity award agreement between Mr. Welch and the Partnership dated April 23, 2013, Mr. Welch received 3,000,000 restricted ETE common units representing limited partner interest. The restricted ETE common units were subject to vesting, based on continued employment with ETE. On December 23, 2013, ETE and Mr. Welch entered into (i) a rescission agreement in order to rescind the original offer letter to the extent it relates to the award of 3,000,000 common units of ETE to Mr. Welch, the original award agreements, and the receipt of cash amounts by Mr. Welch with respect to such awarded units and (ii) a new Class D Unit Agreement between ETE and Mr. Welch providing for the issuance to Mr. Welch of an aggregate of 3,080,000 Class D Units of ETE, which number of Class D Units includes an additional 80,000 Class D Units that were issued to Mr. Welch in connection with other changes to his original offer letter. Under the terms of the Class D Unit Agreement, as amended, 30% of the Class D Units converted to ETE common units on a one-for-one basis on March 31, 2015, 35% were scheduled to convert to ETE common units on a one-for-one-basis on March 31, 2018, and the remaining 35% were scheduled to convert to ETE common units on a one-for-one basis on March 31, 2020, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be allocated to the Class D Units being converted so as to cause the capital account of each such unit to equal the capital account of an ETE Common Unit on the conversion date. Per the terms of the Class D Unit Agreement, 924,000 units converted to ETE common units on a one-for-one basis March 31, 2015. In connection with Mr. Welch’s replacement as Group Chief Financial Officer and Head of Business Development of our General Partner and his termination of employment by an affiliate of ETE, any future conversion of the Class D Units is the subject of on-going discussions between ETE and Mr. Welch in connection with his separation from employment. On March 10, 2016, Jamie Welch (“Welch”) filed an original petition against ETE and LE GP, LLC in Texas state court in Dallas. A confidential settlement was reached in August 2016. The court dismissed the matter with prejudice on September 6, 2016. Sale of Common Units by Subsidiaries The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented. Sale of Common Units by ETP ETP’s Equity Distribution Program From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP 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 agreement. In July 2016, ETP entered into an equity distribution agreement with an aggregate offering price up to $1.50 billion . During the year ended December 31, 2016 , ETP issued 39.2 million units for $891 million , net of commissions of $8 million . In connection with the merger of ETP and Sunoco Logistics in April 2017, the equity distribution agreement was terminated. ETP’s Equity Incentive Plan Activity ETP issues ETP Common Units to employees and directors upon vesting of awards granted under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are entitled withheld by ETP to satisfy tax-withholding obligations. ETP’s Distribution Reinvestment Program ETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and beneficial owners of ETP 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 ETP Common Units. During the years ended December 31, 2016 , 2015 and 2014 , aggregate distributions of $216 million , $360 million , and $155 million , respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.7 million Common Units. In connection with the merger of ETP and Sunoco Logistics in April 2017, the distribution reinvestment plan was terminated. ETP Class E Units These ETP Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all ETP Unitholders, including the ETP Class E Unitholders, up to $1.41 per unit per year, with any excess thereof available for distribution to ETP Unitholders other than the holders of ETP Class E Units in proportion to their respective interests. The ETP Class E Units are treated by ETP as treasury units for accounting purposes because they are owned by a subsidiary of ETP Holdco, Heritage Holdings, Inc. Although no plans are currently in place, management may evaluate whether to retire some or all of the ETP Class E Units at a future date. All of the 8.9 million ETP Class E Units outstanding are held by a subsidiary of ETP and are reported by ETP as treasury units. ETP Class G Units In conjunction with the Sunoco Merger, ETP amended its partnership agreement to create ETP Class F Units. The number of ETP Class F Units issued was determined at the closing of the Sunoco Merger and equaled 90.7 million , which included 40 million ETP Class F Units issued in exchange for cash contributed by Sunoco, Inc. to ETP immediately prior to or concurrent with the closing of the Sunoco Merger. The ETP Class F Units generally did not have any voting rights. The ETP Class F Units were entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETP and its subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per ETP Class F Unit per year. In April 2013, all of the outstanding ETP Class F Units were exchanged for ETP Class G Units on a one-for-one basis. The ETP Class G Units have terms that are substantially the same as the ETP Class F Units, with the principal difference between the ETP Class G Units and the ETP Class F Units being that allocations of depreciation and amortization to the ETP Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. The ETP Class G Units are held by a subsidiary of ETP and therefore are reflected by ETP as treasury units in its consolidated financial statements. ETP Class H Units and Class I 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 are 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, (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. Bakken Pipeline Transaction In March 2015, ETE transferred 46.2 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle 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, ETP also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. In connection with the transaction, ETP issued 100 ETP Class I Units. The ETP 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 ETP 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 ETP Class I Units and (ii) after making cash distributions to ETP 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 ETP’s Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ending March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the ETP 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 remained outstanding. Bakken Equity Sale On August 2, 2016, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 60% membership interest and Sunoco Logistics indirectly owns a 40% membership interest, agreed to sell a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P. for $2.00 billion in cash. This transaction closed in February 2017. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”). The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP will continue to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, ETP and Sunoco Logistics collectively own a 38.25% interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the "Bakken Pipeline"), and MarEn Bakken Company owns 36.75% and Phillips 66 owns 25.00% in the Bakken Pipeline. Class K Units On December 29, 2016, ETP issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in ETP, 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 other than the Class H Units and the Class I Units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco. As of December 31, 2016 , a total of 101,525,429 Class K Units were held by indirect subsidiaries of ETP. Sales of Common Units by Sunoco Logistics 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 September 2014, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million were used to repay outstanding borrowings under the Sunoco Logistics 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 the fourth quarter of 2015, the aggregate capacity was increased to $2.25 billion . During the year ended December 31, 2016 , Sunoco Logistics received proceeds of $744 million , net of commissions of $8 million , from the issuance of 29.1 million common units pursuant to the equity distribution agreement. Sales of Common Units by Sunoco LP In October 2016, Sunoco LP entered into an equity distribution agreement pursuant to which Sunoco LP may sell from time to time common units having aggregate offering prices of up to $400 million . Through December 31, 2016, Sunoco LP received net proceeds of $71 million from the issuance of 2.8 million Sunoco LP common units pursuant to such equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes. As of December 31, 2016 , $328 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement. From January 1, 2017 through February 24, 2017, Sunoco LP issued additional 0.4 million units with total net proceeds of $10 million and intends to use the net proceeds from sales for general partnership purposes, which may include repaying or refinancing all or a portion of our outstanding indebtedness and funding capital expenditures, acquisitions or working capital. 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 ETP. On March 31, 2016, Sunoco LP sold 2.3 million of Sunoco LP’s common units in a private placement to the Partnership. In January 2016, Sunoco LP issued 16.4 million Class C units representing limited partner interest consisting of (i) 5.2 million Class C Units issued by Sunoco LP to Aloha Petroleum, Ltd as consideration for the contribution by Aloha to an indirect wholly-owned subsidiary, and (ii) 11.2 million Class C Units that were issued by Sunoco LP to its indirect wholly-owned subsidiaries in exchange for all of the outstanding Class A Units held by such subsidiaries. In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $213 million . The net proceeds from the offering were used to repay outstanding balances under the Sunoco LP revolving credit facility. In October 2014 and November 2014, Sunoco LP issued an aggregate total of 9.1 million common units in an underwritten public offering. Aggregate net proceeds of $405 million from the offering were used to repay amounts outstanding under the $1.50 billion Sunoco LP Credit Facility and for general partnership purposes. Contributions to Subsidiaries The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP has the right, but not the obligation, to contribute a proportionate amount of capital to ETP to maintain its current general partner interest. ETP GP’s interest in ETP’s distributions is reduced if ETP issues additional units and ETP GP does not contribute a proportionate amount of capital to ETP to maintain its General Partner interest. Parent Company Quarterly Distributions of Available Cash Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Sunoco LP related to limited and general partner interests, including IDRs, as well as cash generated from our investment in Lake Charles LNG. Our distributions declared with respect to our common units during the years ended December 31, 2016, 2015, and 2014 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2013 February 7, 2014 February 19, 2014 $ 0.1731 March 31, 2014 May 5, 2014 May 19, 2014 0.1794 June 30, 2014 August 4, 2014 August 19, 2014 0.1900 September 30, 2014 November 3, 2014 November 19, 2014 0.2075 December 31, 2014 February 6, 2015 February 19, 2015 0.2250 March 31, 2015 May 8, 2015 May 19, 2015 0.2450 June 30, 2015 August 6, 2015 August 19, 2015 0.2650 September 30, 2015 November 5, 2015 November 19, 2015 0.2850 December 31, 2015 February 4, 2016 February 19, 2016 0.2850 March 31, 2016 (1) May 6, 2016 May 19, 2016 0.2850 June 30, 2016 (1) August 8, 2016 August 19, 2016 0.2850 September 30, 2016 (1) November 7, 2016 November 18, 2016 0.2850 December 31, 2016 (1) February 7, 2017 February 21, 2017 0.2850 (1) Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See Note 8, ETE Series A Preferred Units. Our distributions declared with respect to our Convertible Unit during the year ended December 31, 2016 were as follows: Quarter Ended Record Date Payment Date Rate March 31, 2016 May 6, 2016 May 19, 2016 $ 0.1100 June 30, 2016 August 8, 2016 August 19, 2016 0.1100 September 30, 2016 November 7, 2016 November 18, 2016 0.1100 December 31, 2016 February 7, 2017 February 21, 2017 0.1100 ETP’s Quarterly Distributions of Available Cash ETP’s Partnership Agreement requires that ETP distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of ETP, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its General Partner in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in ETP’s Partnership Agreement. ETP’s distributions declared during the periods presented below were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2013 February 7, 2014 February 14, 2014 $ 0.6133 March 31, 2014 May 5, 2014 May 15, 2014 0.6233 June 30, 2014 August 4, 2014 August 14, 2014 0.6367 September 30, 2014 November 3, 2014 November 14, 2014 0.6500 December 31, 2014 February 6, 2015 February 13, 2015 0.6633 March 31, 2015 May 8, 2015 May 15, 2015 0.6767 June 30, 2015 August 6, 2015 August 14, 2015 0.6900 September 30, 2015 November 5, 2015 November 16, 2015 0.7033 December 31, 2015 February 8, 2016 February 16, 2016 0.7033 March 31, 2016 May 6, 2016 May 16, 2016 0.7033 June 30, 2016 August 8, 2016 August 15, 2016 0.7033 September 30, 2016 November 7, 2016 November 14, 2016 0.7033 December 31, 2016 February 7, 2017 February 14, 2017 0.7033 ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods: Total Year 2017 $ 626 2018 138 2019 128 Each year beyond 2019 33 Sunoco Logistics Quarterly Distributions of Available Cash Distributions declared by Sunoco Logistics during the years ended December 31, 2016, 2015, and 2014 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2013 February 10, 2014 February 14, 2014 $ 0.3312 March 31, 2014 May 9, 2014 May 15, 2014 0.3475 June 30, 2014 August 8, 2014 August 14, 2014 0.3650 September 30, 2014 November 7, 2014 November 14, 2014 0.3825 December 31, 2014 February 9, 2015 February 13, 2015 0.4000 March 31, 2015 May 11, 2015 May 15, 2015 0.4190 June 30, 2015 August 10, 2015 August 14, 2015 0.4380 September 30, 2015 November 9, 2015 November 13, 2015 0.4580 December 31, 2015 February 8, 2016 February 12, 2016 0.4790 March 31, 2016 May 9, 2016 May 13, 2016 0.4890 June 30, 2016 August 8, 2016 August 12, 2016 0.5000 September 30, 2016 November 9, 2016 November 14, 2016 0.5100 December 31, 2016 February 7, 2017 February 14, 2017 0.5200 PennTex Quarterly Distributions of Available Cash PennTex is required by its part

Unit-Based Compensation Plans

Unit-Based Compensation Plans	12 Months Ended
	Dec. 31, 2016
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Unit-Based Compensation Plans	UNIT-BASED COMPENSATION PLANS: We, ETP, Sunoco Logistics and Sunoco LP have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other unit-based awards. ETE Long-Term Incentive Plan The Board of Directors or the Compensation Committee of the board of directors of the our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 12,000,000 units. As of December 31, 2016 , 8,271,767 units remain available to be awarded under the plan. During the year ended December 31, 2016 , no ETE unit awards were granted to ETE employees and 23,821 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest 60% in three years and 40% in five years and do not entitle the holders to receive distributions during the vesting period. During the year ended December 31, 2016 and 2015, a total of 28,648 and 26,244 ETE Common Units vested, with a total fair value of $0.2 million and $0.8 million , respectively, as of the vesting date. As of December 31, 2016 , a total of 43,740 restricted units granted to ETE directors remain outstanding, for which we expect to recognize a total of less than $1 million in compensation over a weighted average period of 3.0 years . Subsidiary Unit-Based Compensation Plans Both ETP and Sunoco LP have granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards” to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a five-year period, and vesting The Subsidiary Unit Awards entitle the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding. The following table summarizes the activity of the Subsidiary Unit Awards: ETP Sunoco LP Number of Units Weighted Average Grant-Date Fair Value Per Unit Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2015 7.2 $ 31.74 1.1 $ 41.19 Awards granted 3.8 23.82 1.0 26.95 Awards vested (1.2 ) 35.48 — 36.98 Awards forfeited (0.3 ) 32.26 (0.1 ) 39.77 Unvested awards as of December 31, 2016 9.5 27.69 2.0 34.43 Weighted average grant date fair value for Subsidiary Unit Awards during the year ended December 31: 2016 $ 23.82 $ 26.95 2015 23.47 40.63 2014 40.57 45.50 The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2016, 2015, and 2014 was $40 million , $57 million , and $56 million , respectively, based on the market price of the respective subsidiaries’ common units as of the vesting date. As of December 31, 2016 , estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $275 million , and the weighted average period over which this cost is expected to be recognized in expense is 3.0 years and 4.3 years for ETP and Sunoco LP, respectively.

Income Taxes Income Taxes (Note

Income Taxes Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES: As a partnership, we are not subject to U.S. 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) of our taxable subsidiaries were summarized as follows: Years Ended December 31, 2016 2015 2014 Current expense (benefit): Federal $ 11 $ (315 ) $ 251 State (34 ) (54 ) 78 Total (23 ) (369 ) 329 Deferred expense (benefit): Federal (237 ) 253 (29 ) State 12 (32 ) 25 Total (225 ) 221 (4 ) Total income tax expense (benefit) from continuing operations $ (248 ) $ (148 ) $ 325 Historically, our effective tax rate differed from the statutory rate primarily due to partnership earnings that are not subject to U.S. federal and most state income taxes at the partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and the Susser Merger (see Note 3 ) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2016 , 2015 and 2014 is as follows: December 31, 2016 December 31, 2015 December 31, 2014 Income tax expense (benefit) at U.S. statutory rate of 35 percent $ 95 $ 302 $ 462 Increase (reduction) in income taxes resulting from: Nondeductible goodwill included in the Lake Charles LNG transaction — — 105 Partnership earnings not subject to tax (590 ) (366 ) (284 ) Goodwill impairment 278 — — State tax, net of federal tax benefit (10 ) (35 ) 52 Dividend received deduction (15 ) (22 ) — Premium on debt retirement — — (10 ) Audit settlement — (7 ) — Foreign taxes — — (8 ) Other (6 ) (20 ) 8 Income tax expense (benefit) from continuing operations $ (248 ) $ (148 ) $ 325 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, 2016 2015 Deferred income tax assets: Net operating losses and alternative minimum tax credit $ 472 $ 217 Pension and other postretirement benefits 30 36 Long term debt 32 61 Other 182 162 Total deferred income tax assets 716 476 Valuation allowance (118 ) (121 ) Net deferred income tax assets 598 355 Deferred income tax liabilities: Properties, plants and equipment (1,633 ) (1,633 ) Investments in unconsolidated affiliates (3,789 ) (2,976 ) Trademarks (273 ) (286 ) Other (15 ) (50 ) Total deferred income tax liabilities (5,710 ) (4,945 ) Accumulated deferred income taxes $ (5,112 ) $ (4,590 ) The table below provides a rollforward of the net deferred income tax liability as follows: December 31, 2016 2015 Net deferred income tax liability, beginning of year $ (4,590 ) $ (4,410 ) Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) (460 ) — Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3) (243 ) — Tax provision, including provision from discontinued operations 201 (242 ) Other (20 ) 62 Net deferred income tax liability $ (5,112 ) $ (4,590 ) ETP Holdco and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits of $292 million , all of which will expire in 2032 through December 31, 2035 . Our corporate subsidiaries have state net operating loss carryforward benefits of $127 million , net of federal tax, which expire between January 1, 2017 and 2036. A valuation allowance of $118 million is applicable to the state net operating loss carryforward benefits applicable to significant restriction on their use in the Commonwealth of Pennsylvania. The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2016 2015 2014 Balance at beginning of year $ 610 $ 440 $ 429 Additions attributable to tax positions taken in the current year 8 178 20 Additions attributable to tax positions taken in prior years 18 — — Reduction attributable to tax positions taken in prior years (20 ) — (1 ) Settlements — — (5 ) Lapse of statute (1 ) (8 ) (3 ) Balance at end of year $ 615 $ 610 $ 440 As of December 31, 2016 , we have $596 million ( $554 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it is reasonably possible that its unrecognized tax benefits may be reduced by $1 million ( $0.6 million , net of federal tax) within the next twelve months due to settlement of certain positions. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2016 , we recognized interest and penalties of less than $1 million . At December 31, 2016 , we have interest and penalties accrued of $6 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 its 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 consolidated balance sheet as of December 31, 2016 . In December of 2015, The Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“ Nextel ”) that the Pennsylvania limitation on NOL carryforwards violated the uniformity clause of the Pennsylvania Constitution. Based upon the decision in Nextel , Sunoco, Inc. is recognizing approximately $46 million ( $30 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims. However, as the Nextel decision is subject to appeal, and because of uncertainty in the breadth of the application of the decision, we have reserved $9 million ( $6 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. ETE 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.

Derivative Assets And Liabiliti

Derivative Assets And Liabilities	12 Months Ended
	Dec. 31, 2016
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 operations and operational gas sales on our interstate transportation and storage operations. 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 operations 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 use derivatives in our NGL and refined products transportation and services operations to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. Sunoco Logistics utilizes swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. These contracts are not designated as hedges for accounting purposes. We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing operations. 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 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 operations 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 operations, 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, 2016 December 31, 2015 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures (682,500 ) 2017 (602,500 ) 2016 - 2017 Basis Swaps IFERC/NYMEX (1) 2,242,500 2017 (31,240,000 ) 2016 - 2017 Power (Megawatt): Forwards 391,880 2017 - 2018 357,092 2016 - 2017 Futures 109,564 2017 - 2018 (109,791 ) 2016 Options — Puts (50,400 ) 2017 260,534 2016 Options — Calls 186,400 2017 1,300,647 2016 Crude (Bbls) – Futures (617,000 ) 2017 (591,000 ) 2016 - 2017 (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX 10,750,000 2017 - 2018 (6,522,500 ) 2016 - 2017 Swing Swaps IFERC (5,662,500 ) 2017 71,340,000 2016 - 2017 Fixed Swaps/Futures (52,652,500 ) 2017 - 2019 (14,380,000 ) 2016 - 2018 Forward Physical Contracts (22,492,489 ) 2017 21,922,484 2016 - 2017 Natural Gas Liquid (Bbls) – Forwards/Swaps (5,786,627 ) 2017 (8,146,800 ) 2016 - 2018 Refined Products (Bbls) – Futures (3,144,000 ) 2017 (1,289,000 ) 2016 - 2017 Corn (Bushels) – Futures 1,580,000 2017 1,185,000 2016 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (36,370,000 ) 2017 (37,555,000 ) 2016 Fixed Swaps/Futures (36,370,000 ) 2017 (37,555,000 ) 2016 Hedged Item — Inventory 36,370,000 2017 37,555,000 2016 (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 are designated as hedges for accounting purposes: Notional Amount Outstanding Entity Term Type (1) December 31, December 31, ETP July 2016 (2) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate $ — $ 200 ETP July 2017 (3) Forward-starting to pay a fixed rate of 3.90% and receive a floating rate 500 300 ETP July 2018 (3) Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200 200 ETP July 2019 (3) Forward-starting to pay a fixed rate of 3.25% and receive a floating rate 200 200 ETP December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 1,200 ETP 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 10 and 30 years with a mandatory termination date the same as the effective date. (3) Represents the effective date. These forward-starting swaps have a term 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, independent power generators and fuel distributors. 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, 2016 December 31, 2015 December 31, 2016 December 31, 2015 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ — $ 38 $ (4 ) $ (3 ) — 38 (4 ) (3 ) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 338 353 (416 ) (306 ) Commodity derivatives 25 63 (58 ) (47 ) Interest rate derivatives — — (193 ) (171 ) Embedded derivatives in ETP Preferred Units — — (1 ) (5 ) 363 416 (668 ) (529 ) Total derivatives $ 363 $ 454 $ (672 ) $ (532 ) 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, 2016 December 31, 2015 December 31, 2016 December 31, 2015 Derivatives without offsetting agreements Derivative assets (liabilities) $ — $ — $ (194 ) $ (176 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 25 63 (58 ) (47 ) Broker cleared derivative contracts Other current assets 338 391 (420 ) (309 ) 363 454 (672 ) (532 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (4 ) (17 ) 4 17 Payments on margin deposit Other current assets (338 ) (309 ) 338 309 Total net derivatives $ 21 $ 128 $ (330 ) $ (206 ) We disclose the non-exchange traded financial derivative instruments as derivative 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) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Years Ended December 31, 2016 2015 2014 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ — $ — $ (3 ) Total $ — $ — $ (3 ) 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, 2016 2015 2014 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 14 $ 21 $ (8 ) Total $ 14 $ 21 $ (8 ) Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives Years Ended December 31, 2016 2015 2014 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (35 ) $ (11 ) $ (6 ) Commodity derivatives – Non-trading Cost of products sold (177 ) 15 199 Interest rate derivatives Losses on interest rate derivatives (12 ) (18 ) (157 ) Embedded derivatives Other, net 4 12 3 Total $ (220 ) $ (2 ) $ 39

Regulatory Matters, Commitments

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	12 Months Ended
	Dec. 31, 2016
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	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 agreed to provide contingent residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchases. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETP under the contingent residual support agreement. In February 2017, AmeriGas repurchased $378 million of its 7.00% senior notes, which reduced the remaining amount supported by ETP to $122 million . 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. NGL Pipeline Regulation We have interests in NGL pipelines located in Texas and New Mexico. We commenced the interstate transportation of NGLs in 2013, which is subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not confer any undue preference. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow. 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. We believe 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 they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their 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, 2016 2015 2014 Rental expense (1) $ 129 $ 205 $ 98 Less: Sublease rental income (30 ) (16 ) (26 ) Rental expense, net $ 99 $ 189 $ 72 (1) Includes contingent rentals totaling $23 million , $26 million and $24 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Future minimum lease commitments for such leases are: Years Ending December 31: 2017 $ 82 2018 67 2019 55 2020 52 2021 53 Thereafter 219 Future minimum lease commitments 528 Less: Sublease rental income (79 ) Net future minimum lease commitments $ 449 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 During the summer of 2016, individuals affiliated with, or sympathetic to, the Standing Rock Sioux Tribe (the “SRST”) began gathering near a construction site on the Dakota Access pipeline project in North Dakota to protest the development of the pipeline project. Some of the protesters eventually trespassed on to the construction site, tampered with equipment, and disrupted construction activity at the site. At this time, we are working with the various authorities to mitigate the effects of this largely unlawful protest. We believe that Dakota Access now has the necessary permits and approvals to perform all work on the pipeline project. In response to the protests, Dakota Access filed a lawsuit in federal court in North Dakota to restrain protestors from disrupting construction and also requested a temporary restraining order (“TRO”) against the Chairman of the SRST and the protestors. The U.S. District Court granted Dakota Access’s request for a TRO, and the defendants filed a motion to dismiss the case and dissolve the TRO. The Court later granted the defendants’ motions to dissolve the TRO. Dakota Access filed a response to the defendant’s motion to dismiss, and the Court has yet to rule. At this time, we cannot determine how long the protest will continue, how the legal action will be resolved. Construction work on the pipeline is ongoing, and, barring legal delays, we expect the final portion of the pipeline to be completed in March or April. Additional protests or legal actions may arise in connection with our Dakota Access project or other projects. Trespass on to construction sites or our physical facilities, or other disruptions, could result in further damage to our assets, safety incidents, potential liability or project delays. In July 2016, the U.S. 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. The USACE has also issued an easement to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. The SRST filed a lawsuit in the U.S. District Court for the District of Columbia against the USACE challenging the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claiming 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’ moved to intervene in the case and that motion was granted by the Court. The SRST has also sought an emergency TRO to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction. After that decision, the Department of the Army, the Department of Justice, and the Department of the Interior released a joint statement stating that the USACE would not grant the easement for the land adjacent to Lake Oahe until the federal departments completed a review of the SRST’s claims in its lawsuit with respect to the USACE’s compliance with certain federal statutes in connection with its activities related to the granting of the permits. The SRST appealed the denial of the preliminary injunction to the U.S. Court of Appeals for the D.C. Circuit and filed an emergency motion for an injunction pending the appeal to the U.S. District Court. The U.S. District Court denied SRST’s emergency motion for an injunction pending the appeal. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statues governing the use of government property. The D.C. Circuit denied the SRST’s application for a stay pending appeal and later dismissed the SRST’s appeal of the denied TRO. 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 January 2017, pursuant to a presidential memorandum, the Department the Department of the Army decided that no further environmental review was necessary and delivered Dakota Access an easement to cross Lake Oahe. Construction at the site is ongoing. In the fall of 2016, the Cheyenne River Sioux Tribe intervened alongside the SRST. After USACE gave Dakota Access its final easement, the Cheyenne River Sioux moved for a preliminary injunction and temporary restraining order blocking construction. These motions raised, for the first time, claims based on the religious rights of the Tribe. The district court denied the TRO and has yet to decide whether to grant a preliminary injunction. The SRST has also moved for summary judgment on its claims against the government based on its treaty rights and the National Environmental Policy Act, and the district court is still considering this motion. Briefing is ongoing. In addition, the Oglala and Yankton Sioux tribes have filed related lawsuits in an effort to prevent construction of the Dakota Access pipeline project. While we believe that the pending lawsuits are unlikely to block construction or operation of the pipeline and that construction on the land adjacent to Lake Oahe will be completed in a timely manner, we cannot assure this outcome. Any significant delay imposed by the court will delay the receipt of revenue from this project. 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 (CMB) 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. The extent of possible damages is still under investigation. MTBE Litigation Sunoco, Inc. and/or Sunoco, Inc. (R&M), along with other refiners, manufacturers and sellers of gasoline, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs primarily assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases 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, 2016 , Sunoco, Inc. is a defendant in six cases, including cases initiated by the States of New Jersey, Vermont, Pennsylvania, Rhode Island, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico, Vermont, and Pennsylvania cases assert natural resource damage claims. Fact discovery has concluded with respect to an initial set of 19 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. The initial set of 19 New Jersey trial sites are now pending before the United States District Judge for the District of New Jersey, the Hon. Freda L. Wolfson for the pre-trial and trial phases. Judge Wolfson then referred the case to United States Magistrate Judge for the District of New Jersey, the Hon. Lois H. Goodman. Judge Goodman conducted a status conference with all of the parties and inquired whether the parties will engage in a global mediation and instructed the parties to exchange possible mediator names. All parties agreed to participate in global settlement discussions in a global mediation forum before Hon. Garrett Brown (Ret.), a Judicial Arbitration Mediation Service mediator. The remaining portion of the New Jersey case remains in the multidistrict litigation. The first mediation session with Judge Brown is scheduled for November 2 through November 3, 2016. In early 2017, Sunoco, Inc. and two other co-defendants reached a settlement in principle with the State of New Jersey, subject to the parties agreeing on the terms and conditions of a Settlement and Release agreement. 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. Management believes that 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 said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position. Regency Merger Litigation Following the January 26, 2015 announcement of 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 Regency Merger-related lawsuits have been dismissed, although one lawsuit remains pending on appeal. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware. The lawsuit 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. Defendants filed a motion to dismiss, and on March 29, 2016, the Delaware court granted Defendants’ motion and dismissed the lawsuit. On April 26, 2016, Dieckman filed his Notice of Appeal to the Supreme Court of Delaware. This appeal is styled Adrian Dieckman v. Regency GP LP, et al., No. 208, 2016, in the Supreme Court of the State of Delaware. Dieckman filed his Opening Brief on June 9, 2016, and Defendants’ filed their Answering Brief on July 29, 2016. On August 31, 2016, Dieckman filed his Reply Brief. Oral argument was held on November 16, 2016 before the Delaware Supreme Court. On January 20, 2017, the Delaware Supreme Court issued an order reversing the judgment of the Court of Chancery that dismissed Counts I and II of the Dieckman’s Complaint. 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 has filed a notice of appeal with the Texas Court of Appeals, and briefing by Enterprise and ETP is complete. Oral argument was held on April 20, 2016. The Court of Appeals is taking the briefs under advisement. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed. Sunoco Logistics Merger Litigation Between January 6, 2017 and February 8, 2017, seven purported ETP common unitholders (“Plaintiffs”) separately filed seven putative unitholder class action lawsuits challenging the merger and the disclosures made in connection with the merger. The lawsuits are styled (a) Koma v. Energy Transfer Partners, L.P., et al. , Case No. 3:17-cv-00060-G, in the United States District Court for the Northern District of Texas, Dallas Division (the “ Koma Lawsuit”); (b) Ashraf v. Energy Transfer Partners, L.P. et al. , Case No. 3:17-cv-00118-B, in the United States District Court for the Northern District of Texas, Dallas Division (the “ Ashraf Lawsuit”); (c) Shure v. Energy Transfer Partners, L.P. et al. , Case No. 1:17-cv-00044-UNA, in the United States District Court for the District of Delaware (the “ Shure Lawsuit”); (d) Verlin v. Energy Transfer Partners, L.P. et al. , Case No. 1:17-cv-00045-UNA, in the United States District Court for the District of Delaware (the “ Verlin Lawsuit”); (e) Duany v. Energy Transfer Partners, L.P. et al. , Case No. 1:17-cv-00058-UNA, in the United States District Court for the District of Delaware (the “ Duany Lawsuit”); (f) Epstein v. Energy Transfer Partners, L.P. et. al. , Case No, 1:17-cv-00069, in the United States District Court for the District of Delaware (the “ Epstein Lawsuit”) and (g) Sgnilek v. Energy Transfer Partners, L.P. et al. , Case No. 1:17-cv-00141, in the United States District Court for the District of Delaware (the “ Sgnilek Lawsuit” and collectively with the Koma Lawsuit, Ashraf Lawsuit, Shure Lawsuit, Verlin Lawsuit, Duany Lawsuit, and Epstein Lawsuit, the “Lawsuits”). The Koma Lawsuit, Ashraf Lawsuit, Duany Lawsuit, and Epstein Lawsuit are filed against ETP, ETP GP, ETP GP, LLC, ETE, and the members of the ETP Board. The Shure Lawsuit and Verlin Lawsuit are filed against ETP, ETP GP, the members of the ETP Board, ETE, Sunoco Logistics, and Sunoco Logistics GP. The Sgnilek Lawsuit is filed against ETP, ETP GP, ETP GP LLC, ETE, the members of the ETP Board, Sunoco Logistics and Sunoco Logistics GP (collectively “Defendants”). Plaintiffs allege causes of action challenging the merger and the preliminary joint proxy statement/prospectus filed in connection with the merger. According to Plaintiffs, the preliminary joint proxy statement/prospectus is allegedly misleading because, among other things, it fails to disclose certain information concerning, in general, (a) the background and process that led to the merger; (b) ETE’s, ETP’s, and Sunoco Logistics’ financial projections; (c) the financial analysis and fairness opinion provided by Barclays; and (d) alleged conflicts of interest concerning Barclays, ETE, and certain officers and directors of ETP and ETE. Based on these allegations, and in general, Plaintiffs allege that (i) Defendants have violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and (ii) the members of the ETP Board have violated Section 20(a) of the Exchange Act. Plaintiffs in the Shure Lawsuit and Verlin Lawsuit also allege that Sunoco Logistics has violated Section 20(a) of the Exchange Act. Plaintiffs also assert, in general, that the terms of the merger (including, among other terms, the merger consideration) are unfair to ETP common unitholders and resulted from an unfair and conflicted process. Based on these allegations, the Sgnilek Lawsuit alleges that (a) the ETP Board, ETP GP, ETP GP LLC, ETP, and ETE have breached the covenant of good faith and/or fiduciary duties, and (b) Sunoco Logistics and Sunoco Logistics GP have aided and abetted those alleged breaches. Based on these allegations, Plaintiffs seek to enjoin Defendants from proceeding with or consummating the merger unless and until Defendants disclose the allegedly omitted information summarized above. The Koma Lawsuit and Sgnilek Lawsuit also seek to enjoin Defendants from proceeding with or consummating the merger unless and until the ETP Board adopts and implements processes to obtain the best possible terms for ETP common unitholders. To the extent that the merger is consummated before injunctive relief is granted, Plaintiffs seek to have the merger rescinded. Plaintiffs also seek damages and attorneys’ fees. Defendants’ dates to answer, move to dismiss, or otherwise respond to the Lawsuits have not yet been set. Defendants cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of the filing of this annual report, nor can Defendants predict the amount of time and expense that will be required to resolve such litigation. Defendants believe the Lawsuits are without merit and intend to defend vigorously against the Lawsuits and any other actions challenging the merger. Litigation Filed By or Against WMB On April 6, 2016, WMB filed a complaint against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P. , C.A. No. 12168-VCG. WMB alleged that Defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates (the “Merger Agreement”) by issuing ETE’s Series A Convertible Preferred Units. According to WMB, the issuance of Convertible Units (the “Issuance”) violates various contractual restrictions on ETE’s actions between the execution and closing of the merger. WMB sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance. On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware WMB Litigation. The counterclaim asserts in general that WMB materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow WMB’s independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing the Texas WMB Litigation against Mr. Warren in the District Court of Dallas County, Texas. On May 13, 2016, WMB filed a second lawsuit in the Delaware Court of Chancery against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (the “Second Delaware WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG. In general, WMB alleged that the defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion under Section 721 of the Tax Code (“721 Opinion”), a condition precedent to the closing of the merger, and (b) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. WMB asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions. WMB sought to expedite the second lawsuit, and ETE agreed to expedite both Delaware actions. ETE also filed an answer and counterclaim in the Second Delaware WMB Litigation. In addition to the counterclaims previously asserted, ETE asserted that WMB materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the WMB board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger necessary to prevent the Form S-4 from being materially misleading, (c) failing to facilitate the financing of the merger, (d) failing to be reasonable with respect to its withholding of its consent to ETE’s offering of Series A Convertible Preferred Units, and (e) failing to use its reasonable best efforts to consummate the merger. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016. After expedited discovery and a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied WMB’s requests for injunctive relief. WMB filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. The appeal is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P. , No. 330, 2016. Williams filed an amended complaint on September 16, 2016. In the amended complaint, Williams abandons its request for injunctive relief, including its request that the Court order the ETE Defendants to consummate the merger. Instead, Williams seeks a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that the ETE Defendants breached an additional representation and warranty in the Merger Agreement. The ETE Defendants filed amended counterclaims and affirmative defenses on September 23, 2016. In the amended counterclaim, the ETE Defendants seek a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, Williams filed a motion to dismiss the ETE Defendants’ amended counterclaims and to strike certain of the ETE Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision. On January 11, 2017, the Delaware Supreme Court held oral arguments on Williams’ appeal of the June 2016 trial. The parties are awaiting the Court’s decision. The parties are currently engaging in discovery in connection with their amended claims and counterclaims. Unitholder Litigation Relating to the Issuance In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation , Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware. Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016. The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limited partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to the Convertible Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the issuance of Convertible Units. The parties engaged in discovery, and Plaintiffs’ filed a consolidated amended complaint on August 29, 2016. In addition to the injunctive relief described above, Plaintiffs seek class-wide damages allegedly resulting from the Issuance. On September 28, 2016, Defendants and Plaintiffs filed cross-motions for partial summary judgment. The Court held a hearing on the parties’ motions on November 9, 2016 and has taken the matter under advisement. 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, 2016 and 2015 , accruals of approximately $93 million and $40 million , respectively, were reflected on our 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, 2016 or 2015 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Compliance Orders from the New Mexico Environmental Department Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses. The Air Quality Bureau issued a Settlement Offer for Revised Notice of Violation REG-0569-1402-RI on February 7, 2017. The Settlement Agreement includes a civil penalty of $465,000 . Energy Transfer and the New Mexico Environmental Department are scheduling a meeting to discuss the Settlement Offer in March 2017. Lone Star NGL Fractionators Notice of Enforcement Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to Mont Belvieu Gas Plant. The Partnership has accrued $50,000 related to this claim as of December

Retirement Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Retirement Benefits	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, including those of ETP, Sunoco LP and Lake Charles LNG. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries have made matching contributions of $44 million , $40 million and $50 million to the 401(k) savings plan for the years ended December 31, 2016, 2015, and 2014 , respectively. Pension and Other Postretirement Benefit Plans Panhandle Postretirement benefits expense for the years ended December 31, 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, 2016 December 31, 2015 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 $ 20 $ 57 $ 181 $ 718 $ 65 $ 203 Interest cost 1 2 4 23 2 4 Amendments — — — — — — Benefits paid, net (1 ) (7 ) (21 ) (46 ) (8 ) (20 ) Actuarial (gain) loss and other (2 ) (1 ) 2 16 (2 ) (6 ) Settlements — — — (691 ) — — Benefit obligation at end of period $ 18 $ 51 $ 166 $ 20 $ 57 $ 181 Change in plan assets: Fair value of plan assets at beginning of period $ 15 $ — $ 261 $ 598 $ — $ 272 Return on plan assets and other (2 ) — 6 16 — — Employer contributions — — 10 138 — 9 Benefits paid, net (1 ) — (21 ) (46 ) — (20 ) Settlements — — — (691 ) — — Fair value of plan assets at end of period $ 12 $ — $ 256 $ 15 $ — $ 261 Amount underfunded (overfunded) at end of period $ 6 $ 51 $ (90 ) $ 5 $ 57 $ (80 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 114 $ — $ — $ 103 Current liabilities — (7 ) (2 ) — (9 ) (2 ) Non-current liabilities (6 ) (44 ) (23 ) (5 ) (48 ) (22 ) $ (6 ) $ (51 ) $ 89 $ (5 ) $ (57 ) $ 79 Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: Net actuarial gain $ — $ — $ (13 ) $ 2 $ 4 $ (18 ) Prior service cost — — 15 — — 16 $ — $ — $ 2 $ 2 $ 4 $ (2 ) The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2016 December 31, 2015 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 18 $ 51 N/A $ 20 $ 57 N/A Accumulated benefit obligation 18 51 $ 166 20 57 $ 181 Fair value of plan assets 12 — 256 15 — 261 Components of Net Periodic Benefit Cost December 31, 2016 December 31, 2015 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net Periodic Benefit Cost: Interest cost $ 3 $ 4 $ 25 $ 4 Expected return on plan assets (1 ) (8 ) (16 ) (8 ) Prior service cost amortization — 1 — 1 Actuarial loss amortization — — — — Settlements — — 32 — Net periodic benefit cost $ 2 $ (3 ) $ 41 $ (3 ) Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2016 December 31, 2015 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.65 % 2.34 % 3.59 % 2.38 % 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, 2016 December 31, 2015 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.60 % 3.06 % 3.65 % 2.79 % Expected return on assets: Tax exempt accounts 3.50 % 7.00 % 7.50 % 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’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: December 31, 2016 2015 Health care cost trend rate 6.73 % 7.16 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.96 % 5.39 % Year that the rate reaches the ultimate trend rate 2021 2018 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% and cash and cash equivalents of up to 10% . 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, 2016 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Mutual funds (1) $ 12 $ 12 $ — $ — Total $ 12 $ 12 $ — $ — (1) Comprised of 100% equities as of December 31, 2016 . Fair Value Measurements at December 31, 2015 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Mutual funds (1) $ 15 $ — $ 15 $ — Total $ 15 $ — $ 15 $ — (1) Comprised of 100% equities as of December 31, 2015 . The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows: 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) 142 142 — — Fixed income securities 91 — 91 — Total $ 256 $ 165 $ 91 $ — (1) Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016 . Fair Value Measurements at December 31, 2015 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Cash and Cash Equivalents $ 18 $ 18 $ — $ — Mutual funds (1) 141 141 — — Fixed income securities 102 — 102 — Total $ 261 $ 159 $ 102 $ — (1) Primarily comprised of approximately 56% equities, 33% fixed income securities and 11% cash as of December 31, 2015 . 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 $12 million to pension plans and $10 million to other postretirement plans in 2017 . 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’s 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: Pension Benefits Years Funded Plans Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2017 $ 1 $ 7 $ 26 2018 1 7 25 2019 1 6 23 2020 1 6 22 2021 1 5 19 2022 – 2026 6 17 39 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

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS: The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements. In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions (see Note 15 ). In addition, subsidiaries of ETE recorded sales with affiliates of $221 million , $290 million and $965 million during the years ended December 31, 2016 , 2015 and 2014 , respectively.

Reportable Segments

Reportable Segments	12 Months Ended
	Dec. 31, 2016
Reportable Segments [Abstract]
Reportable Segments	REPORTABLE SEGMENTS: Subsequent to ETE’s acquisition of a controlling interest in Sunoco LP, our financial statements reflect the following reportable business segments: • Investment in ETP, including the consolidated operations of ETP; • Investment in Sunoco LP, including the consolidated operations of Sunoco LP; • Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and • Corporate and Other, including the following: • activities of the Parent Company; and • the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P. ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented. The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP the equity in earnings from which is also eliminated in ETE’s consolidated financial statements. 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. Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation. Eliminations in the tables below include the following: • ETP’s Segment Adjusted EBITDA reflected the results of Lake Charles LNG prior to the Lake Charles LNG Transaction, which was effective January 1, 2014. The Investment in Lake Charles LNG segment reflected the results of operations of Lake Charles LNG for all periods presented. Consequently, the results of operations of Lake Charles LNG were reflected in two segments for the year ended December 31, 2013. Therefore, the results of Lake Charles LNG were included in eliminations for 2013. • MACS, Sunoco LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP, as discussed above. Years Ended December 31, 2016 2015 2014 Revenues: Investment in ETP: Revenues from external customers $ 21,618 $ 34,156 $ 55,475 Intersegment revenues 209 136 — 21,827 34,292 55,475 Investment in Sunoco LP: Revenues from external customers 8,287 10,527 4,291 Intersegment revenues 9 11 — 8,296 10,538 4,291 Investment in Lake Charles LNG: Revenues from external customers 197 216 216 Adjustments and Eliminations: (218 ) (10,842 ) (7,343 ) Total revenues $ 30,102 $ 34,204 $ 52,639 Costs of products sold: Investment in ETP $ 15,394 $ 27,029 $ 48,414 Investment in Sunoco LP 7,459 9,902 4,214 Adjustments and Eliminations (217 ) (9,496 ) (6,767 ) Total costs of products sold $ 22,636 $ 27,435 $ 45,861 Depreciation, depletion and amortization: Investment in ETP $ 1,986 $ 1,929 $ 1,669 Investment in Sunoco LP 126 103 31 Investment in Lake Charles LNG 39 39 39 Corporate and Other 15 17 16 Adjustments and Eliminations — (184 ) (86 ) Total depreciation, depletion and amortization $ 2,166 $ 1,904 $ 1,669 Years Ended December 31, 2016 2015 2014 Equity in earnings of unconsolidated affiliates: Investment in ETP $ 336 $ 469 $ 332 Adjustments and Eliminations (66 ) (193 ) — Total equity in earnings of unconsolidated affiliates $ 270 $ 276 $ 332 Years Ended December 31, 2016 2015 2014 Segment Adjusted EBITDA: Investment in ETP $ 5,605 $ 5,714 $ 5,710 Investment in Sunoco LP 665 719 332 Investment in Lake Charles LNG 179 196 195 Corporate and Other (170 ) (104 ) (97 ) Adjustments and Eliminations (272 ) (590 ) (300 ) Total Segment Adjusted EBITDA 6,007 5,935 5,840 Depreciation, depletion and amortization (2,166 ) (1,904 ) (1,669 ) Interest expense, net of interest capitalized (1,803 ) (1,621 ) (1,368 ) Gains on acquisitions 83 — — Gain on sale of AmeriGas common units — — 177 Impairment of investment in affiliate (308 ) — — Impairment losses (970 ) (339 ) (370 ) Losses on interest rate derivatives (12 ) (18 ) (157 ) Non-cash unit-based compensation expense (70 ) (91 ) (82 ) Unrealized gains (losses) on commodity risk management activities (136 ) (65 ) 116 Losses on extinguishments of debt — (43 ) (25 ) Inventory valuation adjustments 267 (229 ) (445 ) Adjusted EBITDA related to discontinued operations (293 ) (345 ) (208 ) Adjusted EBITDA related to unconsolidated affiliates (675 ) (713 ) (748 ) Equity in earnings of unconsolidated affiliates 270 276 332 Other, net 78 21 (74 ) Income from continuing operations before income tax expense $ 272 $ 864 $ 1,319 December 31, 2016 2015 2014 Total assets: Investment in ETP $ 70,191 $ 65,173 $ 62,518 Investment in Sunoco LP 8,701 8,842 8,773 Investment in Lake Charles LNG 1,508 1,369 1,210 Corporate and Other 711 638 1,119 Adjustments and Eliminations (2,100 ) (4,833 ) (9,341 ) Total $ 79,011 $ 71,189 $ 64,279 Years Ended December 31, 2016 2015 2014 Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis): Investment in ETP $ 5,810 $ 8,167 $ 5,494 Investment in Sunoco LP 439 491 154 Investment in Lake Charles LNG — 1 1 Adjustments and Eliminations — (123 ) (90 ) Total $ 6,249 $ 8,536 $ 5,559 December 31, 2016 2015 2014 Advances to and investments in affiliates: Investment in ETP $ 4,280 $ 5,003 $ 3,760 Adjustments and Eliminations (1,240 ) (1,541 ) (101 ) Total $ 3,040 $ 3,462 $ 3,659 The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP. Investment in ETP Years Ended December 31, 2016 2015 2014 Intrastate Transportation and Storage $ 2,155 $ 1,912 $ 2,645 Interstate Transportation and Storage 946 1,008 1,057 Midstream 2,342 2,607 4,770 NGL and refined products transportation and services 5,973 4,569 4,746 Crude oil transportation and services 7,539 8,980 16,904 All Other 2,872 15,216 25,353 Total revenues 21,827 34,292 55,475 Less: Intersegment revenues 209 136 — Revenues from external customers $ 21,618 $ 34,156 $ 55,475 Investment in Sunoco LP Years Ended December 31, 2016 2015 2014 Retail operations $ 301 $ 334 $ 43 Wholesale operations 7,995 10,204 4,248 Total revenues 8,296 10,538 4,291 Less: Intersegment revenues 9 11 — Revenues from external customers $ 8,287 $ 10,527 $ 4,291 Investment in Lake Charles LNG Lake Charles LNG’s revenues of $197 million , $216 million and $216 million for the years ended December 31, 2016, 2015 and 2014, respectively, were related to LNG terminalling.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	QUARTERLY FINANCIAL DATA (UNAUDITED): Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year. Quarters Ended March 31 June 30 September 30 December 31 Total Year 2016: Revenues $ 6,083 $ 7,415 $ 7,705 $ 8,899 $ 30,102 Operating income (loss) 695 805 646 (236 ) 1,910 Net income (loss) 336 424 41 (760 ) 41 Limited Partners’ interest in net income 311 239 207 226 983 Basic net income per limited partner unit $ 0.30 $ 0.23 $ 0.20 $ 0.22 $ 0.94 Diluted net income per limited partner unit $ 0.30 $ 0.23 $ 0.19 $ 0.21 $ 0.92 Quarters Ended March 31 June 30 September 30 December 31 Total Year 2015: Revenues $ 8,564 $ 9,423 $ 8,473 $ 7,744 $ 34,204 Operating income 589 878 573 210 2,250 Net income (loss) 221 772 238 (138 ) 1,093 Limited Partners’ interest in net income 282 298 291 312 1,183 Basic net income per limited partner unit $ 0.26 $ 0.28 $ 0.28 $ 0.30 $ 1.11 Diluted net income per limited partner unit $ 0.26 $ 0.28 $ 0.28 $ 0.30 $ 1.11 The three months ended December 31, 2015 reflected the unfavorable impact of $120 million related to non-cash inventory valuation adjustments primarily in ETP’s retail marketing operations and our investment in Sunoco LP. The three months ended December 31, 2016 and 2015 reflected the recognition of impairment losses of $970 million and $339 million , respectively. Impairment losses in 2016 were primarily related to ETP’s interstate operations, midstream midcontinent operations and retail operations. In 2015 , impairment losses were primarily related to Lone Star Refinery Services operations and ETP’s Transwestern pipeline. The three months ended September 30, 2016 reflected the recognition of a non-cash impairment of ETP’s investment in MEP of $308 million in our interstate transportation and storage operations.

Supplemental Financial Statemen

Supplemental Financial Statement Information	12 Months Ended
	Dec. 31, 2016
Supplemental Financial Statement Information
Supplemental Financial Statement Information	SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION: Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis: BALANCE SHEETS December 31, 2016 2015 ASSETS CURRENT ASSETS: Cash and cash equivalents $ 2 $ 1 Accounts receivable from related companies 55 34 Total current assets 57 35 PROPERTY, PLANT AND EQUIPMENT, net 36 20 ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES 5,088 5,764 INTANGIBLE ASSETS, net 1 6 GOODWILL 9 9 OTHER NON-CURRENT ASSETS, net 10 10 Total assets $ 5,201 $ 5,844 LIABILITIES AND PARTNERS’ CAPITAL CURRENT LIABILITIES: Accounts payable $ 1 $ — Accounts payable to related companies 22 111 Interest payable 66 66 Accrued and other current liabilities 3 1 Total current liabilities 92 178 LONG-TERM DEBT, less current maturities 6,358 6,332 NOTE PAYABLE TO AFFILIATE 443 265 OTHER NON-CURRENT LIABILITIES 2 1 COMMITMENTS AND CONTINGENCIES PARTNERS’ DEFICIT: General Partner (3 ) (2 ) Limited Partners: Common Unitholders (1,046,947,157 and 1,044,767,336 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively) (1,871 ) (952 ) Class D Units (2,156,000 units authorized, issued and outstanding as of December 31, 2015) — 22 Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016) 180 — Total partners’ deficit (1,694 ) (932 ) Total liabilities and partners’ deficit $ 5,201 $ 5,844 STATEMENTS OF OPERATIONS Years Ended December 31, 2016 2015 2014 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES $ (185 ) $ (112 ) $ (111 ) OTHER INCOME (EXPENSE): Interest expense, net of interest capitalized (327 ) (294 ) (205 ) Equity in earnings of unconsolidated affiliates 1,511 1,601 955 Other, net (4 ) (5 ) (5 ) INCOME BEFORE INCOME TAXES 995 1,190 634 Income tax expense — 1 1 NET INCOME 995 1,189 633 General Partner’s interest in net income 3 3 2 Convertible Unitholders’ interest in income 9 — — Class D Unitholder’s interest in net income — 3 2 Limited Partners’ interest in net income $ 983 $ 1,183 $ 629 STATEMENTS OF CASH FLOWS Years Ended December 31, 2016 2015 2014 NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 918 $ 1,103 $ 816 CASH FLOWS FROM INVESTING ACTIVITIES: Cash paid for Bakken Pipeline Transaction — (817 ) — Contributions to unconsolidated affiliates (70 ) — (118 ) Capital expenditures (16 ) (19 ) — Purchase of additional interest in Regency — — (800 ) Net cash used in investing activities (86 ) (836 ) (918 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings 225 3,672 3,020 Principal payments on debt (210 ) (1,985 ) (1,142 ) Distributions to partners (1,022 ) (1,090 ) (821 ) Proceeds from affiliate 176 210 54 Units repurchased under buyback program — (1,064 ) (1,000 ) Debt issuance costs — (11 ) (15 ) Net cash provided by (used in) financing activities (831 ) (268 ) 96 INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 1 (1 ) (6 ) CASH AND CASH EQUIVALENTS, beginning of period 1 2 8 CASH AND CASH EQUIVALENTS, end of period $ 2 $ 1 $ 2

Estimates, Significant Accoun25

Estimates, Significant Accounting Policies and Balance Sheet Detail (Policy)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
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, 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]	New Accounting Pronouncements 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. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catchup transition method). The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method. We are in the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standards. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts may be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We continue to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us. 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. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. In October 2016, the FASB issued 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. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that adoption of this standard will have on the consolidated financial statements and related disclosures. On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-09, Stock Compensation (Topic 718) (“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures. On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-17, Consolidation (Topic 810): Interests Held Through Related Parties That Are Under Common Control (“ASU 2016-17”), which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (VIE) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under the amendments, a single decision maker is required to include indirect interests on a proportionate basis consistent with indirect interests held through other related parties. Adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures. 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 does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We expect that our adoption of this standard will change our approach for testing goodwill for impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption.
Revenue Recognition	Revenue Recognition Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments. Investment in ETP 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 or installation. 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. The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, 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. ETP’s intrastate transportation and storage operations also generate 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, ETP purchases natural gas from the market, including purchases from ETP’s marketing operations, and from producers at the wellhead. In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects 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, ETP 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 ETP operate, competitive factors in the energy industry, and other issues. Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and segment margins principally under fee-based or other arrangements in which ETP receives 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 ETP’s systems and is not directly dependent on commodity prices. ETP also utilizes other types of arrangements in ETP’s midstream operations, 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 ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells 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 ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s 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 ETP’s 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. ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells 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. Investment in Sunoco LP Revenues from Sunoco LP’s two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Revenue recognition on consignment sales differ from this and are discussed in greater detail below. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Through PropCo, Sunoco LP’s wholly owned corporate subsidiary, Sunoco LP may sell motor fuel to wholesale customers on a consignment basis, in which Sunoco LP retains title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. Sunoco LP derives other income from rental income, propane and lubricating oils and other ancillary product and service offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals and other ancillary product and service offerings. Sunoco LP records revenue on a net commission basis when the product is sold and/or services are rendered. Rental income from operating leases is recognized on a straight line basis over the term of the lease. Investment in Lake Charles LNG Lake Charles LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Lake Charles LNG’s terminal.
Regulatory Accounting - Regulatory Assets and Liabilities	Regulatory Accounting – Regulatory Assets and Liabilities ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations 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 ETP’s 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, ETP ceases 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 NGA and NGPA, 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 which 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 subsidiaries assess the credit risk of their customers and take steps to mitigate risk as necessary. Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and identification of specific customers with payment issues.
Inventories	Inventories Inventories consist principally of natural gas held in storage, crude oil, refined products and spare parts. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and refined products is determined using the last-in, first out method. The cost of spare parts is determined by the first-in, first-out method. Inventories consisted of the following: December 31, 2016 2015 Natural gas and NGLs $ 699 $ 415 Crude oil 683 424 Refined products 483 378 Spare parts and other 238 248 Total inventories $ 2,103 $ 1,465 During the year ended December 31, 2015, the Partnership’s income from continuing operations included a write-down of $229 million on its crude oil, refined products and NGL inventories as a result of declines in the market price of these products. The write-down was calculated based upon current replacement costs. ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in 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. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. For the Lake Charles LNG project, a portion of the management fees are capitalized. 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 2016, ETP recorded a $133 million fixed asset impairment related to the interstate transportation and storage operations 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 ETP’s midstream operations. In 2015, we recorded $110 million fixed asset impairments related to ETP’s NGL and refined products transportation and services operations 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 facilities 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.
Equity and Cost Method Investments, Policy [Policy Text Block]	Advances to and Investments in Affiliates Certain of our subsidiaries 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.
Other Non-Current Assets, net	Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization.
Intangible Assets	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, 2016 December 31, 2015 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 6,050 $ (971 ) $ 5,199 $ (712 ) Trade names (15 years) 352 (22 ) 66 (18 ) Patents (9 years) 25 (21 ) 48 (16 ) Other (1 to 15 years) 42 (9 ) 14 — Total amortizable intangible assets 6,469 (1,023 ) 5,327 (746 ) Non-amortizable intangible assets: Trademarks — — 281 — Contractual rights 43 — 34 — Liquor licenses — — — — Total intangible assets $ 6,512 $ (1,023 ) $ 5,642 $ (746 ) Aggregate amortization expense of intangibles assets was as follows: Years Ended December 31, 2016 2015 2014 Reported in depreciation, depletion and amortization $ 262 $ 288 $ 212 Estimated aggregate amortization expense of intangible assets for the next five years was as follows: Years Ending December 31: 2017 $ 279 2018 277 2019 273 2020 268 2021 251 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.
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: Investment in ETP Investment in Sunoco LP Investment in Lake Charles LNG Corporate, Other and Eliminations Total Balance, December 31, 2014 $ 7,642 $ 1,149 $ 184 $ (3,104 ) $ 5,871 Goodwill acquired — 23 — — 23 Sunoco LP Exchange (2,018 ) — — 2,018 — Goodwill impairment (205 ) — — — (205 ) Other 9 (49 ) — (164 ) (204 ) Balance, December 31, 2015 5,428 1,123 184 (1,250 ) 5,485 Goodwill acquired 428 81 — — 509 Contribution of retail business (1,289 ) — — 1,289 — Goodwill impairment (670 ) (156 ) — — (826 ) Other — 2 — — 2 Balance, December 31, 2016 $ 3,897 $ 1,050 $ 184 $ 39 $ 5,170 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 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage operations and $32 million in the midstream operations 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. Sunoco LP recognized goodwill impairments of $642 million , of which $156 million was allocated to continuing operations, 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 2015, ETP performed goodwill impairment tests on its reporting units and recognized goodwill impairments of: (i) $99 million in the Transwestern reporting unit due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015, and (ii) $106 million in the Lone Star Refinery Services reporting unit due primarily to changes in assumptions related to potential future revenues decrease as well as the market declines in current and expected future commodity prices. 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 recorded by Panhandle and Sunoco Logistics discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2016 and 2015 , 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. Sunoco Logistics believes it 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, 2016 and 2015, other non-current liabilities in ETP’s consolidated balance sheets included AROs of $170 million and $212 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.
Accrued and Other Current Liabilities Policy [Text Block]	Deposits or advances are received from 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 Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on the 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	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 consolidated debt obligations as of December 31, 2016 was $45.05 billion and $43.80 billion , respectively. As of December 31, 2015 , the aggregate fair value and carrying amount of our consolidated debt obligations was $33.22 billion and $36.97 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 the ETP 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. Derivatives related to the embedded derivatives in our preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the year ended December 31, 2016 , no transfers were made between any levels within the fair value hierarchy.
Contributions In Aid Of Construction Costs Policy Text Block	Contributions in Aid of Construction Cost 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 Costs of products sold include actual cost of fuel sold, adjusted for the effects of 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 governmental authorities on a net basis except for our retail marketing operations 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). Excise taxes collected by our retail marketing operations, including discontinued operations, were $3.48 billion , $3.05 billion and $2.46 billion for the years ended December 31, 2016 , 2015 and 2014 , respectively.
Issuances of Subsidiary Units	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 subsidiaries’ 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 Taxes	Income Taxes ETE 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 state income tax 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 reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third 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, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2016, 2015, and 2014 , 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, Oasis Pipeline Company, Susser Petroleum Property Company, Aloha Petroleum and 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 the consolidated statement 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 statement 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, a 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 previously have managed 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 Employers are required to recognize in their balance sheets 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. Employers must recognize the change in the funded status of the plan 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, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

Estimates, Significant Accoun26

Estimates, Significant Accounting Policies and Balance Sheet Detail (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities	The net change in operating assets and liabilities (net of effects of acquisitions, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows: Years Ended December 31, 2016 2015 2014 Accounts receivable $ (1,126 ) $ 856 $ 600 Accounts receivable from related companies 42 (5 ) 30 Inventories (345 ) (410 ) 52 Other current assets 149 (225 ) 151 Other non-current assets, net (148 ) 250 (6 ) Accounts payable 1,214 (1,043 ) (893 ) Accounts payable to related companies (64 ) 400 5 Exchanges payable — — — Accrued and other current liabilities 89 (697 ) (158 ) Other non-current liabilities 158 (233 ) (138 ) Derivative assets and liabilities, net 67 75 19 Net change in operating assets and liabilities, net of effects of acquisitions $ 36 $ (1,032 ) $ (338 )
Schedule Of Non-Cash Investing And Financing Activities	Non-cash investing and financing activities and supplemental cash flow information were as follows: Years Ended December 31, 2016 2015 2014 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 930 $ 910 $ 643 Net gains (losses) from subsidiary common unit transactions 16 (526 ) 744 NON-CASH FINANCING ACTIVITIES: Issuance of Common Units in connection with the PennTex Acquisition 307 — — Contribution of property, plant and equipment from noncontrolling interest — 34 — Subsidiary issuances of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions — — 4,281 Subsidiary issuances of common units in connection with the Susser Merger — — 908 Long-term debt assumed in PVR Acquisition — — 1,887 Long-term debt exchanged in Eagle Rock Midstream Acquisition — — 499 SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized 1,922 1,800 1,416 Cash paid for (refund of) income taxes (229 ) 72 345
Schedule of Inventory	Inventories consisted of the following: December 31, 2016 2015 Natural gas and NGLs $ 699 $ 415 Crude oil 683 424 Refined products 483 378 Spare parts and other 238 248 Total inventories $ 2,103 $ 1,465
Other Current Assets	Other current assets consisted of the following: December 31, 2016 2015 Deposits paid to vendors $ 74 $ 74 Income taxes receivable 128 326 Prepaid expenses and other 301 193 Total other current assets $ 503 $ 593
Property, Plant and Equipment	Components and useful lives of property, plant and equipment were as follows: December 31, 2016 2015 Land and improvements $ 1,160 $ 1,008 Buildings and improvements (1 to 45 years) 2,197 1,629 Pipelines and equipment (5 to 83 years) 35,593 32,677 Natural gas and NGL storage facilities (5 to 46 years) 1,515 390 Bulk storage, equipment and facilities (2 to 83 years) 3,677 2,853 Tanks and other equipment (5 to 40 years) 1,286 1,488 Retail equipment (2 to 99 years) 427 436 Vehicles (1 to 25 years) 241 220 Right of way (20 to 83 years) 3,374 2,573 Natural resources 434 484 Other (1 to 40 years) 1,031 1,296 Construction work-in-process 10,223 7,797 61,158 52,851 Less – Accumulated depreciation and depletion (7,905 ) (6,067 ) Property, plant and equipment, net $ 53,253 $ 46,784
Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense	We recognized the following amounts for the periods presented: Years Ended December 31, 2016 2015 2014 Depreciation and depletion expense $ 1,904 $ 1,616 $ 1,409 Capitalized interest, excluding AFUDC 200 163 101
Schedule of 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, 2016 2015 Unamortized financing costs (1) $ 13 $ 29 Regulatory assets 86 90 Deferred charges 217 198 Restricted funds 190 192 Other 310 202 Total other non-current assets, net $ 816 $ 711 (1) Includes unamortized financing costs related to the Partnership’s revolving credit facilities.
Components And Useful Lives Of Intangibles And Other Assets	Components and useful lives of intangible assets were as follows: December 31, 2016 December 31, 2015 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 6,050 $ (971 ) $ 5,199 $ (712 ) Trade names (15 years) 352 (22 ) 66 (18 ) Patents (9 years) 25 (21 ) 48 (16 ) Other (1 to 15 years) 42 (9 ) 14 — Total amortizable intangible assets 6,469 (1,023 ) 5,327 (746 ) Non-amortizable intangible assets: Trademarks — — 281 — Contractual rights 43 — 34 — Liquor licenses — — — — Total intangible assets $ 6,512 $ (1,023 ) $ 5,642 $ (746 )
Aggregate Amortization Expense Of Intangibles And Other Assets	Aggregate amortization expense of intangibles assets was as follows: Years Ended December 31, 2016 2015 2014 Reported in depreciation, depletion and amortization $ 262 $ 288 $ 212
Estimated Aggregate Amortization Expense	Estimated aggregate amortization expense of intangible assets for the next five years was as follows: Years Ending December 31: 2017 $ 279 2018 277 2019 273 2020 268 2021 251
Schedule of Goodwill	Changes in the carrying amount of goodwill were as follows: Investment in ETP Investment in Sunoco LP Investment in Lake Charles LNG Corporate, Other and Eliminations Total Balance, December 31, 2014 $ 7,642 $ 1,149 $ 184 $ (3,104 ) $ 5,871 Goodwill acquired — 23 — — 23 Sunoco LP Exchange (2,018 ) — — 2,018 — Goodwill impairment (205 ) — — — (205 ) Other 9 (49 ) — (164 ) (204 ) Balance, December 31, 2015 5,428 1,123 184 (1,250 ) 5,485 Goodwill acquired 428 81 — — 509 Contribution of retail business (1,289 ) — — 1,289 — Goodwill impairment (670 ) (156 ) — — (826 ) Other — 2 — — 2 Balance, December 31, 2016 $ 3,897 $ 1,050 $ 184 $ 39 $ 5,170
Accrued and Other Current Liabilities	Accrued and other current liabilities consisted of the following: December 31, 2016 2015 Interest payable $ 545 $ 519 Customer advances and deposits 72 114 Accrued capital expenditures 769 743 Accrued wages and benefits 254 218 Taxes payable other than income taxes 201 76 Exchanges payable 208 106 Other 318 632 Total accrued and other current liabilities $ 2,367 $ 2,408
Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis	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, 2016 and 2015 based on inputs used to derive their fair values: Fair Value Measurements at Fair Value Total 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 2 2 — — Crude – Futures 9 9 — — Total commodity derivatives 363 356 7 — Total assets $ 363 $ 356 $ 7 $ — Liabilities: Interest rate derivatives $ (193 ) $ — $ (193 ) $ — Embedded derivatives in the 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 (23 ) (23 ) — — Crude — Futures (13 ) (13 ) — — Total commodity derivatives (478 ) (470 ) (8 ) — Total liabilities $ (672 ) $ (470 ) $ (201 ) $ (1 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 16 $ 16 $ — $ — Swing Swaps IFERC 10 2 8 — Fixed Swaps/Futures 274 274 — — Forward Physical Contracts 4 — 4 — Power: Forwards 22 — 22 — Futures 3 3 — — Options — Calls 1 1 — — Options — Puts 1 1 — — Natural Gas Liquids — Forwards/Swaps 99 99 — — Refined Products – Futures 15 15 — — Crude – Futures 9 9 — — Total commodity derivatives 454 420 34 — Total assets $ 454 $ 420 $ 34 $ — Liabilities: Interest rate derivatives $ (171 ) $ — $ (171 ) $ — Embedded derivatives in the ETP Preferred Units (5 ) — — (5 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (16 ) (16 ) — — Swing Swaps IFERC (12 ) (2 ) (10 ) — Fixed Swaps/Futures (203 ) (203 ) — — Power: Forwards (22 ) — (22 ) — Futures (2 ) (2 ) — — Options — Puts (1 ) (1 ) — — Natural Gas Liquids — Forwards/Swaps (89 ) (89 ) — — Refined Products – Futures (6 ) (6 ) — — Crude — Futures (5 ) (5 ) — — Total commodity derivatives (356 ) (324 ) (32 ) — Total liabilities $ (532 ) $ (324 ) $ (203 ) $ (5 )
Unobservable Inputs of Fair Value Level 3 Liabilities [Table Text Block]	The following table presents the material unobservable inputs used to estimate the fair value of ETP’s Preferred Units and the embedded derivatives in ETP’s Preferred Units: Unobservable Input December 31, 2016 Embedded derivatives in the ETP Preferred Units Credit Spread 5.12 % Volatility 31.73 %
Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis	The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2016 . Balance, December 31, 2015 $ (5 ) Net unrealized gains included in other income (expense) 4 Balance, December 31, 2016 $ (1 )

Acquisitions and Related Tran27

Acquisitions and Related Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Disposal Groups, Including Discontinued Operations [Table Text Block]	The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet: December 31, 2016 December 31, 2015 Carrying amount of assets classified as held for sale: Cash and cash equivalents $ 20 $ 25 Inventories 188 171 Other current assets 83 10 Property, plant and equipment, net 2,185 1,899 Goodwill 1,568 1,988 Intangible assets, net 503 535 Other non-current assets, net 2 19 Total assets classified as held for sale in the Consolidated Balance Sheet $ 4,549 $ 4,647 Carrying amount of liabilities classified as held for sale: Other non-current liabilities 68 67 Total liabilities classified as held for sale in the Consolidated Balance Sheet $ 68 $ 67 The results of operations associated with discontinued operations are presented in the following table: Years Ended 2016 2015 2014 REVENUES $ 7,402 $ 7,922 $ 3,052 COSTS AND EXPENSES Cost of products sold 6,020 6,574 2,553 Operating expenses 1,486 933 291 Depreciation and amortization 193 175 55 Selling, general and administrative 114 91 55 Total costs and expenses 7,813 7,773 2,954 OPERATING INCOME (411 ) 149 98 Interest expense, net 29 22 1 Other, net 8 (2 ) (1 ) INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (448 ) 129 98 Income tax expense 31 48 32 INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES $ (479 ) $ 81 $ 66 INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE ATTRIBUTABLE TO ETE $ (12 ) $ 1 $ 3
PennTex [Member]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	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.
Susser Merger [Member]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	Summary of Assets Acquired and Liabilities Assumed ETP accounted for the Susser Merger 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 following table summarizes the assets acquired and liabilities assumed recognized as of the merger date: Susser Total current assets $ 446 Property, plant and equipment 1,069 Goodwill (1) 1,734 Intangible assets 611 Other non-current assets 17 3,877 Total current liabilities 377 Long-term debt, less current maturities 564 Deferred income taxes 488 Other non-current liabilities 39 Noncontrolling interest 626 2,094 Total consideration 1,783 Cash received 67 Total consideration, net of cash received $ 1,716 (1) None of the goodwill is expected to be deductible for tax purposes.
Eagle Rock Midstream Acquisition [Member]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	The total purchase price was allocated as follows: Assets At July 1, 2014 Current assets $ 120 Property, plant and equipment 1,295 Other non-current assets 4 Goodwill 49 Total assets acquired 1,468 Liabilities Current liabilities 116 Long-term debt 499 Other non-current liabilities 12 Total liabilities assumed 627 Net assets acquired $ 841 The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
PVR Acquisition [Member]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	Regency completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows: Assets At March 21, 2014 Current assets $ 149 Property, plant and equipment 2,716 Investment in unconsolidated affiliates 62 Intangible assets (average useful life of 30 years) 2,717 Goodwill (1) 370 Other non-current assets 18 Total assets acquired 6,032 Liabilities Current liabilities 168 Long-term debt 1,788 Premium related to senior notes 99 Non-current liabilities 30 Total liabilities assumed 2,085 Net assets acquired $ 3,947 (1) None of the goodwill is expected to be deductible for tax purposes.

Advances to and Investments i28

Advances to and Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2016
Investment In Affiliates [Abstract]
Schedule Of Aggregated Selected Balance Sheet And Income Statement Data For Our Unconsolidated Affiliates	The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2016 and 2015 , were as follows: December 31, 2016 2015 Citrus $ 1,729 $ 1,739 AmeriGas 82 80 FEP 101 115 MEP 318 660 HPC 382 402 Others 428 466 Total $ 3,040 $ 3,462 Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented: December 31, 2016 2015 Current assets $ 720 $ 632 Property, plant and equipment, net 9,982 10,213 Other assets 2,618 2,649 Total assets $ 13,320 $ 13,494 Current liabilities $ 1,358 $ 841 Non-current liabilities 7,583 7,950 Equity 4,379 4,703 Total liabilities and equity $ 13,320 $ 13,494 Years Ended December 31, 2016 2015 2014 Revenue $ 3,509 $ 4,026 $ 4,925 Operating income 1,181 1,302 1,071 Net income 602 807 577 In addition to the equity method investments described above our subsidiaries 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, 2016
Earnings Per Share [Abstract]
Reconciliation Of Net Income (Loss) And Weighted Average Units	A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows: Years Ended December 31, 2016 2015 2014 Income from continuing operations $ 520 $ 1,012 $ 994 Less: Income (loss) from continuing operations attributable to noncontrolling interest (487 ) (176 ) 371 Income from continuing operations, net of noncontrolling interest 1,007 1,188 623 Less: General Partner’s interest in income from continuing operations 3 3 2 Less: Convertible Unitholders’ interest in net income from continuing operations 8 — — Less: Class D Unitholder’s interest in income from continuing operations — 3 2 Income from continuing operations available to Limited Partners $ 996 $ 1,182 $ 619 Basic Income from Continuing Operations per Limited Partner Unit: Weighted average limited partner units 1,045.5 1,062.8 1,088.6 Basic income from continuing operations per Limited Partner unit $ 0.95 $ 1.11 $ 0.57 Basic income (loss) from discontinued operations per Limited Partner unit $ (0.01 ) $ — $ 0.01 Diluted Income from Continuing Operations per Limited Partner Unit: Income from continuing operations available to Limited Partners $ 996 $ 1,182 $ 619 Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units 8 3 (2 ) Diluted income from continuing operations available to Limited Partners 1,004 1,185 617 Weighted average limited partner units 1,045.5 1,062.8 1,088.6 Dilutive effect of unconverted unit awards and Convertible Units 33.1 1.6 2.2 Weighted average limited partner units, assuming dilutive effect of unvested unit awards 1,078.6 1,064.4 1,090.8 Diluted income from continuing operations per Limited Partner unit $ 0.93 $ 1.11 $ 0.57 Diluted income (loss) from discontinued operations per Limited Partner unit $ (0.01 ) $ — $ 0.01

Debt Obligations Debt Obligatio

Debt Obligations Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Obligations [Abstract]
Schedule of debt obligations	Our debt obligations consist of the following: December 31, 2016 2015 Parent Company Indebtedness: 7.50% Senior Notes, due October 15, 2020 $ 1,187 $ 1,187 5.875% Senior Notes, due January 15, 2024 1,150 1,150 5.50% Senior Notes due June 1, 2027 1,000 1,000 ETE Senior Secured Term Loan, due December 2, 2019 2,190 2,190 ETE Senior Secured Revolving Credit Facility due December 18, 2018 875 860 Unamortized premiums, discounts and fair value adjustments, net (15 ) (17 ) Deferred debt issuance costs (30 ) (38 ) 6,357 6,332 Subsidiary Indebtedness: ETP Debt 6.125% Senior Notes due February 15, 2017 400 400 2.50% Senior Notes due June 15, 2018 650 650 6.70% Senior Notes due July 1, 2018 600 600 9.70% Senior Notes due March 15, 2019 400 400 9.00% Senior Notes due April 15, 2019 450 450 5.75% Senior Notes due September 1, 2020 400 400 4.15% Senior Notes due October 1, 2020 1,050 1,050 6.50% Senior Notes due July 15, 2021 500 500 4.65% Senior Notes due June 1, 2021 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 5.875% Senior Notes due March 1, 2022 900 900 5.00% Senior Notes due October 1, 2022 700 700 3.60% Senior Notes due February 1, 2023 800 800 5.50% Senior Notes due April 15, 2023 700 700 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 4.05% Senior Notes due March 15, 2025 1,000 1,000 4.75% Senior Notes due January 15, 2026 1,000 1,000 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 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.15% Senior Notes due March 15, 2045 1,000 1,000 6.125% Senior Notes due December 15, 2045 1,000 1,000 Floating Rate Junior Subordinated Notes due November 1, 2066 546 545 ETP $3.75 billion Revolving Credit Facility due November 2019 2,777 1,362 Unamortized premiums, discounts and fair value adjustments, net (18 ) (21 ) Deferred debt issuance costs (132 ) (147 ) 22,067 20,633 Transwestern Debt 5.54% Senior Notes due November 17, 2016 — 125 5.64% Senior Notes due May 24, 2017 82 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 Unamortized premiums, discounts and fair value adjustments, net — (1 ) Deferred debt issuance costs (1 ) (2 ) 656 779 Panhandle Debt 6.20% Senior Notes due November 1, 2017 300 300 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 14, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 50 75 1,135 1,160 Sunoco, Inc. Debt 5.75% Senior Notes due January 15, 2017 400 400 9.00% Debentures due November 1, 2024 65 65 Unamortized premiums, discounts and fair value adjustments, net 9 20 474 485 Sunoco Logistics Debt 6.125% Senior Notes due May 15, 2016 — 175 5.50% Senior Notes due February 15, 2020 250 250 4.40% Senior Notes due April 1, 2021 600 600 4.65% Senior Notes due February 15, 2022 300 300 3.45% Senior Notes due January 15, 2023 350 350 4.25% Senior Notes due April 1, 2024 500 500 5.95% Senior Notes due December 1, 2025 400 400 3.90% Senior Notes due July 15, 2026 550 — 6.85% Senior Notes due February 15, 2040 250 250 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.30% Senior Notes due April 1, 2044 700 700 5.35% Senior Notes due May 15, 2045 800 800 Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 1,292 562 Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017 (1) 630 — Unamortized premiums, discounts and fair value adjustments, net 75 85 Deferred debt issuance costs (34 ) (32 ) 7,313 5,590 Bakken Project Debt Bakken Project $2.50 billion Credit Facility due August 2019 1,100 — Deferred debt issuance costs (13 ) — 1,087 — PennTex Debt PennTex $275 million Revolving Credit Facility due December 2019 168 — Sunoco LP Debt 5.50% Senior Notes Due August 1, 2020 600 600 6.375% Senior Notes due April 1, 2023 800 800 6.25% Senior Notes due April 15, 2021 800 — Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019 1,000 450 Sunoco LP Term Loan due October 1, 2019 1,243 — Lease-related obligations 118 126 Deferred debt issuance costs (47 ) (18 ) 4,514 1,958 Other 31 31 43,802 36,968 Less: current maturities 1,194 131 $ 42,608 $ 36,837
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 $156 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: 2017 $ 1,817 2018 2,530 2019 9,483 2020 4,960 2021 2,706 Thereafter 22,462 Total $ 43,958

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Schedule of Future Relinquishments of Incentive Distribution Rights [Table Text Block]	ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods: Total Year 2017 $ 626 2018 138 2019 128 Each year beyond 2019 33
Change In ETE Common Units	The change in ETE Common Units during the years ended December 31, 2016 , 2015 and 2014 was as follows: Years Ended December 31, 2016 2015 2014 Number of Common Units, beginning of period 1,044.8 1,077.5 1,119.8 Conversion of Class D Units to ETE Common Units — 0.9 — Repurchase of common units under buyback program — (33.6 ) (42.3 ) Issuance of common units 2.1 — — Number of Common Units, end of period 1,046.9 1,044.8 1,077.5 ETE Series A Preferred Units Years Ended December 31, 2016 2015 2014 Number of Series A Convertible Preferred Units, beginning of period — — — Issuance of Series A Convertible Preferred Units 329.3 — — Number of Series A Convertible Preferred Units, end of period 329.3 — —
Accumulated Other Comprehensive Income (Loss)	The following table presents the components of AOCI, net of tax: December 31, 2016 2015 Available-for-sale securities $ 2 $ — Foreign currency translation adjustment (5 ) (4 ) Actuarial gain related to pensions and other postretirement benefits 7 8 Investments in unconsolidated affiliates, net 4 — Subtotal 8 4 Amounts attributable to noncontrolling interest (8 ) (4 ) Total AOCI included in partners’ capital, net of tax $ — $ —
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss): December 31, 2016 2015 Available-for-sale securities $ (2 ) $ (2 ) Foreign currency translation adjustment 3 4 Actuarial loss relating to pension and other postretirement benefits — 7 Total $ 1 $ 9
Parent Company [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Our distributions declared with respect to our common units during the years ended December 31, 2016, 2015, and 2014 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2013 February 7, 2014 February 19, 2014 $ 0.1731 March 31, 2014 May 5, 2014 May 19, 2014 0.1794 June 30, 2014 August 4, 2014 August 19, 2014 0.1900 September 30, 2014 November 3, 2014 November 19, 2014 0.2075 December 31, 2014 February 6, 2015 February 19, 2015 0.2250 March 31, 2015 May 8, 2015 May 19, 2015 0.2450 June 30, 2015 August 6, 2015 August 19, 2015 0.2650 September 30, 2015 November 5, 2015 November 19, 2015 0.2850 December 31, 2015 February 4, 2016 February 19, 2016 0.2850 March 31, 2016 (1) May 6, 2016 May 19, 2016 0.2850 June 30, 2016 (1) August 8, 2016 August 19, 2016 0.2850 September 30, 2016 (1) November 7, 2016 November 18, 2016 0.2850 December 31, 2016 (1) February 7, 2017 February 21, 2017 0.2850
ETP [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	ETP’s distributions declared during the periods presented below were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2013 February 7, 2014 February 14, 2014 $ 0.6133 March 31, 2014 May 5, 2014 May 15, 2014 0.6233 June 30, 2014 August 4, 2014 August 14, 2014 0.6367 September 30, 2014 November 3, 2014 November 14, 2014 0.6500 December 31, 2014 February 6, 2015 February 13, 2015 0.6633 March 31, 2015 May 8, 2015 May 15, 2015 0.6767 June 30, 2015 August 6, 2015 August 14, 2015 0.6900 September 30, 2015 November 5, 2015 November 16, 2015 0.7033 December 31, 2015 February 8, 2016 February 16, 2016 0.7033 March 31, 2016 May 6, 2016 May 16, 2016 0.7033 June 30, 2016 August 8, 2016 August 15, 2016 0.7033 September 30, 2016 November 7, 2016 November 14, 2016 0.7033 December 31, 2016 February 7, 2017 February 14, 2017 0.7033
Sunoco Logistics [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Sunoco Logistics Quarterly Distributions of Available Cash Distributions declared by Sunoco Logistics during the years ended December 31, 2016, 2015, and 2014 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2013 February 10, 2014 February 14, 2014 $ 0.3312 March 31, 2014 May 9, 2014 May 15, 2014 0.3475 June 30, 2014 August 8, 2014 August 14, 2014 0.3650 September 30, 2014 November 7, 2014 November 14, 2014 0.3825 December 31, 2014 February 9, 2015 February 13, 2015 0.4000 March 31, 2015 May 11, 2015 May 15, 2015 0.4190 June 30, 2015 August 10, 2015 August 14, 2015 0.4380 September 30, 2015 November 9, 2015 November 13, 2015 0.4580 December 31, 2015 February 8, 2016 February 12, 2016 0.4790 March 31, 2016 May 9, 2016 May 13, 2016 0.4890 June 30, 2016 August 8, 2016 August 12, 2016 0.5000 September 30, 2016 November 9, 2016 November 14, 2016 0.5100 December 31, 2016 February 7, 2017 February 14, 2017 0.5200
Sunoco LP [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Sunoco LP Quarterly Distributions of Available Cash Distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014 were as follows: Quarter Ended Record Date Payment Date Rate September 30, 2014 November 18, 2014 November 28, 2014 $ 0.5457 December 31, 2014 February 17, 2015 February 27, 2015 0.6000 March 31, 2015 May 19, 2015 May 29, 2015 0.6450 June 30, 2015 August 18, 2015 August 28, 2015 0.6934 September 30, 2015 November 17, 2015 November 27, 2015 0.7454 December 31, 2015 February 5, 2016 February 16, 2016 0.8013 March 31, 2016 May 6, 2016 May 16, 2016 0.8173 June 30, 2016 August 5, 2016 August 15, 2016 0.8255 September 30, 2016 November 7, 2016 November 15, 2016 0.8255 December 31, 2016 February 13, 2017 February 21, 2017 0.8255
Series A Convertible Preferred Units [Member] | Parent Company [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Our distributions declared with respect to our Convertible Unit during the year ended December 31, 2016 were as follows: Quarter Ended Record Date Payment Date Rate March 31, 2016 May 6, 2016 May 19, 2016 $ 0.1100 June 30, 2016 August 8, 2016 August 19, 2016 0.1100 September 30, 2016 November 7, 2016 November 18, 2016 0.1100 December 31, 2016 February 7, 2017 February 21, 2017 0.1100
PennTex [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	PennTex Quarterly Distributions of Available Cash PennTex is required by its partnership agreement to distribute a minimum quarterly distribution of $0.2750 per unit at the end of each quarter. Distributions declared during the periods presented were as follows: Quarter Ended Record Date Payment Date Rate September 30, 2016 November 7, 2016 November 14, 2016 $ 0.2950 December 31, 2016 February 7, 2017 February 14, 2017 0.2950

Unit-Based Compensation Plans U

Unit-Based Compensation Plans Unit-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2016
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Schedule Of ETP Awards Granted To Employees And Non-Employee Directos	The following table summarizes the activity of the Subsidiary Unit Awards: ETP Sunoco LP Number of Units Weighted Average Grant-Date Fair Value Per Unit Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2015 7.2 $ 31.74 1.1 $ 41.19 Awards granted 3.8 23.82 1.0 26.95 Awards vested (1.2 ) 35.48 — 36.98 Awards forfeited (0.3 ) 32.26 (0.1 ) 39.77 Unvested awards as of December 31, 2016 9.5 27.69 2.0 34.43 Weighted average grant date fair value for Subsidiary Unit Awards during the year ended December 31: 2016 $ 23.82 $ 26.95 2015 23.47 40.63 2014 40.57 45.50

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Federal and State Income Taxes [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows: Years Ended December 31, 2016 2015 2014 Current expense (benefit): Federal $ 11 $ (315 ) $ 251 State (34 ) (54 ) 78 Total (23 ) (369 ) 329 Deferred expense (benefit): Federal (237 ) 253 (29 ) State 12 (32 ) 25 Total (225 ) 221 (4 ) Total income tax expense (benefit) from continuing operations $ (248 ) $ (148 ) $ 325
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Historically, our effective tax rate differed from the statutory rate primarily due to partnership earnings that are not subject to U.S. federal and most state income taxes at the partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and the Susser Merger (see Note 3 ) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2016 , 2015 and 2014 is as follows: December 31, 2016 December 31, 2015 December 31, 2014 Income tax expense (benefit) at U.S. statutory rate of 35 percent $ 95 $ 302 $ 462 Increase (reduction) in income taxes resulting from: Nondeductible goodwill included in the Lake Charles LNG transaction — — 105 Partnership earnings not subject to tax (590 ) (366 ) (284 ) Goodwill impairment 278 — — State tax, net of federal tax benefit (10 ) (35 ) 52 Dividend received deduction (15 ) (22 ) — Premium on debt retirement — — (10 ) Audit settlement — (7 ) — Foreign taxes — — (8 ) Other (6 ) (20 ) 8 Income tax expense (benefit) from continuing operations $ (248 ) $ (148 ) $ 325
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, 2016 2015 Deferred income tax assets: Net operating losses and alternative minimum tax credit $ 472 $ 217 Pension and other postretirement benefits 30 36 Long term debt 32 61 Other 182 162 Total deferred income tax assets 716 476 Valuation allowance (118 ) (121 ) Net deferred income tax assets 598 355 Deferred income tax liabilities: Properties, plants and equipment (1,633 ) (1,633 ) Investments in unconsolidated affiliates (3,789 ) (2,976 ) Trademarks (273 ) (286 ) Other (15 ) (50 ) Total deferred income tax liabilities (5,710 ) (4,945 ) Accumulated deferred income taxes $ (5,112 ) $ (4,590 )
ScheduleOfUnrecognizedTaxBenefits [Table Text Block]	The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2016 2015 2014 Balance at beginning of year $ 610 $ 440 $ 429 Additions attributable to tax positions taken in the current year 8 178 20 Additions attributable to tax positions taken in prior years 18 — — Reduction attributable to tax positions taken in prior years (20 ) — (1 ) Settlements — — (5 ) Lapse of statute (1 ) (8 ) (3 ) Balance at end of year $ 615 $ 610 $ 440
Summary of Deferred Tax Liability Not Recognized [Table Text Block]	The table below provides a rollforward of the net deferred income tax liability as follows: December 31, 2016 2015 Net deferred income tax liability, beginning of year $ (4,590 ) $ (4,410 ) Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) (460 ) — Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3) (243 ) — Tax provision, including provision from discontinued operations 201 (242 ) Other (20 ) 62 Net deferred income tax liability $ (5,112 ) $ (4,590 )

Derivative Assets And Liabili34

Derivative Assets And Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Offsetting Assets [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, 2016 December 31, 2015 December 31, 2016 December 31, 2015 Derivatives without offsetting agreements Derivative assets (liabilities) $ — $ — $ (194 ) $ (176 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 25 63 (58 ) (47 ) Broker cleared derivative contracts Other current assets 338 391 (420 ) (309 ) 363 454 (672 ) (532 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (4 ) (17 ) 4 17 Payments on margin deposit Other current assets (338 ) (309 ) 338 309 Total net derivatives $ 21 $ 128 $ (330 ) $ (206 )
Outstanding Commodity-Related Derivatives	The following table details our outstanding commodity-related derivatives: December 31, 2016 December 31, 2015 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures (682,500 ) 2017 (602,500 ) 2016 - 2017 Basis Swaps IFERC/NYMEX (1) 2,242,500 2017 (31,240,000 ) 2016 - 2017 Power (Megawatt): Forwards 391,880 2017 - 2018 357,092 2016 - 2017 Futures 109,564 2017 - 2018 (109,791 ) 2016 Options — Puts (50,400 ) 2017 260,534 2016 Options — Calls 186,400 2017 1,300,647 2016 Crude (Bbls) – Futures (617,000 ) 2017 (591,000 ) 2016 - 2017 (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX 10,750,000 2017 - 2018 (6,522,500 ) 2016 - 2017 Swing Swaps IFERC (5,662,500 ) 2017 71,340,000 2016 - 2017 Fixed Swaps/Futures (52,652,500 ) 2017 - 2019 (14,380,000 ) 2016 - 2018 Forward Physical Contracts (22,492,489 ) 2017 21,922,484 2016 - 2017 Natural Gas Liquid (Bbls) – Forwards/Swaps (5,786,627 ) 2017 (8,146,800 ) 2016 - 2018 Refined Products (Bbls) – Futures (3,144,000 ) 2017 (1,289,000 ) 2016 - 2017 Corn (Bushels) – Futures 1,580,000 2017 1,185,000 2016 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (36,370,000 ) 2017 (37,555,000 ) 2016 Fixed Swaps/Futures (36,370,000 ) 2017 (37,555,000 ) 2016 Hedged Item — Inventory 36,370,000 2017 37,555,000 2016 (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	The following table summarizes our interest rate swaps outstanding, none of which are designated as hedges for accounting purposes: Notional Amount Outstanding Entity Term Type (1) December 31, December 31, ETP July 2016 (2) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate $ — $ 200 ETP July 2017 (3) Forward-starting to pay a fixed rate of 3.90% and receive a floating rate 500 300 ETP July 2018 (3) Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200 200 ETP July 2019 (3) Forward-starting to pay a fixed rate of 3.25% and receive a floating rate 200 200 ETP December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 1,200 ETP 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.
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, 2016 December 31, 2015 December 31, 2016 December 31, 2015 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ — $ 38 $ (4 ) $ (3 ) — 38 (4 ) (3 ) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 338 353 (416 ) (306 ) Commodity derivatives 25 63 (58 ) (47 ) Interest rate derivatives — — (193 ) (171 ) Embedded derivatives in ETP Preferred Units — — (1 ) (5 ) 363 416 (668 ) (529 ) Total derivatives $ 363 $ 454 $ (672 ) $ (532 )
Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives	The following tables summarize the amounts recognized with respect to our derivative financial instruments: Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Years Ended December 31, 2016 2015 2014 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ — $ — $ (3 ) Total $ — $ — $ (3 )
Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Years Ended December 31, 2016 2015 2014 Derivatives in cash flow hedging relationships: Commodity derivatives Cost of products sold $ — $ — $ (3 ) Total $ — $ — $ (3 ) 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, 2016 2015 2014 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 14 $ 21 $ (8 ) Total $ 14 $ 21 $ (8 ) Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives Years Ended December 31, 2016 2015 2014 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (35 ) $ (11 ) $ (6 ) Commodity derivatives – Non-trading Cost of products sold (177 ) 15 199 Interest rate derivatives Losses on interest rate derivatives (12 ) (18 ) (157 ) Embedded derivatives Other, net 4 12 3 Total $ (220 ) $ (2 ) $ 39

Regulatory Matters, Commitmen35

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Schedule of Rent Expense [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, 2016 2015 2014 Rental expense (1) $ 129 $ 205 $ 98 Less: Sublease rental income (30 ) (16 ) (26 ) Rental expense, net $ 99 $ 189 $ 72 (1) Includes contingent rentals totaling $23 million , $26 million and $24 million for the years ended December 31, 2016 , 2015 and 2014 , respectively.
Environmental Exit Costs by Cost [Table Text Block]	December 31, 2016 2015 Current $ 37 $ 42 Non-current 348 326 Total environmental liabilities $ 385 $ 368
Schedule of Future Minimum Rental Payments for Operating Leases	Future minimum lease commitments for such leases are: Years Ending December 31: 2017 $ 82 2018 67 2019 55 2020 52 2021 53 Thereafter 219 Future minimum lease commitments 528 Less: Sublease rental income (79 ) Net future minimum lease commitments $ 449

Retirement Benefits Retirement

Retirement Benefits Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	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, 2016 December 31, 2015 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 $ 20 $ 57 $ 181 $ 718 $ 65 $ 203 Interest cost 1 2 4 23 2 4 Amendments — — — — — — Benefits paid, net (1 ) (7 ) (21 ) (46 ) (8 ) (20 ) Actuarial (gain) loss and other (2 ) (1 ) 2 16 (2 ) (6 ) Settlements — — — (691 ) — — Benefit obligation at end of period $ 18 $ 51 $ 166 $ 20 $ 57 $ 181 Change in plan assets: Fair value of plan assets at beginning of period $ 15 $ — $ 261 $ 598 $ — $ 272 Return on plan assets and other (2 ) — 6 16 — — Employer contributions — — 10 138 — 9 Benefits paid, net (1 ) — (21 ) (46 ) — (20 ) Settlements — — — (691 ) — — Fair value of plan assets at end of period $ 12 $ — $ 256 $ 15 $ — $ 261 Amount underfunded (overfunded) at end of period $ 6 $ 51 $ (90 ) $ 5 $ 57 $ (80 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 114 $ — $ — $ 103 Current liabilities — (7 ) (2 ) — (9 ) (2 ) Non-current liabilities (6 ) (44 ) (23 ) (5 ) (48 ) (22 ) $ (6 ) $ (51 ) $ 89 $ (5 ) $ (57 ) $ 79 Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: Net actuarial gain $ — $ — $ (13 ) $ 2 $ 4 $ (18 ) Prior service cost — — 15 — — 16 $ — $ — $ 2 $ 2 $ 4 $ (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, 2016 December 31, 2015 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 18 $ 51 N/A $ 20 $ 57 N/A Accumulated benefit obligation 18 51 $ 166 20 57 $ 181 Fair value of plan assets 12 — 256 15 — 261
Schedule of Benefit Obligations Assumptions [Table Text Block]	Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2016 December 31, 2015 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.65 % 2.34 % 3.59 % 2.38 % 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, 2016 December 31, 2015 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.60 % 3.06 % 3.65 % 2.79 % Expected return on assets: Tax exempt accounts 3.50 % 7.00 % 7.50 % 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 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’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: December 31, 2016 2015 Health care cost trend rate 6.73 % 7.16 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.96 % 5.39 % Year that the rate reaches the ultimate trend rate 2021 2018
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, 2016 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Mutual funds (1) $ 12 $ 12 $ — $ — Total $ 12 $ 12 $ — $ — (1) Comprised of 100% equities as of December 31, 2016 . Fair Value Measurements at December 31, 2015 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Mutual funds (1) $ 15 $ — $ 15 $ — Total $ 15 $ — $ 15 $ — (1) Comprised of 100% equities as of December 31, 2015 . The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows: 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) 142 142 — — Fixed income securities 91 — 91 — Total $ 256 $ 165 $ 91 $ — (1) Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016 . Fair Value Measurements at December 31, 2015 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Cash and Cash Equivalents $ 18 $ 18 $ — $ — Mutual funds (1) 141 141 — — Fixed income securities 102 — 102 — Total $ 261 $ 159 $ 102 $ — (1) Primarily comprised of approximately 56% equities, 33% fixed income securities and 11% cash as of December 31, 2015 . 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]	Benefit Payments Panhandle’s 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: Pension Benefits Years Funded Plans Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2017 $ 1 $ 7 $ 26 2018 1 7 25 2019 1 6 23 2020 1 6 22 2021 1 5 19 2022 – 2026 6 17 39
Schedule of Net Benefit Costs [Table Text Block]	Components of Net Periodic Benefit Cost December 31, 2016 December 31, 2015 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net Periodic Benefit Cost: Interest cost $ 3 $ 4 $ 25 $ 4 Expected return on plan assets (1 ) (8 ) (16 ) (8 ) Prior service cost amortization — 1 — 1 Actuarial loss amortization — — — — Settlements — — 32 — Net periodic benefit cost $ 2 $ (3 ) $ 41 $ (3 )

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2016
Financial Information By Segment	Years Ended December 31, 2016 2015 2014 Revenues: Investment in ETP: Revenues from external customers $ 21,618 $ 34,156 $ 55,475 Intersegment revenues 209 136 — 21,827 34,292 55,475 Investment in Sunoco LP: Revenues from external customers 8,287 10,527 4,291 Intersegment revenues 9 11 — 8,296 10,538 4,291 Investment in Lake Charles LNG: Revenues from external customers 197 216 216 Adjustments and Eliminations: (218 ) (10,842 ) (7,343 ) Total revenues $ 30,102 $ 34,204 $ 52,639 Costs of products sold: Investment in ETP $ 15,394 $ 27,029 $ 48,414 Investment in Sunoco LP 7,459 9,902 4,214 Adjustments and Eliminations (217 ) (9,496 ) (6,767 ) Total costs of products sold $ 22,636 $ 27,435 $ 45,861 Depreciation, depletion and amortization: Investment in ETP $ 1,986 $ 1,929 $ 1,669 Investment in Sunoco LP 126 103 31 Investment in Lake Charles LNG 39 39 39 Corporate and Other 15 17 16 Adjustments and Eliminations — (184 ) (86 ) Total depreciation, depletion and amortization $ 2,166 $ 1,904 $ 1,669 Years Ended December 31, 2016 2015 2014 Equity in earnings of unconsolidated affiliates: Investment in ETP $ 336 $ 469 $ 332 Adjustments and Eliminations (66 ) (193 ) — Total equity in earnings of unconsolidated affiliates $ 270 $ 276 $ 332 Years Ended December 31, 2016 2015 2014 Segment Adjusted EBITDA: Investment in ETP $ 5,605 $ 5,714 $ 5,710 Investment in Sunoco LP 665 719 332 Investment in Lake Charles LNG 179 196 195 Corporate and Other (170 ) (104 ) (97 ) Adjustments and Eliminations (272 ) (590 ) (300 ) Total Segment Adjusted EBITDA 6,007 5,935 5,840 Depreciation, depletion and amortization (2,166 ) (1,904 ) (1,669 ) Interest expense, net of interest capitalized (1,803 ) (1,621 ) (1,368 ) Gains on acquisitions 83 — — Gain on sale of AmeriGas common units — — 177 Impairment of investment in affiliate (308 ) — — Impairment losses (970 ) (339 ) (370 ) Losses on interest rate derivatives (12 ) (18 ) (157 ) Non-cash unit-based compensation expense (70 ) (91 ) (82 ) Unrealized gains (losses) on commodity risk management activities (136 ) (65 ) 116 Losses on extinguishments of debt — (43 ) (25 ) Inventory valuation adjustments 267 (229 ) (445 ) Adjusted EBITDA related to discontinued operations (293 ) (345 ) (208 ) Adjusted EBITDA related to unconsolidated affiliates (675 ) (713 ) (748 ) Equity in earnings of unconsolidated affiliates 270 276 332 Other, net 78 21 (74 ) Income from continuing operations before income tax expense $ 272 $ 864 $ 1,319 December 31, 2016 2015 2014 Total assets: Investment in ETP $ 70,191 $ 65,173 $ 62,518 Investment in Sunoco LP 8,701 8,842 8,773 Investment in Lake Charles LNG 1,508 1,369 1,210 Corporate and Other 711 638 1,119 Adjustments and Eliminations (2,100 ) (4,833 ) (9,341 ) Total $ 79,011 $ 71,189 $ 64,279 Years Ended December 31, 2016 2015 2014 Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis): Investment in ETP $ 5,810 $ 8,167 $ 5,494 Investment in Sunoco LP 439 491 154 Investment in Lake Charles LNG — 1 1 Adjustments and Eliminations — (123 ) (90 ) Total $ 6,249 $ 8,536 $ 5,559 December 31, 2016 2015 2014 Advances to and investments in affiliates: Investment in ETP $ 4,280 $ 5,003 $ 3,760 Adjustments and Eliminations (1,240 ) (1,541 ) (101 ) Total $ 3,040 $ 3,462 $ 3,659 The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP. Investment in ETP Years Ended December 31, 2016 2015 2014 Intrastate Transportation and Storage $ 2,155 $ 1,912 $ 2,645 Interstate Transportation and Storage 946 1,008 1,057 Midstream 2,342 2,607 4,770 NGL and refined products transportation and services 5,973 4,569 4,746 Crude oil transportation and services 7,539 8,980 16,904 All Other 2,872 15,216 25,353 Total revenues 21,827 34,292 55,475 Less: Intersegment revenues 209 136 — Revenues from external customers $ 21,618 $ 34,156 $ 55,475 Investment in Sunoco LP Years Ended December 31, 2016 2015 2014 Retail operations $ 301 $ 334 $ 43 Wholesale operations 7,995 10,204 4,248 Total revenues 8,296 10,538 4,291 Less: Intersegment revenues 9 11 — Revenues from external customers $ 8,287 $ 10,527 $ 4,291 Investment in Lake Charles LNG Lake Charles LNG’s revenues of $197 million , $216 million and $216 million for the years ended December 31, 2016, 2015 and 2014, respectively, were related to LNG terminalling.

Quarterly Financial Data (Una38

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Quarters Ended March 31 June 30 September 30 December 31 Total Year 2016: Revenues $ 6,083 $ 7,415 $ 7,705 $ 8,899 $ 30,102 Operating income (loss) 695 805 646 (236 ) 1,910 Net income (loss) 336 424 41 (760 ) 41 Limited Partners’ interest in net income 311 239 207 226 983 Basic net income per limited partner unit $ 0.30 $ 0.23 $ 0.20 $ 0.22 $ 0.94 Diluted net income per limited partner unit $ 0.30 $ 0.23 $ 0.19 $ 0.21 $ 0.92 Quarters Ended March 31 June 30 September 30 December 31 Total Year 2015: Revenues $ 8,564 $ 9,423 $ 8,473 $ 7,744 $ 34,204 Operating income 589 878 573 210 2,250 Net income (loss) 221 772 238 (138 ) 1,093 Limited Partners’ interest in net income 282 298 291 312 1,183 Basic net income per limited partner unit $ 0.26 $ 0.28 $ 0.28 $ 0.30 $ 1.11 Diluted net income per limited partner unit $ 0.26 $ 0.28 $ 0.28 $ 0.30 $ 1.11 The three months ended December 31, 2015 reflected the unfavorable impact of $120 million related to non-cash inventory valuation adjustments primarily in ETP’s retail marketing operations and our investment in Sunoco LP. The three months ended December 31, 2016 and 2015 reflected the recognition of impairment losses of $970 million and $339 million , respectively. Impairment losses in 2016 were primarily related to ETP’s interstate operations, midstream midcontinent operations and retail operations. In 2015 , impairment losses were primarily related to Lone Star Refinery Services operations and ETP’s Transwestern pipeline. The three months ended September 30, 2016 reflected the recognition of a non-cash impairment of ETP’s investment in MEP of $308 million in our interstate transportation and storage operations.

Supplemental Financial Statem39

Supplemental Financial Statement Information (Tables) - Parent Company [Member]	12 Months Ended
	Dec. 31, 2016
Schedule Of Balance Sheets	BALANCE SHEETS December 31, 2016 2015 ASSETS CURRENT ASSETS: Cash and cash equivalents $ 2 $ 1 Accounts receivable from related companies 55 34 Total current assets 57 35 PROPERTY, PLANT AND EQUIPMENT, net 36 20 ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES 5,088 5,764 INTANGIBLE ASSETS, net 1 6 GOODWILL 9 9 OTHER NON-CURRENT ASSETS, net 10 10 Total assets $ 5,201 $ 5,844 LIABILITIES AND PARTNERS’ CAPITAL CURRENT LIABILITIES: Accounts payable $ 1 $ — Accounts payable to related companies 22 111 Interest payable 66 66 Accrued and other current liabilities 3 1 Total current liabilities 92 178 LONG-TERM DEBT, less current maturities 6,358 6,332 NOTE PAYABLE TO AFFILIATE 443 265 OTHER NON-CURRENT LIABILITIES 2 1 COMMITMENTS AND CONTINGENCIES PARTNERS’ DEFICIT: General Partner (3 ) (2 ) Limited Partners: Common Unitholders (1,046,947,157 and 1,044,767,336 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively) (1,871 ) (952 ) Class D Units (2,156,000 units authorized, issued and outstanding as of December 31, 2015) — 22 Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016) 180 — Total partners’ deficit (1,694 ) (932 ) Total liabilities and partners’ deficit $ 5,201 $ 5,844
Schedule Of Statements Of Operations	STATEMENTS OF OPERATIONS Years Ended December 31, 2016 2015 2014 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES $ (185 ) $ (112 ) $ (111 ) OTHER INCOME (EXPENSE): Interest expense, net of interest capitalized (327 ) (294 ) (205 ) Equity in earnings of unconsolidated affiliates 1,511 1,601 955 Other, net (4 ) (5 ) (5 ) INCOME BEFORE INCOME TAXES 995 1,190 634 Income tax expense — 1 1 NET INCOME 995 1,189 633 General Partner’s interest in net income 3 3 2 Convertible Unitholders’ interest in income 9 — — Class D Unitholder’s interest in net income — 3 2 Limited Partners’ interest in net income $ 983 $ 1,183 $ 629
Schedule Of Statements Of Cash Flows	STATEMENTS OF CASH FLOWS Years Ended December 31, 2016 2015 2014 NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 918 $ 1,103 $ 816 CASH FLOWS FROM INVESTING ACTIVITIES: Cash paid for Bakken Pipeline Transaction — (817 ) — Contributions to unconsolidated affiliates (70 ) — (118 ) Capital expenditures (16 ) (19 ) — Purchase of additional interest in Regency — — (800 ) Net cash used in investing activities (86 ) (836 ) (918 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings 225 3,672 3,020 Principal payments on debt (210 ) (1,985 ) (1,142 ) Distributions to partners (1,022 ) (1,090 ) (821 ) Proceeds from affiliate 176 210 54 Units repurchased under buyback program — (1,064 ) (1,000 ) Debt issuance costs — (11 ) (15 ) Net cash provided by (used in) financing activities (831 ) (268 ) 96 INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 1 (1 ) (6 ) CASH AND CASH EQUIVALENTS, beginning of period 1 2 8 CASH AND CASH EQUIVALENTS, end of period $ 2 $ 1 $ 2

Operations And Organization (Na

Operations And Organization (Narrative) (Details) $ in Millions	1 Months Ended					6 Months Ended	12 Months Ended
	Apr. 30, 2017shares	Mar. 31, 2017	Oct. 31, 2015USD ($)	Jul. 31, 2015shares	Apr. 30, 2015USD ($)shares	Jun. 30, 2017shares	Dec. 31, 2016USD ($)shares
LNG Storage Capacity							9
Payments to Acquire Businesses, Gross | $			$ 382
Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.							100
Citrus [Member]
Interest ownership							50.00%
ETP [Member]
Incentive Distribution Rights							100.00%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.							3,900,000
Sunoco Logistics [Member]
General Partner Interest							0.10%
Sunoco Logistics [Member] | ETP [Member]
Incentive Distribution Rights							99.90%
SXL and ETP Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction	832,000,000
Dropdown of Sunoco LLC Interest [Member]
Payments to Acquire Businesses, Gross | $					$ 775
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 | $							$ 320
Relinquishment, Year 1 [Member] | Regency Merger [Member]
Relinquishment of Incentive Distributions | $							80
Relinquishment, Years 2 through 5 [Member] | Regency Merger [Member]
Relinquishment of Incentive Distributions | $							$ 60
Class H Units [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.							81,000,000
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
Subsequent Event [Member] | Post-Merger ETP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest						2.50%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.						27,500,000
Subsequent Event [Member] | ETP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		3.30%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.						18,400,000
Subsequent Event [Member] | SXL and ETP Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.5
Subsequent Event [Member] | Class H Units [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.						81,000,000
Subsequent Event [Member] | Class I Units [Member] | Post-Merger ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.						100
Subsequent Event [Member] | Class I Units [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.						100

Estimates, Significant Accoun41

Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Tangible Asset Impairment Charges	$ 133	$ 110
ARO Underlying Asset	14	18
Impairment of Intangible Assets, Finite-lived		24
Asset Retirement Obligation, Legally Restricted Assets, Fair Value	13	6
Deferred Tax Liabilities, Gross	5,710	4,945
Long-term Debt, Fair Value	45,050	33,220
Impairment losses	826	205
Goodwill acquired	509	23
Goodwill	5,170	5,485	$ 5,871
Long-term Debt	43,802	36,968
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	0
Midstream [Member]
Tangible Asset Impairment Charges	10
Impairment losses	(32)
Investment In ETP [Member]
Impairment losses	670	205
Goodwill acquired	428	0
Goodwill	3,897	5,428	7,642
NGL and refined products transportation and services [Member]
Impairment losses		(106)
Interstate Transportation and Storage [Member]
Impairment losses	(638)	(99)
Retail Marketing [Member]
Excise Taxes Collected	$ 3,480	$ 3,050	$ 2,460

Estimates (Schedule Of Net Chan

Estimates (Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Accounts receivable	$ (1,126)	$ 856	$ 600
Accounts receivable from related companies	42	(5)	30
Inventories	(345)	(410)	52
Other current assets	(149)	225	(151)
Other non-current assets, net	(148)	250	(6)
Accounts payable	1,214	(1,043)	(893)
Accounts payable to related companies	(64)	400	5
Exchanges payable	0	0	0
Accrued and other current liabilities	89	(697)	(158)
Other non-current liabilities	158	(233)	(138)
Derivative assets and liabilities, net	67	75	19
Net change in operating assets and liabilities, net of effects of acquisitions	$ 36	$ (1,032)	$ (338)

Estimates (Schedule Of Non-Cash

Estimates (Schedule Of Non-Cash Investing And Financing Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 930	$ 910	$ 643
Contribution of property, plant and equipment from noncontrolling interest	0	34	0
Net gains (losses) from subsidiary common unit transactions	16	(526)	744
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	236
Long-term debt exchanged in Eagle Rock Midstream Acquisition	0	0	499
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	1,922	1,800	1,416
Proceeds from Income Tax Refunds	(229)
Cash paid for (refund of) income taxes		72	345
Subsidiary units issued in PVR, Hoover and Eagle Rock Midstream Acquisitions [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	0	0	4,281
Subsidiary units issued in Susser Merger [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	0	0	908
PVR Acquisition [Member]
NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed in PVR Acquisition	0	0	1,887
PennTex Acquisition [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger		$ 0	$ 0
Limited Partner [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	0
Limited Partner [Member] | PennTex Acquisition [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	$ 307

Estimates (Schedule of Inventor

Estimates (Schedule of Inventory) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Inventory valuation adjustments	$ 120	$ (267)	$ 229	$ 445
Inventory, Net [Abstract]
Natural gas and NGLs	415	699	415
Crude oil	424	683	424
Refined products	378	483	378
Spare parts and other	248	238	248
Total inventories	$ 1,465	$ 2,103	$ 1,465

Estimates (Other Current Assets

Estimates (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Other Information [Abstract]
Deposits paid to vendors	$ 74	$ 74
Income taxes receivable	128	326
Prepaid expenses and other	301	193
Total other current assets	$ 503	$ 593

Estimates (Property, Plant and

Estimates (Property, Plant and Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 61,158	$ 52,851
Less - Accumulated depreciation	(7,905)	(6,067)
Property, Plant and Equipment, Net	53,253	46,784
Land and Land Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,160	1,008
Building and Building Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	2,197	1,629
Pipelines [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	35,593	32,677
Natural gas and NGL storage facilities (5 to 46 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,515	390
Bulk storage, equipment and facilities (2 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	3,677	2,853
Tanks and other equipment (5 to 40 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,286	1,488
Retail equipment (2 to 99 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	427	436
Vehicles [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	241	220
Right of way (20 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	3,374	2,573
Natural resources
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	434	484
Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,031	1,296
Construction Work-In-Process [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 10,223	$ 7,797

Estimates (Schedule Of Property

Estimates (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Depreciation and depletion expense	$ 1,904	$ 1,616	$ 1,409
Capitalized interest, excluding AFUDC	$ 200	$ 163	$ 101

Estimates (Schedule of Other No

Estimates (Schedule of Other Non-Current Assets, net) (Details) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Unamortized financing costs(1)	[1]	$ 13	$ 29
Regulatory assets		86	90
Deferred charges		217	198
Restricted funds		190	192
Other		310	202
Total other non-current assets, net		$ 816	$ 711
[1]	(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.

Estimates (Components Of Intang

Estimates (Components Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Impairment losses	$ 826	$ 205
Gross Carrying Amount	6,512	5,642
Accumulated Amortization	(1,023)	(746)
Customer relationships, contracts and agreements (3 to 46 years)
Gross Carrying Amount	6,050	5,199
Accumulated Amortization	(971)	(712)
Trade names (15 years)
Gross Carrying Amount	25	48
Accumulated Amortization	(21)	(16)
Patents (9 years)
Gross Carrying Amount	352	66
Accumulated Amortization	(22)	(18)
Total Amortizable Intangible Assets [Member]
Gross Carrying Amount	6,469	5,327
Accumulated Amortization	(1,023)	(746)
Trademarks [Member]
Gross Carrying Amount	0	281
Accumulated Amortization	0	0
Other Amortizable Intangible Assets [Member]
Gross Carrying Amount	42	14
Accumulated Amortization	(9)	0
Contractual Rights [Member]
Gross Carrying Amount	43	34
Accumulated Amortization	0	0
liquor licenses [Member]
Gross Carrying Amount	0	0
Accumulated Amortization	0	$ 0
Sunoco LP [Member]
Impairment losses	642
Sunoco LP [Member] | Continuing Operations [Member]
Impairment losses	$ 156

Estimates, Significant Accoun50

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Useful Lives) (Details) (Details)	12 Months Ended
	Dec. 31, 2016
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Intangible assets, useful life, minimum (years)	3 years
Minimum [Member] | Other (1 to 15 years)
Intangible assets, useful life, minimum (years)	1 year
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Intangible assets, useful life, minimum (years)	46 years
Maximum [Member] | Trade names (15 years)
Intangible assets, useful life, minimum (years)	15 years
Maximum [Member] | Patents (9 years)
Intangible assets, useful life, minimum (years)	9 years
Maximum [Member] | Other (1 to 15 years)
Intangible assets, useful life, minimum (years)	15 years
Buildings and improvements [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Buildings and improvements [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	45 years
Pipelines And Equipment [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	5 years
Pipelines And Equipment [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Natural gas and NGL storage facilities (5 to 46 years) | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	5 years
Natural gas and NGL storage facilities (5 to 46 years) | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	46 years
Bulk storage, equipment and facilities (2 to 83 years) | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	2 years
Bulk storage, equipment and facilities (2 to 83 years) | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Tanks and other equipment (5 to 40 years) | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	5 years
Tanks and other equipment (5 to 40 years) | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	40 years
Retail equipment (2 to 99 years) | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	2 years
Retail equipment (2 to 99 years) | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	99 years
Vehicles [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Vehicles [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	25 years
Right of way (20 to 83 years) | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	20 years
Right of way (20 to 83 years) | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Property, Plant and Equipment, Other Types [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Property, Plant and Equipment, Other Types [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	40 years

Estimates (Aggregate Amortizati

Estimates (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Depreciation And Amortization [Member]
Reported in depreciation and amortization	$ 262	$ 288	$ 212

Estimates (Estimated Aggregate

Estimates (Estimated Aggregate Amortization Expense) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
2,017	$ 279
2,018	277
2,019	273
2,020	268
2,021	251
Gross Carrying Amount	$ 6,512	$ 5,642

Estimates (Schedule Of Goodwill

Estimates (Schedule Of Goodwill) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Roll Forward]
Goodwill	$ 5,485	$ 5,871
Goodwill acquired	509	23
Goodwill	5,170	5,485
Goodwill impairment	(826)	(205)
Goodwill, Other Changes	2	(204)
Goodwill, Written off Related to Sale of Business Unit	0	0
Investment In ETP [Member]
Goodwill [Roll Forward]
Goodwill	5,428	7,642
Goodwill acquired	428	0
Goodwill	3,897	5,428
Goodwill impairment	(670)	(205)
Goodwill, Other Changes	0	9
Goodwill, Written off Related to Sale of Business Unit	(1,289)	(2,018)
Investment In Sunoco LP [Member]
Goodwill [Roll Forward]
Goodwill	1,123	1,149
Goodwill acquired	81	23
Goodwill	1,050	1,123
Goodwill impairment	(156)	0
Goodwill, Other Changes	2	(49)
Goodwill, Written off Related to Sale of Business Unit	0	0
Investment in Lake Charles LNG [Member]
Goodwill [Roll Forward]
Goodwill	184	184
Goodwill acquired	0	0
Goodwill	184	184
Goodwill impairment	0	0
Goodwill, Other Changes	0	0
Goodwill, Written off Related to Sale of Business Unit	0	0
Corporate, Other and Eliminations [Member]
Goodwill [Roll Forward]
Goodwill	(1,250)	(3,104)
Goodwill acquired	0	0
Goodwill	39	(1,250)
Goodwill impairment	0	0
Goodwill, Other Changes	0	(164)
Goodwill, Written off Related to Sale of Business Unit	$ 1,289	$ 2,018

Estimates, Significant Accoun54

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Asset Retirement Obligations) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations, Noncurrent	$ 170	$ 212

Estimates (Accrued And Other Cu

Estimates (Accrued And Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Other Information [Abstract]
Interest payable	$ 545	$ 519
Customer advances and deposits	72	114
Accrued capital expenditures	769	743
Accrued wages and benefits	254	218
Taxes payable other than income taxes	201	76
Exchanges payable	208	106
Other	318	632
Accrued and other current liabilities	$ 2,367	$ 2,408

Estimates (Fair Value Of Financ

Estimates (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Total liabilities	$ (672)
Level 1 [Member]
Total liabilities	(470)
Level 2 [Member]
Total liabilities	(201)
Level 3 [Member]
Total liabilities	(1)
Fair Value, Measurements, Recurring [Member]
Commodity derivatives:	363	$ 454
Total assets	363	454
Interest rate derivatives	(193)	(171)
Embedded derivatives in the ETP Preferred Units	(1)	(5)
Commodity derivatives:	(478)	(356)
Total liabilities		(532)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Commodity derivatives:	356	420
Total assets	356	420
Interest rate derivatives	0	0
Embedded derivatives in the ETP Preferred Units	0	0
Commodity derivatives:	(470)	(324)
Total liabilities		(324)
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Commodity derivatives:	7	34
Total assets	7	34
Interest rate derivatives	(193)	(171)
Embedded derivatives in the ETP Preferred Units	0	0
Commodity derivatives:	(8)	(32)
Total liabilities		(203)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Commodity derivatives:	0	0
Total assets	0	0
Interest rate derivatives	0	0
Embedded derivatives in the ETP Preferred Units	(1)	(5)
Commodity derivatives:	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value		5
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Put Option [Member]
Commodity derivatives:		(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Options - Calls [Member]
Commodity derivatives:	1	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Options - Puts [Member]
Commodity derivatives:		1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Forward Swaps [Member]
Commodity derivatives:	4	22
Commodity derivatives:	(5)	(22)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Future [Member]
Commodity derivatives:	1	3
Commodity derivatives:	(1)	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Put Option [Member]
Commodity derivatives:		(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Options - Calls [Member]
Commodity derivatives:	1	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Options - Puts [Member]
Commodity derivatives:		1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	1	3
Commodity derivatives:	(1)	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Put Option [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Options - Calls [Member]
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Options - Puts [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:	4	22
Commodity derivatives:	(5)	(22)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Put Option [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Options - Calls [Member]
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Options - Puts [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Future [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Forward Swaps [Member]
Commodity derivatives:		15
Commodity derivatives:	(13)	(6)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Future [Member]
Commodity derivatives:	2
Commodity derivatives:	(23)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:		15
Commodity derivatives:	(13)	(6)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	2
Commodity derivatives:	(23)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:	0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 3 [Member] | Future [Member]
Commodity derivatives:	0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:		9
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Future [Member]
Commodity derivatives:	9
Commodity derivatives:		(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:		9
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	9
Commodity derivatives:		(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:	0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 3 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 3 [Member] | Future [Member]
Commodity derivatives:	0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	14	16
Commodity derivatives:	(11)	(16)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	2	10
Commodity derivatives:	(3)	(12)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	96	274
Commodity derivatives:	(149)	(203)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	1	4
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	14	16
Commodity derivatives:	(11)	(16)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	0	2
Commodity derivatives:	0	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	96	274
Commodity derivatives:	(149)	(203)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	2	8
Commodity derivatives:	(3)	(10)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	1	4
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Forward Swaps [Member]
Commodity derivatives:	233	99
Commodity derivatives:	(273)	(89)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:	233	99
Commodity derivatives:	(273)	(89)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	$ 0	$ 0

Estimates, Significant Accoun57

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Fair Value Schedule of Unobservable Inputs) (Details)	Dec. 31, 2016
Unobservable Inputs [Abstract]
Fair Value Embedde Derivatives, Significant Unobservable Input, Credit Spread	5.12%
Fair Value, Embedded Derivatives, Significant Unobservable Input, Volatility	31.73%

Estimates (Reconciliation For L

Estimates (Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net unrealized gains included in other income (expense)	$ 4
Liabilities, Fair Value Disclosure, Recurring	672
Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Liabilities, Fair Value Disclosure, Recurring		$ 532
Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Liabilities, Fair Value Disclosure, Recurring	$ 1
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value		$ 5

Acquisitions and Related Tran59

Acquisitions and Related Transactions (2017 Acquisitions) (Details) $ in Millions	1 Months Ended		12 Months Ended
	Apr. 30, 2017USD ($)	Oct. 31, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 382
Income (loss) from discontinued operations, net of income taxes			$ (479)	$ 81	$ 130
Subsequent Event [Member] | 7-Eleven Transaction [Member]
Business Acquisition [Line Items]
Number of Stores	1,112
Payments to Acquire Businesses, Gross	$ 3,300
Subsequent Event [Member] | Discontinued Operations, Held-for-sale [Member]
Business Acquisition [Line Items]
Number of Stores	208
Sold in another transaction [Member] | Subsequent Event [Member] | Discontinued Operations, Held-for-sale [Member]
Business Acquisition [Line Items]
Number of Stores	9
Stores held for sale [Member] | Subsequent Event [Member] | Discontinued Operations, Held-for-sale [Member]
Business Acquisition [Line Items]
Number of Stores	97
Stores held for sale and currently sold [Member] | Subsequent Event [Member] | Discontinued Operations, Held-for-sale [Member]
Business Acquisition [Line Items]
Number of Stores	16
Stores held for sale and currently under contract [Member] | Subsequent Event [Member] | Discontinued Operations, Held-for-sale [Member]
Business Acquisition [Line Items]
Number of Stores	20
7-Eleven Transaction [Member] | Subsequent Event [Member] | Discontinued Operations, Held-for-sale [Member]
Business Acquisition [Line Items]
Number of Stores	31
Currently being marketed [Member] | Subsequent Event [Member] | Discontinued Operations, Held-for-sale [Member]
Business Acquisition [Line Items]
Number of Stores	21
Sunoco LP Convenience Store Sale [Member]
Business Acquisition [Line Items]
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents			20	25
Disposal Group, Including Discontinued Operation, Revenue			7,402	7,922	3,052
Disposal Group, Including Discontinued Operation, Assets			4,549	4,647
Disposal Group, Including Discontinued Operation, Other Assets			2	19
Disposal Group, Including Discontinued Operation, Intangible Assets			503	535
Disposal Group, Including Discontinued Operation, Goodwill			1,568	1,988
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment			2,185	1,899
Disposal Group, Including Discontinued Operation, Other Assets, Current			83	10
Disposal Group, Including Discontinued Operation, Inventory			188	171
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent			68	67
Disposal Group, Including Discontinued Operation, Costs of Goods Sold			6,020	6,574	2,553
Disposal Group, Including Discontinued Operation, Operating Expense			1,486	933	291
Disposal Group, Including Discontinued Operation, Depreciation and Amortization			193	175	55
Disposal Group, Including Discontinued Operation, General and Administrative Expense			114	91	55
Disposal Group, Including Discontinued Operations, Total Costs and Expenses			7,813	7,773	2,954
Disposal Group, Including Discontinued Operation, Operating Income (Loss)			(411)	149	98
Disposal Group, Including Discontinued Operation, Interest Expense			29	22	1
Disposal Group, Including Discontinued Operation, Other Expense			8	(2)	(1)
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax			(448)	129	98
Discontinued Operation, Tax Effect of Discontinued Operation			31	48	32
Income (loss) from discontinued operations, net of income taxes			(479)	81	66
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent			$ (12)	$ 1	$ 3

Acquisitions and Related Tran60

Acquisitions and Related Transactions Acquisitions (2016 Narrative) (Details) shares in Millions, barrels in Millions

1 Months Ended

12 Months Ended

Mar. 31, 2017

Feb. 28, 2017

Nov. 30, 2016USD ($)barrels

Oct. 31, 2016USD ($)

Aug. 31, 2016USD ($)

Apr. 30, 2016

Mar. 31, 2016USD ($)shares

Oct. 31, 2015USD ($)

Dec. 31, 2016USD ($)

Nov. 01, 2016USD ($)

Aug. 01, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Business Acquisition [Line Items]

Payments to Acquire Businesses, Gross

$ 382,000,000

Property, Plant and Equipment, Net

$ 53,253,000,000

$ 46,784,000,000

Intangible assets, net

5,489,000,000

4,896,000,000

Goodwill

5,170,000,000

5,485,000,000

$ 5,871,000,000

PennTex Acquisition [Member]

Business Acquisition [Line Items]

Business Acquisition, Goodwill, Expected Tax Deductible Amount

$ 0

Intangible assets

446,000,000

Business Combination, Consideration Transferred

$ 627,000,000

Goodwill1

[1]

177,000,000

Total consideration, net of cash received

$ 606,000,000

Vitol Acquisition [Member]

Business Acquisition [Line Items]

Business Combination, Consideration Transferred

$ 760,000,000

Crude Oil Terminal, Capacity, Bbls | barrels

2

Total consideration, net of cash received

$ 769,000,000

Net Working Capital

13,000,000

Property, Plant and Equipment, Net

286,000,000

Intangible assets, net

313,000,000

Goodwill

$ 251,000,000

Bakken Equity Sale [Member]

Business Acquisition [Line Items]

Payments to Acquire Businesses, Gross

$ 2,000,000,000

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%

Sunoco LP [Member] | Emerge Energy Services [Member]

Business Acquisition [Line Items]

Business Acquisition, Goodwill, Expected Tax Deductible Amount

$ 78,000,000

Intangible assets

$ 23,000,000

Business Combination, Consideration Transferred

$ 171,000,000

Sunoco LP [Member] | Convenience Stores [Member]

Business Acquisition [Line Items]

Business Combination, Consideration Transferred

$ 55,000,000

114,000,000

Goodwill1

61,000,000

Bakken Holdings Company LLC [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

40.00%

Subsequent Event [Member] | Permian Express Partners LLC [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

85.00%

Subsequent Event [Member] | ETP [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

3.30%

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 ETCOC [Member] | Subsequent Event [Member] | Phillips 66 Company [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

25.00%

Dakota Access and ETCOC [Member] | Subsequent Event [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

60.00%

Sunoco Logistics [Member] | Bakken Holdings Company LLC [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

40.00%

Bakken Pipeline Investments LLC [Member] | Bakken Holdings Company LLC [Member]

Business Acquisition [Line Items]

Business Acquisition, Percentage of Voting Interests Acquired

49.00%

Bakken Pipeline [Member] | Subsequent Event [Member] | Phillips 66 Company [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

25.00%

Bakken Pipeline [Member] | Subsequent Event [Member] | ETP and Sunoco Logistics [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

38.25%

Bakken Pipeline [Member] | Subsequent Event [Member] | MarEn Bakken Company [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

36.75%

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 Pipeline [Member]

Business Acquisition [Line Items]

Line of Credit Facility, Maximum Borrowing Capacity

2,500,000,000

Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]

Business Acquisition [Line Items]

Long-term Line of Credit

$ 1,100,000,000

$ 0

[1]

(1) None of the goodwill is expected to be deductible for tax purposes.

Acquisitions and Related Tran61

Acquisitions and Related Transactions Acquisitions (2015 Narrative) (Details) $ in Millions, gallons in Billions	1 Months Ended					3 Months Ended	12 Months Ended
	Aug. 31, 2016	Oct. 31, 2015USD ($)shares	Jul. 31, 2015USD ($)shares	Apr. 30, 2015USD ($)gallonsshares	Mar. 31, 2015USD ($)shares	Mar. 31, 2015USD ($)shares	Dec. 31, 2016USD ($)	Dec. 31, 2014USD ($)
Payments to Acquire Businesses, Gross | $		$ 382
Dropdown of Sunoco LLC Interest [Member]
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]
Payments to Acquire Businesses, Gross | $			$ 970
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable | $			$ 970
Sunoco LP Exchange [Member]
Stock Repurchased During Period, Shares | shares			31,500,000
IDR Subsidies | $			$ 35
Term of IDR Subsidy			10 years
Bakken Pipeline Transaction [Member]
Class I Distributions | $						$ 55	$ 30
Business Combination, Consideration Transferred | $					$ 879
Partners' Capital Account, Units, Redeemed | shares					46,200,000
Regency Merger [Member]
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 | $							$ 320
Dakota Access and ETCOC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		75.00%
Susser [Member] | Dropdown of Susser [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Sunoco LP [Member]
Partners' Capital Account, Sale of Units | $			$ 213					$ 405
Sunoco LP [Member] | Dropdown of Susser [Member]
Sale of Stock, Number of Shares Issued in Transaction | shares			22,000,000
Sunoco GP [Member] | Sunoco LP Exchange [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Parent Company [Member] | Bakken Pipeline Transaction [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					45.00%
Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		40.00%
Class I Units [Member] | Bakken Pipeline Transaction [Member]
Partners' Capital Account, Units | shares					100	100
Class B Units [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares		9,400,000
Class A Units [Member] | Sunoco LP [Member] | Dropdown of Susser [Member]
Sale of Stock, Number of Shares Issued in Transaction | shares			79,308
Class H Units [Member]
Partners' Capital Account, Units | shares					50,200,000	50,200,000
Allocation of Profits, Losses and Other by Sunoco, Percent							90.05%
Class H Units [Member] | Bakken Pipeline Transaction [Member]
Allocation of Profits, Losses and Other by Sunoco, Percent					90.05%	90.05%
Partners' Capital Account, Units, Redeemed | shares					30,800,000
ETP [Member] | Sunoco LP [Member] | Dropdown of Susser [Member]
Sale of Stock, Number of Shares Issued in Transaction | shares			10,900,000
ETP [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	60.00%
Relinquishment, Years 2 through 5 [Member] | Regency Merger [Member]
Relinquishment of Incentive Distributions | $							$ 60
Relinquishment, Year 1 [Member] | Regency Merger [Member]
Relinquishment of Incentive Distributions | $							$ 80
ETP Subsidiaries [Member] | Regency Merger [Member]
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, Equity Interest Issued or Issuable, Number of Shares | shares				1,900,000

Acquisitions and Related Tran62

Acquisitions and Related Transactions Acquisitions (2014 Narrative) (Details)	1 Months Ended							3 Months Ended								12 Months Ended
	Oct. 31, 2015USD ($)	Jul. 31, 2015USD ($)shares	Apr. 30, 2015shares	Oct. 31, 2014USD ($)shares	Aug. 31, 2014USD ($)shares	Mar. 21, 2014USD ($)$ / sharesshares	Feb. 28, 2014shares	Dec. 31, 2016USD ($)shares	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)shares	Oct. 01, 2014	Aug. 29, 2014USD ($)	Jan. 10, 2014shares
Related Party Transaction, Amounts of Transaction																$ 75,000,000
Payments to Acquire Businesses, Gross	$ 382,000,000
Revenues								$ 8,899,000,000	$ 7,705,000,000	$ 7,415,000,000	$ 6,083,000,000	$ 7,744,000,000	$ 8,473,000,000	$ 9,423,000,000	$ 8,564,000,000	30,102,000,000	$ 34,204,000,000	$ 52,639,000,000
Net income								$ (760,000,000)	$ 41,000,000	$ 424,000,000	$ 336,000,000	$ (138,000,000)	$ 238,000,000	$ 772,000,000	$ 221,000,000	41,000,000	1,093,000,000	1,124,000,000
Number of Regency Common Units to be Issued in Acquisition Per Share | shares						1.02
MACS Transaction [Member]
Business Combination, Consideration Transferred				$ 768,000,000
PVR Acquisition [Member]
Business Acquisition, Goodwill, Expected Tax Deductible Amount						$ 0
Revenues						956,000,000
Net income						166,000,000
Eagle Rock Midstream Acquisition [Member]
Revenues																903,000,000
Net income																$ 30,000,000
Sunoco LP [Member]
Business Combination, Consideration Transferred				$ 556,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares				4,000,000	11,000,000
Lake Charles LNG Transaction [Member]
Partners' Capital Account, Units, Redeemed | shares							28,100,000
Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares			258,300,000
Susser Merger [Member]
Business Acquisition, Goodwill, Expected Tax Deductible Amount																				$ 0
Business Combination, Consideration Transferred					$ 875,000,000
Payments to Acquire Businesses, Gross					$ 1,800,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares					23,700,000
Number of Stores																				630
Dealer-operated [Member] | MACS Transaction [Member]
Number of Stores																			200
Company-operated [Member] | MACS Transaction [Member]
Number of Stores																			110
Susser [Member]
Incentive Distribution Rights																				100.00%
Revenues																	2,320,000,000
Net income																	105,000,000
Business Combination, Acquisition Related Costs																	$ 25,000,000
Sunoco LP [Member]
Partners' Capital Account, Sale of Units		$ 213,000,000																$ 405,000,000
Partners' Capital Account, Units, Sale of Units | shares		5,500,000																9,100,000
Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent. | shares								100								100
Regency [Member] | PVR Acquisition [Member]
Business Combination, Consideration Transferred						5,700,000,000
Payments to Acquire Businesses, Gross						$ 36,000,000
Business Acquisition, Share Price | $ / shares						$ 27.82
Proceeds from divestiture of business						$ 1,800,000,000
Regency [Member] | Eagle Rock Midstream Acquisition [Member]
Proceeds from Issuance of Common Stock																$ 400,000,000
Stock Issued During Period, Shares, Acquisitions | shares																8,200,000
Business Combination, Consideration Transferred																$ 1,300,000,000
ETP [Member]
Incentive Distribution Rights								100.00%								100.00%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | shares								3,900,000								3,900,000
7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument, Interest Rate, Stated Percentage																					7.60%
8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument, Interest Rate, Stated Percentage																					8.25%
8.375% Senior Notes due June 1, 2019 [Member] | Regency [Member]
Senior Notes								$ 499,000,000								$ 499,000,000
Debt Instrument, Interest Rate, Stated Percentage								8.375%								8.375%
Panhandle [Member] | Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent. | shares																					31,400,000
Panhandle [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | shares																					3,300,000
Class F Units [Member] | Panhandle [Member] | Regency [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent. | shares																					6,300,000

Acquisitions (Schedule Of Asset

Acquisitions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition Table) (Details) - USD ($) $ in Millions		Nov. 01, 2016	Aug. 29, 2014	Jul. 01, 2014	Mar. 21, 2014
Susser Merger [Member]
Business Acquisition [Line Items]
Current assets			$ 446
Property, plant and equipment			1,069
Goodwill1			1,734
Intangible assets			611
Other assets			17
Total assets acquired			3,877
Current liabilities			377
Long-term debt obligations, less current maturities			564
Deferred income taxes			488
Other non-current liabilities			39
Noncontrolling interest			626
Total liabilities assumed			2,094
Total consideration			1,783
Cash received			67
Total consideration, net of cash received			$ 1,716
PVR Acquisition [Member]
Business Acquisition [Line Items]
Current assets					$ 149
Property, plant and equipment					2,716
Goodwill1					370
Intangible assets					2,717
Investments in unconsolidated affiliates					62
Other assets					18
Total assets acquired					6,032
Current liabilities					168
Long-term debt obligations, less current maturities					1,788
Premium related to senior notes					99
Other non-current liabilities					30
Total liabilities assumed					2,085
Total consideration					$ 3,947
PennTex Acquisition [Member]
Business Acquisition [Line Items]
Current assets		$ 34
Property, plant and equipment		393
Goodwill1	[1]	177
Intangible assets		446
Total assets acquired		1,050
Current liabilities		6
Long-term debt obligations, less current maturities		164
Other non-current liabilities		17
Noncontrolling interest		236
Total liabilities assumed		423
Total consideration		627
Cash received		21
Total consideration, net of cash received		$ 606
Eagle Rock Midstream Acquisition [Member]
Business Acquisition [Line Items]
Current assets				$ 120
Property, plant and equipment				1,295
Goodwill1				49
Other assets				4
Total assets acquired				1,468
Current liabilities				116
Long-term debt obligations, less current maturities				499
Other non-current liabilities				12
Total liabilities assumed				627
Total consideration, net of cash received				$ 841
[1]	(1) None of the goodwill is expected to be deductible for tax purposes.

Advances to and Investments i64

Advances to and Investments in Unconsolidated Affiliates Narrative (Details) - USD ($) shares in Millions, $ in Millions	Jan. 12, 2012	Oct. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Impairment losses			$ 970	$ 339	$ 370
Payments to Acquire Businesses, Gross		$ 382
Proceeds from the sale of other assets			$ 35	14	54
AmeriGas common units sold by ETP			(18.9)
Proceeds from the sale of AmeriGas common units			$ 0	0	814
Advances to and investments in unconsolidated affiliates			3,040	3,462	3,659
Goodwill			5,170	5,485	5,871
Equity in earnings from unconsolidated affiliates			$ 270	$ 276	$ 332
Citrus [Member]
Interest ownership			50.00%
Business Acquisition, Percentage of Voting Interests Acquired			50.00%
FGT [Member]
Percentage Ownership Operating Facility			100.00%
Fayetteville Express Pipeline, LLC [Member]
Interest ownership			50.00%
Midcontinent Express Pipeline, LLC [Member]
Interest ownership			50.00%
MEP [Member]
Impairment losses			$ 308
RIGS Haynesville Partnership Co. [Member]
Interest ownership			49.99%
AmeriGas [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	29.6
Proceeds from the sale of AmeriGas common units			$ 814
Investment Owned, Balance, Shares			3.1

Advances to and Investments i65

Advances to and Investments in Unconsolidated Affiliates Investment in Affiliates (Carrying Values) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Advances to and investments in unconsolidated affiliates	$ 3,040	$ 3,462	$ 3,659
RIGS Haynesville Partnership Co. [Member]
Advances to and investments in unconsolidated affiliates	382	402
Other Affiliates [Member]
Advances to and investments in unconsolidated affiliates	428	466
Citrus [Member]
Advances to and investments in unconsolidated affiliates	1,729	1,739
AmeriGas [Member]
Advances to and investments in unconsolidated affiliates	82	80
FEP [Member]
Advances to and investments in unconsolidated affiliates	101	115
MEP [Member]
Advances to and investments in unconsolidated affiliates	$ 318	$ 660

Investments in Affiliates (Summ

Investments in Affiliates (Summarized Balance Sheet Information) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Investment In Affiliates [Abstract]
Current assets	$ 720	$ 632
Property, plant and equipment, net	9,982	10,213
Other assets	2,618	2,649
Total assets	13,320	13,494
Current Liabilities	1,358	841
Non-current liabilities	7,583	7,950
Equity	4,379	4,703
Total liabilities and equity	$ 13,320	$ 13,494

Investments in Affiliates (Su67

Investments in Affiliates (Summarized Income Statement Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Investment In Affiliates [Abstract]
Revenues	$ 3,509	$ 4,026	$ 4,925
Operating Income	1,181	1,302	1,071
Net income	$ 602	$ 807	$ 577

Net Income Per Limited Partne68

Net Income Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Income from continuing operations	$ 520	$ 1,012	$ 994
Less: Income (loss) from continuing operations attributable to noncontrolling interest	(487)	(176)	371
Income from continuing operations, net of noncontrolling interest	1,007	1,188	623
Less: General Partner’s interest in income from continuing operations	3	3	2
Convertible Unitholders’ interest in income	8	0	0
Less: Class D Unitholder’s interest in income from continuing operations	0	3	2
Income from continuing operations available to Limited Partners	996	1,182	619
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units	8	3	(2)
Diluted income from continuing operations available to Limited Partners	$ 1,004	$ 1,185	$ 617
Weighted average limited partner units	1,045.5	1,062.8	1,088.6
Basic income from continuing operations per Limited Partner unit	$ 0.95	$ 1.11	$ 0.57
Basic income (loss) from discontinued operations per Limited Partner unit	$ (0.01)	$ 0	$ 0.01
Dilutive effect of unconverted unit awards and Convertible Units	33.1	1.6	2.2
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	1,078.6	1,064.4	1,090.8
Diluted income from continuing operations per Limited Partner unit	$ 0.93	$ 1.11	$ 0.57
Diluted income (loss) from discontinued operations per Limited Partner unit	$ (0.01)	$ 0	$ 0.01

Debt Obligations Debt Obligat69

Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) - USD ($) $ in Millions		Dec. 31, 2016	Apr. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Capital Lease Obligations		$ 118		$ 126
Debt Instrument, Unamortized Discount (Premium), Net		156
Other Long-term Debt		31		31
Long-term Debt		43,802		36,968
Current maturities of long-term debt		1,194		131
Long-term debt, less current maturities		42,608		36,837
Parent Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		15		17
Deferred Finance Costs, Noncurrent, Net		(30)		(38)
Long-term Debt		6,357		6,332
Long-term debt, less current maturities		6,358		6,332
Parent Company [Member] | ETE 7.5% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		1,187		1,187
Parent Company [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		1,150		1,150
Parent Company [Member] | 5.5% Senior Notes due June 1, 2027 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000		1,000
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument [Line Items]
Secured Debt		2,190		2,190
Parent Company [Member] | ETE Senior Secured Revolving Credit Facility due December 18, 2018 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		875		860
ETP [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		(18)		(21)
Deferred Finance Costs, Noncurrent, Net		(132)		(147)
Long-term Debt		22,067		20,633
ETP [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		277		277
ETP [Member] | 4.05% Senior Notes due March 2025 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000		1,000
ETP [Member] | 4.75% Senior Notes due January 2026 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000		1,000
ETP [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes		267		267
ETP [Member] | 4.90% Senior Notes due March 2035 [Member]
Debt Instrument [Line Items]
Senior Notes		500		500
ETP [Member] | 6.625% Senior Notes, due October 15, 2036 [Member]
Debt Instrument [Line Items]
Senior Notes		400		400
ETP [Member] | 7.5% Senior Notes, due July 1, 2038 [Member]
Debt Instrument [Line Items]
Senior Notes		550		550
ETP [Member] | Senior Notes 6.05% Due June 1, 2041 [Member]
Debt Instrument [Line Items]
Senior Notes		700		700
ETP [Member] | Senior Notes 6.50% Due February 1, 2042 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000		1,000
ETP [Member] | 5.15% Senior Notes due February 1, 2043 [Member]
Debt Instrument [Line Items]
Senior Notes		450		450
ETP [Member] | 5.95% Senior Notes due October 1, 2043 [Member]
Debt Instrument [Line Items]
Senior Notes		450		450
ETP [Member] | 5.15% Senior Notes due March 2045 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000		1,000
ETP [Member] | 6.125% Senior Notes due December 2045 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000		1,000
ETP [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member]
Debt Instrument [Line Items]
Junior Subordinated Notes		546		545
ETP [Member] | ETP Credit Facility due November 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		2,777		1,362
ETP [Member] | 6.125% Senior Notes, due February 15, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes		400		400
ETP [Member] | 2.50% Senior Notes due June 2018 [Member]
Debt Instrument [Line Items]
Senior Notes		650		650
ETP [Member] | 6.7% Senior Notes, due July 1, 2018 [Member]
Debt Instrument [Line Items]
Senior Notes		600		600
ETP [Member] | 9.7% Senior Notes, due March 15, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes		400		400
ETP [Member] | 9.0% Senior Notes due April 15, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes		450		450
ETP [Member] | 5.75% Senior Notes due September 1, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		400		400
ETP [Member] | 4.15% Senior Notes due October 1, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		1,050		1,050
ETP [Member] | 5.875% Senior Notes due April 1, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		900		900
ETP [Member] | 5.5% Senior Notes, due April 15, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		700		700
ETP [Member] | 4.5% Senior Notes due November 1, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		600		600
ETP [Member] | 4.9% Senior Notes due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		350		350
ETP [Member] | 6.5% Senior Notes due May 15, 2021 [Member]
Debt Instrument [Line Items]
Senior Notes		500		500
ETP [Member] | Senior Notes 4.65% Due June 1, 2021 [Member]
Debt Instrument [Line Items]
Senior Notes		800		800
ETP [Member] | Senior Notes 5.20% Due February 1, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000		1,000
ETP [Member] | 5.0% Senior Notes due October 1, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		700		700
ETP [Member] | 3.6% Senior Notes due February 1, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		800		800
Sunoco [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		(9)		(20)
Long-term Debt		474		485
Sunoco [Member] | 5.75% Senior Notes, due 2017 [Member]
Debt Instrument [Line Items]
Senior Notes		400		400
Sunoco [Member] | 9.00% Debentures, due 2024 [Member]
Debt Instrument [Line Items]
Subordinated Debt		65		65
Sunoco Logistics [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		75		85
Deferred Finance Costs, Noncurrent, Net		(34)		(32)
Long-term Debt		7,313		5,590
Sunoco Logistics [Member] | 6.125% Senior Notes, due May 15, 2016 [Member]
Debt Instrument [Line Items]
Senior Notes		0		175
Sunoco Logistics [Member] | 5.50% Senior Notes, due February 15, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		250		250
Sunoco Logistics [Member] | Senior Note 4.65% Due February 15, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		300		300
Sunoco Logistics [Member] | 3.45% Senior Notes due January 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		350		350
Sunoco Logistics [Member] | 6.85% Senior Notes, due February 15, 2040 [Member]
Debt Instrument [Line Items]
Senior Notes		250		250
Sunoco Logistics [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		500		500
Sunoco Logistics [Member] | 5.95% Senior Notes due December 2025 [Member]
Debt Instrument [Line Items]
Senior Notes		400		400
Sunoco Logistics [Member] | 3.90% Senior Notes due July 15, 2026 [Member]
Debt Instrument [Line Items]
Senior Notes		550		0
Sunoco Logistics [Member] | Senior Note 6.10%, due February 15, 2042 [Member]
Debt Instrument [Line Items]
Senior Notes		300		300
Sunoco Logistics [Member] | 5.30% Senior Notes due April 1, 2044 [Member]
Debt Instrument [Line Items]
Senior Notes		700		700
Sunoco Logistics [Member] | 5.35% Senior Notes due May 15, 2045 [Member]
Debt Instrument [Line Items]
Senior Notes		800		800
Sunoco Logistics [Member] | 4.95% Senior Notes due January 2043 [Member]
Debt Instrument [Line Items]
Senior Notes		350		350
Sunoco Logistics [Member] | Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		1,292		562
Sunoco Logistics [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	[1]	630		0
Bakken Project [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net		(13)		0
Long-term Debt		1,087		0
Bakken Project [Member] | Bakken Project $2.50 billion Credit Facility due August 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		1,100		0
PennTex [Member] | PennTex $275 million Revolving Credit Facility due December 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		168		0
Sunoco LP [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net		(47)		(18)
Long-term Debt		4,514		1,958
Sunoco LP [Member] | 5.5% Senior Notes due August 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		600		600
Sunoco LP [Member] | 6.375% Senior Notes due April 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		800		800
Sunoco LP [Member] | 6.25% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Senior Notes		800	$ 800	0
Sunoco LP [Member] | Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		1,000		450
Sunoco LP [Member] | Term loan due 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		1,243		0
Long-term Debt		2,035
Transwestern [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		0		(1)
Deferred Finance Costs, Noncurrent, Net		(1)		(2)
Long-term Debt		656		779
Transwestern [Member] | 5.54% Senior Unsecured Notes, due November 17, 2016 [Member]
Debt Instrument [Line Items]
Senior Notes		0		125
Transwestern [Member] | 5.64% Senior Unsecured Notes, due May 24, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes		82		82
Transwestern [Member] | 5.36% Senior Unsecured Notes, due December 9, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		175		175
Transwestern [Member] | 5.89% Senior Unsecured Notes, due May 24, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		150		150
Transwestern [Member] | 5.66% Senior Unsecured Notes, due December 9, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		175		175
Transwestern [Member] | 6.16% Senior Unsecured Notes, due May 24, 2037 [Member]
Debt Instrument [Line Items]
Senior Notes		75		75
Panhandle [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		(50)		(75)
Long-term Debt		1,135		1,160
Panhandle [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		82		82
Panhandle [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes		33		33
Panhandle [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member]
Debt Instrument [Line Items]
Junior Subordinated Notes		54		54
Panhandle [Member] | 6.20% Senior Notes, due November 1, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes		300		300
Panhandle [Member] | 7.00% Senior Notes, due June 15, 2018 [Member]
Debt Instrument [Line Items]
Senior Notes		400		400
Panhandle [Member] | 8.125% Senior Notes, due June 1, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes		150		150
Panhandle [Member] | 7.00% Senior Notes, due July 15, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes		$ 66		$ 66
[1]	(1) Sunoco Logistics’ $1.0 billion 364-Day Credit Facility, including its $630 million term loan, were classified as long-term debt as of December 31, 2016 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis.

Debt Obligations Debt Obligat70

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
2,017	$ 1,817
2,018	2,530
2,019	9,483
2,020	4,960
2,021	2,706
Thereafter	22,462
Long-term Debt	43,802	$ 36,968
Excluding unamortized premiums and fair value adjustments [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 43,958

Debt Obligations (Debt Narrativ

Debt Obligations (Debt Narrative) (Details) - USD ($) shares in Millions, $ in Millions		1 Months Ended			12 Months Ended
		Mar. 31, 2017	Jan. 31, 2017	Apr. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2017	Oct. 05, 2012
Noncontrolling interest					$ 24,211	$ 24,530
Less: Net income (loss) attributable to noncontrolling interest					(954)	(96)	$ 491
Repayments of Long-term Debt					19,076	19,828	13,886
Long-term Debt					43,802	36,968
Proceeds from borrowings					25,785	26,455	18,375
Advances to and investments in unconsolidated affiliates					3,040	3,462	3,659
Equity in earnings from unconsolidated affiliates					270	276	332
Sunoco Merger [Member]
Senior Notes					465				$ 965
PennTex [Member] | PennTex $275 million Revolving Credit Facility due December 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity					275
Outstanding borrowings					168	0
Line of Credit Facility, Maximum Borrowing Capacity					400
Line of Credit Facility, Remaining Borrowing Capacity					$ 106
Line of Credit Facility, Interest Rate at Period End					2.90%
Sunoco [Member]
Long-term Debt					$ 474	485
Sunoco [Member] | 5.75% Senior Notes, due 2017 [Member]
Senior Notes					$ 400	400
Debt instrument, interest rate, stated percentage					5.75%
Debt Instrument, Maturity Date					Jan. 15, 2017
Parent Company [Member]
Repayments of Long-term Debt					$ 210	1,985	1,142
Long-term Debt					6,357	6,332
Proceeds from borrowings					225	3,672	3,020
Advances to and investments in unconsolidated affiliates					5,088	5,764
Equity in earnings from unconsolidated affiliates					1,511	1,601	955
Parent Company [Member] | 5.5% Senior Notes due June 1, 2027 [Member]
Senior Notes					$ 1,000	1,000
Debt instrument, interest rate, stated percentage					5.50%
Debt Instrument, Maturity Date					Jun. 1, 2027
Parent Company [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Senior Notes					$ 1,150	1,150
Debt instrument, interest rate, stated percentage					5.88%
Debt Instrument, Maturity Date					Jan. 15, 2024
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Secured Debt					$ 2,190	2,190
Debt Instrument, Covenant Description					Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the MLP Merger, ETP , and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics ; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the MLP Merger, ETP, and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.
Debt Instrument, Collateral					Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 18.4 million common units representing limited partner interests in ETP and approximately 81.0 million Class H units of ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in, immediately prior to the consummation of the MLP Merger, ETP and, immediately after the consummation of the MLP Merger, Sunoco Logistics
Debt Instrument, Maturity Date					Dec. 2, 2019
Panhandle [Member]
Long-term Debt					$ 1,135	1,160
Panhandle [Member] | 3.26% Junior Subordinated Notes due November 1, 2066 [Member]
Debt Instrument, Interest Rate, Effective Percentage					3.77%
Panhandle [Member] | Junior Subordinated Debt [Member]
Debt Instrument, Description of Variable Rate Basis					three-month LIBOR rate plus 3.0175%
Panhandle [Member] | Variable Rate Portion of Debt [Member] | Junior Subordinated Debt [Member]
Senior Notes					$ 54
ETP [Member]
Long-term Debt					$ 22,067	20,633
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.					3.9
ETP [Member] | 3.26% Junior Subordinated Notes due November 1, 2066 [Member]
Debt instrument, interest rate, stated percentage					7.20%
Debt Instrument, Maturity Date					Nov. 1, 2066
ETP [Member] | 5.875% Senior Notes due April 1, 2022 [Member]
Senior Notes					$ 900	900
Debt instrument, interest rate, stated percentage					5.88%
Debt Instrument, Maturity Date					Mar. 1, 2022
ETP [Member] | 5.0% Senior Notes due October 1, 2022 [Member]
Senior Notes					$ 700	700
Debt instrument, interest rate, stated percentage					5.00%
Debt Instrument, Maturity Date					Oct. 1, 2022
ETP [Member] | ETP Credit Facility due November 2019 [Member]
Letters of Credit Outstanding, Amount					$ 160
Commercial Paper					777
Line of Credit Facility, Current Borrowing Capacity					3,750
Outstanding borrowings					2,777	1,362
Line of Credit Facility, Remaining Borrowing Capacity					$ 813
Line of Credit Facility, Interest Rate at Period End					2.20%
Sunoco Logistics [Member]
Long-term Debt					$ 7,313	5,590
Sunoco Logistics [Member] | 5.35% Senior Notes due May 15, 2045 [Member]
Senior Notes					$ 800	800
Debt instrument, interest rate, stated percentage					5.35%
Debt Instrument, Maturity Date					May 15, 2045
Sunoco Logistics [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Senior Notes					$ 500	500
Debt instrument, interest rate, stated percentage					4.25%
Debt Instrument, Maturity Date					Apr. 1, 2024
Sunoco Logistics [Member] | 4.40% Senior Notes due April 2021 [Member]
Senior Notes					$ 600	600
Debt instrument, interest rate, stated percentage					4.40%
Debt Instrument, Maturity Date					Apr. 1, 2021
Sunoco Logistics [Member] | 3.90% Senior Notes due July 15, 2026 [Member]
Senior Notes					$ 550	0
Debt instrument, interest rate, stated percentage					3.90%
Debt Instrument, Maturity Date					Jul. 15, 2026
Sunoco Logistics [Member] | Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member]
Commercial Paper					$ 50
Line of Credit Facility, Current Borrowing Capacity					2,500
Outstanding borrowings					1,292	562
Line of Credit Facility, Maximum Borrowing Capacity					$ 3,250
Line of Credit Facility, Interest Rate at Period End					1.76%
Sunoco Logistics [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member]
Line of Credit Facility, Current Borrowing Capacity					$ 1,000
Outstanding borrowings	[1]				630	0
Line of Credit Facility, Maximum Borrowing Capacity					1,000
Bakken Project [Member]
Long-term Debt					1,087	0
Bakken Project [Member] | Bakken Project $2.50 billion Credit Facility due August 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity					2,500
Outstanding borrowings					$ 1,100	0
Line of Credit Facility, Interest Rate at Period End					2.13%
Sunoco LP [Member]
Long-term Debt					$ 4,514	1,958
Sunoco LP [Member] | Term loan due 2019 [Member]
Long-term Debt					2,035
Outstanding borrowings					1,243	0
Sunoco LP [Member] | Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity					1,500
Outstanding borrowings					1,000	450
Sunoco LP [Member] | 5.5% Senior Notes due August 2020 [Member]
Senior Notes					$ 600	600
Debt instrument, interest rate, stated percentage					5.50%
Debt Instrument, Maturity Date					Aug. 1, 2020
Sunoco LP [Member] | 6.375% Senior Notes due April 2023 [Member]
Senior Notes					$ 800	800
Debt instrument, interest rate, stated percentage					6.375%
Debt Instrument, Maturity Date					Apr. 1, 2023
Sunoco LP [Member] | 6.25% Senior Notes due 2021 [Member]
Senior Notes				$ 800	$ 800	0
Debt instrument, interest rate, stated percentage				6.25%	6.25%
Proceeds from borrowings				$ 789
Debt Instrument, Maturity Date					Apr. 15, 2021
Letter of Credit [Member]
Debt Instrument, Basis Spread on Variable Rate					2.75%
Base Rate Loans [Member]
Debt Instrument, Basis Spread on Variable Rate					1.75%
ETP [Member] | ETP GP [Member]
Noncontrolling interest					$ 18,430	20,530
Less: Net income (loss) attributable to noncontrolling interest					$ (651)	$ 334	823
ETP [Member] | ETE Common Holdings [Member]
Advances to and investments in unconsolidated affiliates							1,720
Equity in earnings from unconsolidated affiliates							$ 292
ETE Common Holdings [Member] | Regency [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.							30.9
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest							7.50%
ETE Common Holdings [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.							5.2
Percent of total equity ownership of a subsidiary							1.50%
Class H Units [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.					81
Class H Units [Member] | ETE Common Holdings [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.							50.2
Percent of total equity ownership of a subsidiary							100.00%
Subsequent Event [Member]
Proceeds from borrowings			$ 1,480
Subsequent Event [Member] | 4.20% Senior Notes due April 2027 [Member]
Senior Notes			$ 600
Debt instrument, interest rate, stated percentage			4.20%
Subsequent Event [Member] | 5.30% Senior Notes due April 2047 [Member]
Senior Notes			$ 900
Debt instrument, interest rate, stated percentage			5.30%
Subsequent Event [Member] | Sunoco [Member] | 5.75% Senior Notes, due 2017 [Member]
Repayments of Long-term Debt			$ 400
Subsequent Event [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.								18.4
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		3.30%
Subsequent Event [Member] | Class H Units [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.								81
ETE Credit Facility [Member]
Line of Credit Facility, Current Borrowing Capacity					$ 1,500
Letters Of Credit Availablity					$ 150
ETE Credit Facility [Member] | Letter of Credit [Member] | Minimum [Member]
Debt Instrument, Basis Spread on Variable Rate					1.75%
ETE Credit Facility [Member] | Letter of Credit [Member] | Maximum [Member]
Debt Instrument, Basis Spread on Variable Rate					2.50%
ETE Credit Facility [Member] | Base Rate Loans [Member] | Minimum [Member]
Debt Instrument, Basis Spread on Variable Rate					0.75%
ETE Credit Facility [Member] | Base Rate Loans [Member] | Maximum [Member]
Debt Instrument, Basis Spread on Variable Rate					1.50%
[1]	(1) Sunoco Logistics’ $1.0 billion 364-Day Credit Facility, including its $630 million term loan, were classified as long-term debt as of December 31, 2016 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis.

Debt Obligations Debt Obligat72

Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2016
Debt Instrument [Line Items]
Leverage Ratio Maximum	6
Maximum Leverage Ratio Permitted	7
Debt instrument covenant minimum fixed charge coverage ratio	1.5
ETP [Member]
Debt Instrument [Line Items]
Leverage Ratio Maximum	5
Maximum Leverage Ratio Permitted	5.5
Sunoco Logistics [Member]
Debt Instrument [Line Items]
Maximum consolidated EBITDA ratio	5
Adjusted EBITDA Ratio	4.4
Bakken Project $2.50 billion Credit Facility due August 2019 [Member]
Debt Instrument [Line Items]
Minimum debt service coverage ratio	1.20
PennTex [Member]
Debt Instrument [Line Items]
Leverage Ratio Maximum	4.75
Minimum interest coverage ratio	2.50
Acquisition Period [Member] | Sunoco Logistics [Member]
Debt Instrument [Line Items]
Maximum consolidated EBITDA ratio	5.5
Leverage Ratio [Member] | Sunoco LP [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	The Sunoco LP Credit Facilities  require Sunoco LP to maintain a leverage ratio (as defined therein) of not more than (a) as of the last day of each fiscal quarter through December 31, 2017, 6.75 to 1.0, (b) as of March 31, 2018, 6.5 to 1.0, (c) as of June 30, 2018, 6.25 to 1.0, (d) as of September 30, 2018, 6.0 to 1.0, (e) as of December 31, 2018, 5.75 to 1.0 and (f) thereafter, 5.5 to 1.0 (in the case of the quarter ending March 31, 2019 and thereafter, subject to increases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of $50 million, as permitted under the Credit Facilities.  Indebtedness under the Credit Facilities is secured by a security interest in, among other things, all of Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing borrowings under the Credit Facilities will be released.
Minimum [Member] | PennTex [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.35%
Minimum [Member] | Applicable margins for LIBOR rate loans [Member] | PennTex [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%
Minimum [Member] | Applicable margin for ABR loans [Member] | PennTex [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Maximum [Member] | PennTex [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.50%
Maximum [Member] | Applicable margins for LIBOR rate loans [Member] | PennTex [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.25%
Maximum [Member] | Applicable margin for ABR loans [Member] | PennTex [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.25%

Debt Obligations Debt Obligat73

Debt Obligations Debt Obligations (Interest Rates & Maturities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Apr. 30, 2016	Dec. 31, 2015
Parent Company [Member]
Deferred Finance Costs, Noncurrent, Net	$ 30		$ 38
ETP [Member]
Deferred Finance Costs, Noncurrent, Net	132		147
Sunoco Logistics [Member]
Deferred Finance Costs, Noncurrent, Net	34		32
Sunoco LP [Member]
Deferred Finance Costs, Noncurrent, Net	47		18
Transwestern [Member]
Deferred Finance Costs, Noncurrent, Net	$ 1		$ 2
6.375% Senior Notes due April 2023 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.375%
Debt Instrument, Maturity Date	Apr. 1, 2023
6.25% Senior Notes due 2021 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.25%	6.25%
Debt Instrument, Maturity Date	Apr. 15, 2021
ETE 7.5% Senior Notes due 2020 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	Oct. 15, 2020
5.875% Senior Notes due January 15, 2024 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Debt Instrument, Maturity Date	Jan. 15, 2024
5.5% Senior Notes due June 1, 2027 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Jun. 1, 2027
ETE Senior Secured Term Loan due December 2, 2018 [Member] | Parent Company [Member]
Debt Instrument, Maturity Date	Dec. 2, 2018
ETE Senior Secured Term Loan due December 2, 2019 [Member] | Parent Company [Member]
Debt Instrument, Maturity Date	Dec. 2, 2019
6.125% Senior Notes, due February 15, 2017 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument, Maturity Date	Feb. 15, 2017
2.50% Senior Notes due June 2018 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument, Maturity Date	Jun. 15, 3028
6.7% Senior Notes, due July 1, 2018 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.70%
Debt Instrument, Maturity Date	Jul. 1, 2018
9.7% Senior Notes, due March 15, 2019 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.70%
Debt Instrument, Maturity Date	Mar. 15, 2019
9.0% Senior Notes due April 15, 2019 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%
Debt Instrument, Maturity Date	Apr. 15, 2019
4.15% Senior Notes due October 1, 2020 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.15%
Debt Instrument, Maturity Date	Oct. 1, 2020
Senior Notes 4.65% Due June 1, 2021 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	Jun. 1, 2021
Senior Notes 5.20% Due February 1, 2022 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.20%
Debt Instrument, Maturity Date	Feb. 1, 2022
3.6% Senior Notes due February 1, 2023 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.60%
Debt Instrument, Maturity Date	Feb. 1, 2023
4.9% Senior Notes due February 1, 2024 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.90%
Debt Instrument, Maturity Date	Feb. 1, 2024
6.625% Senior Notes, due October 15, 2036 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Debt Instrument, Maturity Date	Oct. 15, 2036
4.90% Senior Notes due March 2035 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.90%
Debt Instrument, Maturity Date	Mar. 15, 2035
7.5% Senior Notes, due July 1, 2038 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	Jul. 1, 2038
Senior Notes 6.05% Due June 1, 2041 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.05%
Debt Instrument, Maturity Date	Jun. 1, 2041
Senior Notes 6.50% Due February 1, 2042 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Maturity Date	Feb. 1, 2042
5.15% Senior Notes due February 1, 2043 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Debt Instrument, Maturity Date	Feb. 1, 2043
5.95% Senior Notes due October 1, 2043 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt Instrument, Maturity Date	Oct. 1, 2043
5.15% Senior Notes due March 2045 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Debt Instrument, Maturity Date	Mar. 15, 2045
6.125% Senior Notes due December 2045 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument, Maturity Date	Dec. 15, 2045
6.20% Senior Notes, due November 1, 2017 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.20%
Debt Instrument, Maturity Date	Nov. 1, 2017
7.00% Senior Notes, due June 15, 2018 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Debt Instrument, Maturity Date	Jun. 15, 2018
8.125% Senior Notes, due June 1, 2019 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.125%
Debt Instrument, Maturity Date	Jun. 1, 2019
7.00% Senior Notes, due July 15, 2029 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Debt Instrument, Maturity Date	Jul. 15, 2029
Term Loan due February 23, 2015 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.84%
Debt Instrument, Maturity Date	Feb. 23, 2015
5.75% Senior Notes due September 1, 2020 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument, Maturity Date	Sep. 1, 2020
5.875% Senior Notes due April 1, 2022 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Debt Instrument, Maturity Date	Mar. 1, 2022
5.5% Senior Notes, due April 15, 2023 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Apr. 15, 2023
4.5% Senior Notes due November 1, 2023 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Debt Instrument, Maturity Date	Nov. 1, 2023
6.5% Senior Notes due May 15, 2021 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Maturity Date	May 15, 2021
5.0% Senior Notes due October 1, 2022 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Debt Instrument, Maturity Date	Oct. 1, 2022
7.60% Senior Notes, due February 1, 2024 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt Instrument, Maturity Date	Feb. 1, 2024
7.60% Senior Notes, due February 1, 2024 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt Instrument, Maturity Date	Feb. 1, 2024
4.05% Senior Notes due March 2025 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.05%
Debt Instrument, Maturity Date	Mar. 15, 2025
4.75% Senior Notes due January 2026 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.75%
Debt Instrument, Maturity Date	Jan. 15, 2026
8.25% Senior Notes, due November 14, 2029 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Debt Instrument, Maturity Date	Nov. 15, 2029
8.25% Senior Notes, due November 14, 2029 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Debt Instrument, Maturity Date	Nov. 14, 2029
7.2% Junior Subordinated Notes due November 21, 2066 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.20%
Debt Instrument, Maturity Date	Nov. 1, 2066
5.75% Senior Notes, due 2017 [Member] | Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument, Maturity Date	Jan. 15, 2017
9.00% Debentures, due 2024 [Member] | Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%
Debt Instrument, Maturity Date	Nov. 1, 2024
6.125% Senior Notes, due May 15, 2016 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument, Maturity Date	May 15, 2016
5.50% Senior Notes, due February 15, 2020 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Feb. 15, 2020
4.40% Senior Notes due April 2021 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.40%
Debt Instrument, Maturity Date	Apr. 1, 2021
Senior Note 4.65% Due February 15, 2022 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	Feb. 15, 2022
3.45% Senior Notes due January 2023 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.45%
Debt Instrument, Maturity Date	Jan. 15, 2023
4.25% Senior Notes due April 1, 2024 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Debt Instrument, Maturity Date	Apr. 1, 2024
5.95% Senior Notes due December 2025 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt Instrument, Maturity Date	Dec. 1, 2025
3.90% Senior Notes due July 15, 2026 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.90%
Debt Instrument, Maturity Date	Jul. 15, 2026
6.85% Senior Notes, due February 15, 2040 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.85%
Debt Instrument, Maturity Date	Feb. 15, 2040
Senior Note 6.10%, due February 15, 2042 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.10%
Debt Instrument, Maturity Date	Feb. 15, 2042
4.95% Senior Notes due January 2043 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.95%
Debt Instrument, Maturity Date	Jan. 15, 2043
5.30% Senior Notes due April 1, 2044 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.30%
Debt Instrument, Maturity Date	Apr. 1, 2044
5.35% Senior Notes due May 15, 2045 [Member] | Sunoco Logistics [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.35%
Debt Instrument, Maturity Date	May 15, 2045
5.54% Senior Unsecured Notes, due November 17, 2016 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.54%
Debt Instrument, Maturity Date	Nov. 17, 2016
5.64% Senior Unsecured Notes, due May 24, 2017 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.64%
Debt Instrument, Maturity Date	May 24, 2017
5.36% Senior Unsecured Notes, due December 9, 2020 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.36%
Debt Instrument, Maturity Date	Dec. 9, 2020
5.89% Senior Unsecured Notes, due May 24, 2022 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.89%
Debt Instrument, Maturity Date	May 24, 2022
5.66% Senior Unsecured Notes, due December 9, 2024 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.66%
Debt Instrument, Maturity Date	Dec. 9, 2024
6.16% Senior Unsecured Notes, due May 24, 2037 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.16%
Debt Instrument, Maturity Date	May 24, 2037

Redeemable Preferred Units (Det

Redeemable Preferred Units (Details)	1 Months Ended	9 Months Ended	12 Months Ended
	Jan. 31, 2017USD ($)shares	Sep. 30, 2015shares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares	Apr. 30, 2015USD ($)$ / commonunit
Preferred Units, Issued | shares			329,299,267	0
Mandatory redeemable price of units outstanding					$ 35,000,000
Issuance of common units			$ 37,000,000	$ 0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares		1,300,000
Preferred Units Quarterly Cash Distribution Per Unit | $ / commonunit					0.445
Preferrred Units Issued Stated Price					$ 18.30
Conversion Price of Preferred Units					$ 44.37
Subsequent Event [Member]
Payments for Repurchase of Preferred Stock and Preference Stock	$ 53,000,000
Subsequent Event [Member] | ETP Series A Preferred Units [Member]
Partners' Capital Account, Units, Redeemed | shares	1,900,000

Equity (Narrative) (Details)

Equity (Narrative) (Details) - USD ($)	1 Months Ended											3 Months Ended																	6 Months Ended	12 Months Ended			36 Months Ended
	Mar. 31, 2017	Feb. 28, 2017	Jan. 31, 2017	Oct. 31, 2016	Aug. 31, 2016	Mar. 31, 2016	Oct. 31, 2015	Jul. 31, 2015	Mar. 31, 2015	Aug. 31, 2014	Mar. 21, 2014	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	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Aug. 01, 2016	Jul. 31, 2016	Apr. 30, 2015	Dec. 31, 2012	Oct. 05, 2012
Proposed Environmental Penalty												$ 0																	$ 0	$ 0			$ 0
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016)												$ 180,000,000								$ 0									$ 180,000,000	$ 180,000,000	$ 0		$ 180,000,000
Stock Issued During Period, Shares, New Issues																														2,100,000	0	0
Ratio of Convertible Units to Common Units												31.50%																	31.50%	31.50%			31.50%
Stock Repurchase Program, Authorized Amount												$ 2,000,000,000												$ 1,000,000,000					$ 2,000,000,000	$ 2,000,000,000		$ 1,000,000,000	$ 2,000,000,000
Partners' Capital Account, Units, Unit-based Compensation																														0	33,600,000	42,300,000
Stock Repurchase Program, Remaining Authorized Repurchase Amount												$ 936,000,000																	$ 936,000,000	$ 936,000,000			$ 936,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted																														3,000,000
Minimum beneficial percentage ownership, other than the Partnership's General Partner and its affiliates, no voting rights, not considered outstanding												20.00%																	20.00%	20.00%			20.00%
Limited Partners' Capital Account, Units Outstanding												1,046,947,157								1,044,767,336				1,077,500,000				1,119,800,000	1,046,947,157	1,046,947,157	1,044,767,336	1,077,500,000	1,046,947,157
Limited Partner interest in the Partnership, percentage																														97.71%
Gain from subsidiary issuances of common units																														$ 16,000,000	$ (526,000,000)	$ 744,000,000
Common Units Issued In Connection With The Dividend Reinvestment Plan																																	25,700,000
Class E Unit Distribution Rate												11.10%																	11.10%	11.10%			11.10%
Class E Unit Maximum Distribution												$ 1.41																	$ 1.41	$ 1.41			$ 1.41
Class F Unit Distribution Rate												35.00%																	35.00%	35.00%			35.00%
Class F Unit Maximum Distribution												$ 3.75																	$ 3.75	$ 3.75			$ 3.75
Payments to Acquire Businesses, Gross							$ 382,000,000
Conversion Price of Preferred Units																																				$ 44.37
Kelcy L. Warren [Member]
Stock Issued During Period, Shares, New Issues																														187,313,942
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest																														18.00%
Messrs. McReynolds, Ramsey and McCrea [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest																														2.20%
Mr. Ray Davis [Member] | LE GP, LLC [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest																														18.80%
Mr. Ray Davis [Member] | ETE [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest																														6.90%
PennTex [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit												0.2950		$ 0.2950
ETP [Member]
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	$ 0.6500	$ 0.6367	$ 0.6233	$ 0.6133
Common Units Issued Inconnection With The Equity Distribution Agreement																														39,200,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement																														$ 891,000,000
Equity Distribution Agreements, Value of Units Available to be Issued																																			$ 1,500,000,000
Stock Issued During Period, Value, Dividend Reinvestment Plan																														216,000,000	360,000,000	$ 155,000,000
ETP [Member] | Sunoco, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest						68.42%
ETP [Member] | Legacy Sunoco, Inc. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest						100.00%
Parent Company [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit												$ 0.2850	[1]	0.2850	[1]	0.2850	[1]	0.2850	[1]	$ 0.2850	0.2850	0.2650	0.2450	0.2250	0.2075	0.1900	0.1794	0.1731
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016)												$ 180,000,000								$ 0									$ 180,000,000	180,000,000	0		$ 180,000,000
Sunoco Logistics [Member]
Proposed Environmental Penalty												$ 100,000																	100,000	$ 100,000			$ 100,000				$ 1,400,000
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	0.3825	$ 0.3650	$ 0.3475	$ 0.3312
Common Units Issued Inconnection With The Equity Distribution Agreement																														29,100,000
Proceeds from Issuance of Common Stock									$ 629,000,000																				$ 644,000,000		362,000,000
Fees and Commissions																														$ 8,000,000
Equity Distribution Agreement, maximum aggregate value of common units sold																														2,250,000,000	$ 1,250,000,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement																														$ 744,000,000
Partners' Capital Account, Units, Sale of Units									15,500,000																				24,200,000		7,700,000
Sunoco LP [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit												$ 0.8255		$ 0.8255		$ 0.8255		$ 0.8173		$ 0.8013	$ 0.7454	$ 0.6934	$ 0.6450	$ 0.6000	$ 0.5457
Common Units Issued Inconnection With The Equity Distribution Agreement																														2,800,000
Equity Distribution Agreement, maximum aggregate value of common units sold				$ 400,000,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement																														$ 71,000,000
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan												328,000,000																	328,000,000	328,000,000			328,000,000
Partners' Capital Account, Units, Sale of Units								5,500,000																								9,100,000
Partners' Capital Account, Sale of Units								$ 213,000,000																								$ 405,000,000
Partners' Capital Account, Units, Sold in Private Placement						2,300,000
Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest							40.00%
Bakken Holdings Company LLC [Member] | Bakken Pipeline Investments LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired																																		49.00%
Bakken Holdings Company LLC [Member] | Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					40.00%
Bakken Holdings Company LLC [Member] | ETP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					60.00%
Class D Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted																														3,080,000
Limited Partners' Capital Account, Units Outstanding												0								2,156,000									0	0	2,156,000		0
Class F Units [Member] | Sunoco [Member]
Partners' Capital Account, Units												40,000,000																	40,000,000	40,000,000			40,000,000
Class H Units [Member]
Partners' Capital Account, Units									50,200,000														50,200,000
Allocation of Profits, Losses and Other by Sunoco, Percent												90.05%																	90.05%	90.05%			90.05%
Class K Units [Member]
Distribution Made to Limited Partner, Distributions Declared, Per Unit												$ 0.67275
Common Stock Held by Subsidiary												$ 101,525,429																	$ 101,525,429	$ 101,525,429			$ 101,525,429
Common Class C [Member] | Sunoco LP [Member]
Partners' Capital Account, Units, Sale of Units																		16,400,000
Common Class C [Member] | Sunoco LP [Member] | Aloha Petroleum LP [Member]
Partners' Capital Account, Units, Sale of Units																		5,200,000
Common Class C [Member] | Sunoco LP [Member] | Indirect wholly-owned subsidiary [Member]
Partners' Capital Account, Units, Sale of Units																		11,200,000
Holdco Transaction [Member] | Class G Units [Member]
Partners' Capital Account, Units																																						90,700,000
PVR Acquisition [Member] | Regency [Member]
Business Combination, Consideration Transferred											$ 5,700,000,000
Payments to Acquire Businesses, Gross											$ 36,000,000
Eagle Rock Midstream Acquisition [Member] | Regency [Member]
Stock Issued During Period, Shares, Acquisitions																														8,200,000
Proceeds from Issuance of Common Stock																														$ 400,000,000
Business Combination, Consideration Transferred																														1,300,000,000
Susser Merger [Member]
Business Combination, Consideration Transferred										$ 875,000,000
Payments to Acquire Businesses, Gross										$ 1,800,000,000
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%
Bakken Pipeline Transaction [Member] | Class H Units [Member]
Allocation of Profits, Losses and Other by Sunoco, Percent									90.05%														90.05%
Partners' Capital Account, Units, Redeemed									30,800,000
Bakken Pipeline Transaction [Member] | Class I Units [Member]
Partners' Capital Account, Units									100														100
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross					$ 2,000,000,000
Sunoco Retail to Sunoco LP [Member]
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						5,700,000
Permian Express 2 [Member] | Sunoco Logistics [Member]
Proposed Environmental Penalty												$ 100,000																	$ 100,000	$ 100,000			$ 100,000
Additional Units [Member] | Class D Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted																														80,000
March 2015 [Member]
Vesting Schedule, Percent of Class D Units Vesting												30.00%																	30.00%	30.00%			30.00%
March 2018 [Member]
Vesting Schedule, Percent of Class D Units Vesting												35.00%																	35.00%	35.00%			35.00%
March 2020 [Member]
Vesting Schedule, Percent of Class D Units Vesting												35.00%																	35.00%	35.00%			35.00%
Equity Distribution Agreement [Member] | ETP [Member]
Fees and Commissions																														$ 8,000,000
Sunoco Logistics Crude Oil Pipeline [Member] | Sunoco Logistics [Member]
Proposed Environmental Penalty												$ 100,000																	$ 100,000	100,000			$ 100,000
Wortham, Texas Crude Oil Pipeline [Member] | Sunoco Logistics [Member]
Proposed Environmental Penalty												$ 100,000																	100,000	100,000			100,000
Series A Convertible Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit												$ 0.285
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016)												$ 180,000,000																	$ 180,000,000	$ 180,000,000			$ 180,000,000
Stock Issued During Period, Shares, New Issues						329,300,000																								329,295,770	0	0
Distribution Made to Limited Partner, Distributions Declared, Per Unit												$ 0.11
Convertible Unit Distribution to ETE Common Units Distribution, Percent												40.00%																	40.00%	40.00%			40.00%
Conversion Price of Preferred Units												$ 6.56																	$ 6.56	$ 6.56			$ 6.56
Series A Convertible Preferred Units [Member] | Mr. McReynolds [Member]
Stock Issued During Period, Shares, New Issues																														21,382,155
Series A Convertible Preferred Units [Member] | Mr. Ramsey [Member]
Stock Issued During Period, Shares, New Issues																														51,317
Series A Convertible Preferred Units [Member] | Mr. McCrea [Member]
Stock Issued During Period, Shares, New Issues																														1,112,728
Series A Convertible Preferred Units [Member] | Mr. Ray Davis [Member]
Stock Issued During Period, Shares, New Issues																														72,042,486
Class E Units [Member] | ETP [Member]
Limited Partners' Capital Account, Units Outstanding												8,900,000																	8,900,000	8,900,000			8,900,000
Class D Units [Member]
Stock Issued During Period, Shares, New Issues																														0	924,000	0
Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member] | Sunoco Logistics [Member]
Line of Credit Facility, Current Borrowing Capacity												$ 2,500,000,000																	$ 2,500,000,000	$ 2,500,000,000			$ 2,500,000,000
Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member] | Sunoco LP [Member]
Line of Credit Facility, Current Borrowing Capacity												$ 1,500,000,000																	$ 1,500,000,000	$ 1,500,000,000			$ 1,500,000,000
Subsequent Event [Member]
Partners' Capital Account, Units, Sold in Private Placement			32,200,000
Proceeds from Issuance of Private Placement			$ 580,000,000
Subsequent Event [Member] | Phillips 66 Company [Member] | Dakota Access and ETCOC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		25.00%
Subsequent Event [Member] | Phillips 66 Company [Member] | Bakken Pipeline [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		25.00%
Subsequent Event [Member] | ETP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	3.30%
Partners' Capital Account, Units, Sold in Private Placement			23,700,000
Proceeds from Issuance of Private Placement			$ 568,000,000
Subsequent Event [Member] | Sunoco LP [Member]
Common Units Issued Inconnection With The Equity Distribution Agreement		400,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement		$ 10,000,000
Subsequent Event [Member] | Bakken Pipeline Investments LLC [Member] | Dakota Access and ETCOC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		75.00%
Subsequent Event [Member] | ETP and Sunoco Logistics [Member] | Bakken Pipeline [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		38.25%
Subsequent Event [Member] | MarEn Bakken Company [Member] | Bakken Pipeline [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		36.75%
Minimum [Member] | PennTex [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit																														$ 0.2750
[1]	(1) Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to

Equity (Change In ETE Common Un

Equity (Change In ETE Common Units) (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
		Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Preferred Units, Outstanding						329,299,267	0
Stock Issued During Period, Shares, New Issues			2,100,000	0	0
Unamortized financing costs(1)	[1]					$ 13	$ 29
Outstanding			1,046,947,157	1,044,767,336	1,077,500,000	1,046,947,157	1,044,767,336	1,077,500,000	1,119,800,000
Issuance of restricted Common Units under long-term incentive plans			0	(33,600,000)	(42,300,000)
Number of Common Units, end of period			1,046,947,157	1,044,767,336	1,077,500,000
Series A Convertible Preferred Units [Member]
Preferred Units, Outstanding						329,300,000	0	0	0
Stock Issued During Period, Shares, New Issues		329,300,000	329,295,770	0	0
Class D Units [Member]
Stock Issued During Period, Shares, New Issues			0	924,000	0
[1]	(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.

Equity (Quarterly Distributions

Equity (Quarterly Distributions Of Available Cash) (Details) - USD ($) $ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

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

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Partners' Capital Account, Distributions

$ 1,022

$ 1,090

$ 821

PennTex [Member]

Distribution Made to Limited Partner, Date of Record

Feb. 7, 2017

Nov. 7, 2016

Distribution Made to Limited Partner, Distribution Date

Feb. 14, 2017

Nov. 14, 2016

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.2950

$ 0.2950

Sunoco LP [Member]

Distribution Made to Limited Partner, Date of Record

Feb. 13, 2017

Nov. 7, 2016

Aug. 5, 2016

May 6, 2016

Feb. 5, 2016

Nov. 17, 2015

Aug. 18, 2015

May 19, 2015

Feb. 17, 2015

Nov. 18, 2014

Distribution Made to Limited Partner, Distribution Date

Feb. 21, 2017

Nov. 15, 2016

Aug. 15, 2016

May 16, 2016

Feb. 16, 2016

Nov. 27, 2015

Aug. 28, 2015

May 29, 2015

Feb. 27, 2015

Nov. 28, 2014

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.8255

$ 0.8255

$ 0.8255

$ 0.8173

$ 0.8013

$ 0.7454

$ 0.6934

$ 0.6450

$ 0.6000

$ 0.5457

Sunoco Logistics [Member]

Distribution Made to Limited Partner, Date of Record

Feb. 7, 2017

Nov. 9, 2016

Aug. 8, 2016

May 9, 2016

Feb. 8, 2016

Nov. 9, 2015

Aug. 10, 2015

May 11, 2015

Feb. 9, 2015

Nov. 7, 2014

Aug. 8, 2014

May 9, 2014

Feb. 10, 2014

Distribution Made to Limited Partner, Distribution Date

Feb. 14, 2017

Nov. 14, 2016

Aug. 12, 2016

May 13, 2016

Feb. 12, 2016

Nov. 13, 2015

Aug. 14, 2015

May 15, 2015

Feb. 13, 2015

Nov. 14, 2014

Aug. 14, 2014

May 15, 2014

Feb. 14, 2014

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

$ 0.3825

$ 0.3650

$ 0.3475

$ 0.3312

Parent Company [Member]

Distribution Made to Limited Partner, Date of Record

Feb. 7, 2017

[1]

Nov. 7, 2016

[1]

Aug. 8, 2016

[1]

May 6, 2016

[1]

Feb. 4, 2016

Nov. 5, 2015

Aug. 6, 2015

May 8, 2015

Feb. 6, 2015

Nov. 3, 2014

Aug. 4, 2014

May 5, 2014

Feb. 7, 2014

Distribution Made to Limited Partner, Distribution Date

Feb. 21, 2017

[1]

Nov. 18, 2016

[1]

Aug. 19, 2016

[1]

May 19, 2016

[1]

Feb. 19, 2016

Nov. 19, 2015

Aug. 19, 2015

May 19, 2015

Feb. 19, 2015

Nov. 19, 2014

Aug. 19, 2014

May 19, 2014

Feb. 19, 2014

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.2850

[1]

$ 0.2850

[1]

$ 0.2850

[1]

$ 0.2850

[1]

$ 0.2850

$ 0.2850

$ 0.2650

$ 0.2450

$ 0.2250

$ 0.2075

$ 0.1900

$ 0.1794

$ 0.1731

ETP [Member]

Distribution Made to Limited Partner, Date of Record

Feb. 7, 2017

Nov. 7, 2016

Aug. 8, 2016

May 6, 2016

Feb. 8, 2016

Nov. 5, 2015

Aug. 6, 2015

May 8, 2015

Feb. 6, 2015

Nov. 3, 2014

Aug. 4, 2014

May 5, 2014

Feb. 7, 2014

Distribution Made to Limited Partner, Distribution Date

Feb. 14, 2017

Nov. 14, 2016

Aug. 15, 2016

May 16, 2016

Feb. 16, 2016

Nov. 16, 2015

Aug. 14, 2015

May 15, 2015

Feb. 13, 2015

Nov. 14, 2014

Aug. 14, 2014

May 15, 2014

Feb. 14, 2014

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

$ 0.6500

$ 0.6367

$ 0.6233

$ 0.6133

Series A Convertible Preferred Units [Member] | Parent Company [Member]

Distribution Made to Limited Partner, Date of Record

Feb. 7, 2017

Nov. 7, 2016

Aug. 8, 2016

May 6, 2016

Distribution Made to Limited Partner, Distribution Date

Feb. 21, 2017

Nov. 18, 2016

Aug. 19, 2016

May 19, 2016

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.1100

$ 0.1100

$ 0.1100

$ 0.1100

[1]

(1) Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to

Equity (Accumulated Other Compr

Equity (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Partners' Capital Notes [Abstract]
Unrealized gains on available-for-sale securities	$ 2	$ 0
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Gain (Loss) Arising During Period, Net of Tax	(5)	(4)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	7	8
AOCI attributable to equity method investments	4	0
Subtotal	8	4
Amounts attributable to noncontrolling interest	(8)	(4)
Total AOCI included in partners' capital, net of tax	$ 0	$ 0

Equity Tax amounts in component

Equity Tax amounts in components of other comprehensive income (loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Other Comprehensive Income Loss Commodity Hedges Tax	$ (2)	$ (2)
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax	3	4
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized (Gain) Loss Arising During Period, Tax	0	7
Other Comprehensive Income (Loss), Tax	$ 1	$ 9

Equity (Relinquishments of Ince

Equity (Relinquishments of Incentive Distribution Rights) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Subsequent Event [Member] | Currently Effective IDRs [Member]
Relinquishment of Incentive Distributions	$ 33	$ 128	$ 138	$ 626

ETE Unit-Based Compensation Pla

ETE Unit-Based Compensation Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock Issued During Period, Shares, New Issues	2,100,000	0	0
ETE Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	12,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	8,271,767
Unvested awards	43,740
Units Vested In Period	28,648	26,244
Fair Value Of Units As Of The Vesting Date	$ 0.2	$ 0.8
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 1
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	3 years 18 days
Employee [Member] | ETE Long-Term Incentive Plan [Member]
Awards granted	0
Director [Member] | ETE Long-Term Incentive Plan [Member]
Awards granted	23,821
March 2015 [Member]
Vesting Schedule, Percent of Class D Units Vesting	30.00%
March 2018 [Member]
Vesting Schedule, Percent of Class D Units Vesting	35.00%
March 2020 [Member]
Vesting Schedule, Percent of Class D Units Vesting	35.00%

Unit-Based Compensation Plans S

Unit-Based Compensation Plans Subsidiary Unit-Based Compensation Plans (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Subsidiary Unit Based Compensation [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair Value Of Units As Of The Vesting Date	$ 40	$ 57	$ 56
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 275
ETP Unit-Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	9.5	7.2
Weighted Average Grant-Date Fair Value Per ETP Unit	$ 27.69	$ 31.74
Awards granted	3.8
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards granted	$ 23.82
Awards vested	(1.2)
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards vested	$ 35.48
Stock Granted, Value, Share-based Compensation, Forfeited	$ (0.3)
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards forfeited	$ 32.26
Sunoco Logistics Unit-Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	3 years
Sunoco LP Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	2	1.1
Weighted Average Grant-Date Fair Value Per ETP Unit	$ 34.43	$ 41.19
Awards granted	1
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards granted	$ 26.95	$ 40.63	$ 45.50
Awards vested	0
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards vested	$ 36.98
Stock Granted, Value, Share-based Compensation, Forfeited	$ (0.1)
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards forfeited	$ 39.77
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	4 years 3 months

Income Taxes Narrative (Details

Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	$ 292
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	127
Deferred Tax Liabilities, Gross	5,710	$ 4,945
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	596
Net operating losses and alternative minimum tax credit	472	217
Valuation allowance	(118)	(121)
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, Ater Tax	554
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	$ 1
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Other Information	0.6
Proceeds from Income Tax Refunds	$ 530
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	530
State	(34)	$ (54)	$ 78
Unrecognized Tax Benefits, Interest on Income Taxes Expense	1
Income Tax Examination, Penalties and Interest Accrued	6
Pennsylvania Constitution [Member]
Operating Loss Carryforwards [Line Items]
State	46
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	9
Net of federal tax [Member] | Pennsylvania Constitution [Member]
Operating Loss Carryforwards [Line Items]
State	30
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	$ 6
Maximum [Member] | ETP Holdco and other corporate subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2035
Minimum [Member] | Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Jan. 1, 2017

Income Taxes Components of Inco

Income Taxes Components of Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current expense (benefit):
Federal	$ 11	$ (315)	$ 251
State	(34)	(54)	78
Total	(23)	(369)	329
Deferred expense (benefit):
Federal	(237)	253	(29)
State	12	(32)	25
Total	(225)	221	(4)
Total income tax expense (benefit) from continuing operations	$ (248)	$ (148)	$ 325

Income Taxes Reconciliation of

Income Taxes Reconciliation of Income Tax Satutory Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income tax expense (benefit) at U.S. statutory rate of 35 percent	$ 95	$ 302	$ 462
Increase (reduction) in income taxes resulting from:
Nondeductible goodwill included in the Lake Charles LNG transaction	0	0	105
Goodwill impairment	278	0	0
Partnership earnings not subject to tax	(590)	(366)	(284)
State tax, net of federal tax benefit	(10)	(35)	52
Dividend received deduction	(15)	(22)	0
Premium on debt retirement	0	0	(10)
Audit settlement	0	(7)	0
Foreign taxes	0	0	(8)
Other	(6)	(20)	8
Total income tax expense (benefit) from continuing operations	$ (248)	$ (148)	$ 325

Income Taxes Effects of Tempora

Income Taxes Effects of Temporary Differences That Comprise Net Deffered Income Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Deferred income tax assets:
Net operating losses and alternative minimum tax credit	$ 472	$ 217
Pension and other postretirement benefits	30	36
Long term debt	32	61
Other	182	162
Deferred Tax Assets, Gross	716	476
Valuation allowance	(118)	(121)
Net deferred income tax assets	598	355
Deferred income tax liabilities:
Properties, plants and equipment	(1,633)	(1,633)
Investments in unconsolidated affiliates	(3,789)	(2,976)
Trademarks	(273)	(286)
Other	(15)	(50)
Deferred Tax Liabilities, Gross	5,710	4,945
Deferred Tax Liabilities	$ (5,112)	$ (4,590)	$ (4,410)

Income Taxes Components of Net

Income Taxes Components of Net Deferred Tax Liability (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Components of Net Deferred Income Tax [Abstract]
Deferred Tax Liabilities, Net	$ (5,112)	$ (4,590)	$ (4,410)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)	460	0
Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3)	243	0
Tax provision, including provision from discontinued operations	201	242
Other	$ (20)	$ 62

Income Taxes Changes in Unrecog

Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes in Unrecognized Tax Benefits [Abstract]
Balance at beginning of year	$ 610	$ 440	$ 429
Additions attributable to tax positions taken in the current year	8	178	20
Additions attributable to tax positions taken in prior years	18	0	0
Reduction attributable to tax positions taken in prior years	(20)	0	(1)
Settlements	0	0	5
Lapse of statute	1	8	3
Balance at end of year	$ 615	$ 610	$ 440

Regulatory Matters, Commitmen89

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details)	1 Months Ended			12 Months Ended
	Feb. 28, 2017USD ($)	Oct. 31, 2015USD ($)	Apr. 30, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Feb. 01, 2017USD ($)	Apr. 30, 2016USD ($)	Jan. 31, 2012USD ($)
Payments for Environmental Liabilities				$ 43,000,000	$ 38,000,000
Lease Expiration Date				Dec. 31, 2034
Operating leases rent expense				$ 129,000,000	205,000,000	$ 98,000,000
Total environmental liabilities				385,000,000	368,000,000
Operating Leases, Rent Expense, Contingent Rentals				$ 23,000,000	26,000,000	$ 24,000,000
Site Contingency, Number of Sites Needing Remediation				50
Proposed Environmental Penalty				$ 0
Payments to Acquire Businesses, Gross		$ 382,000,000
Long-term Debt				43,802,000,000	36,968,000,000
AmeriGas [Member]
Contingent Residual Support Agreement Obligation									$ 1,550,000,000
Sunoco LP [Member]
Long-term Debt				4,514,000,000	1,958,000,000
Related To Deductibles [Member]
Accrual for loss contingency				$ 93,000,000	40,000,000
MTBE Sites [Member]
Site Contingency, Number of Sites Needing Remediation				19
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount				$ 319,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount				595,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount				1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount				536,000,000
New Mexico Environmental Department [Member]
Total environmental liabilities				250,000
Civil penalties				465,000
Texas Commission on Environmental Quality [Member]
Total environmental liabilities				50,000
Supplemental Environmental Project [Member]
Proposed Environmental Penalty				$ 21,000
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, Stated Percentage				6.375%
Senior Notes				$ 800,000,000	800,000,000
6.25% Senior Notes due 2021 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage				6.25%				6.25%
Senior Notes				$ 800,000,000	$ 0			$ 800,000,000
Term loan due 2019 [Member] | Sunoco LP [Member]
Long-term Debt				$ 2,035,000,000
Subsequent Event [Member] | AmeriGas [Member]
Debt Instrument, Interest Rate, Stated Percentage							7.00%
Contingent Residual Support Agreement Obligation							$ 122,000,000
Repayments of Senior Debt	$ 378,000,000

Derivative Assets And Liabili90

Derivative Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details)		12 Months Ended
		Dec. 31, 2016barrelsMMbtuMegawattbushels	Dec. 31, 2015barrelsMMbtuMegawattbushels
Maximum [Member]
Term Of Commodity Derivatives
Minimum [Member]
Term Of Commodity Derivatives
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member]
Derivative, Nonmonetary Notional Amount		(5,662,500)
Term Of Commodity Derivatives		2,017
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount		(52,652,500)	(14,380,000)
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,018	2,018
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,017	2,016
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount			(6,522,500)
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member]
Derivative, Nonmonetary Notional Amount		(22,492,489)
Term Of Commodity Derivatives		2,017
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount		(682,500)	(602,500)
Term Of Commodity Derivatives		2,017
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Maximum [Member]
Term Of Commodity Derivatives			2,017
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Minimum [Member]
Term Of Commodity Derivatives			2,016
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount	[1]		(31,240,000)
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member] | Maximum [Member]
Term Of Commodity Derivatives			2,017
Short [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member] | Minimum [Member]
Term Of Commodity Derivatives			2,016
Short [Member] | Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount		(36,370,000)	(37,555,000)
Term Of Commodity Derivatives		2,017	2,016
Short [Member] | Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount		(36,370,000)	(37,555,000)
Term Of Commodity Derivatives		2,017	2,016
Short [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | Megawatt			(109,791)
Term Of Commodity Derivatives			2,016
Short [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member]
Derivative, Nonmonetary Notional Amount | Megawatt		(50,400)
Term Of Commodity Derivatives		2,017
Short [Member] | WTI Crude Oil [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | barrels		(617,000)	(591,000)
Term Of Commodity Derivatives		2,017
Short [Member] | WTI Crude Oil [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Maximum [Member]
Term Of Commodity Derivatives			2,017
Short [Member] | WTI Crude Oil [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Minimum [Member]
Term Of Commodity Derivatives			2,016
Short [Member] | Natural Gas Liquids [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member]
Derivative, Nonmonetary Notional Amount | barrels		(5,786,627)	(8,146,800)
Term Of Commodity Derivatives		2,017
Short [Member] | Natural Gas Liquids [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member] | Maximum [Member]
Term Of Commodity Derivatives			2,018
Short [Member] | Natural Gas Liquids [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member] | Minimum [Member]
Term Of Commodity Derivatives			2,016
Short [Member] | Refined Products [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | barrels		(3,144,000)	(1,289,000)
Term Of Commodity Derivatives		2,017
Short [Member] | Refined Products [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Maximum [Member]
Term Of Commodity Derivatives			2,017
Short [Member] | Refined Products [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Minimum [Member]
Term Of Commodity Derivatives			2,016
Long [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member]
Derivative, Nonmonetary Notional Amount			(71,340,000)
Long [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Maximum [Member]
Term Of Commodity Derivatives			2,017
Long [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Minimum [Member]
Term Of Commodity Derivatives			2,016
Long [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount		(10,750,000)
Long [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,018	2,017
Long [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,017	2,016
Long [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member]
Derivative, Nonmonetary Notional Amount			(21,922,484)
Long [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Maximum [Member]
Term Of Commodity Derivatives			2,017
Long [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Minimum [Member]
Term Of Commodity Derivatives			2,016
Long [Member] | Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount	[1]	(2,242,500)
Term Of Commodity Derivatives		2,017
Long [Member] | Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member]
Derivative, Nonmonetary Notional Amount		(36,370,000)	(37,555,000)
Term Of Commodity Derivatives		2,017	2,016
Long [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount | Megawatt		(186,400)	(1,300,647)
Term Of Commodity Derivatives		2,017	2,016
Long [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | Megawatt		(109,564)
Long [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,018
Long [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,017
Long [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member]
Derivative, Nonmonetary Notional Amount | Megawatt			(260,534)
Term Of Commodity Derivatives			2,016
Long [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forwards Swaps [Member]
Derivative, Nonmonetary Notional Amount | Megawatt		(391,880)	(357,092)
Long [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forwards Swaps [Member] | Maximum [Member]
Term Of Commodity Derivatives		2,018	2,017
Long [Member] | Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forwards Swaps [Member] | Minimum [Member]
Term Of Commodity Derivatives		2,017	2,016
Long [Member] | Corn [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | bushels		(1,580,000)	(1,185,000)
Term Of Commodity Derivatives		2,017	2,016
[1]	(1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Regulatory Matters, Commitmen91

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Schedule of Future Minimum Rental Payments for Operating Leases) (Details) $ in Millions	Dec. 31, 2016USD ($)
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
2,017	$ 82
2,018	67
2,019	55
2,020	52
2,021	53
Thereafter	219
Total Future Rent Payments	528
Future Rental Income	(79)
Net Future Rental Payments	$ 449

Derivative Assets And Liabili92

Derivative Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) - Interest Rate Derivatives [Member] - ETP [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
December 2018 [Member]
Notional Amount		$ 1,200	$ 1,200
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%
March 2019 [Member]
Notional Amount		$ 300	300
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
Forward-Starting Swaps [Member] | July 2016 [Member]
Notional Amount	[2]	$ 0	200
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
Forward-Starting Swaps [Member] | July 2017 [Member]
Notional Amount	[3]	$ 500	300
Type	[1],[3]	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate
Forward-Starting Swaps [Member] | July 2018 [Member]
Notional Amount	[3]	$ 200	200
Type	[1],[3]	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate
Forward-Starting Swaps [Member] | July 2019 [Member]
Notional Amount	[3]	$ 200	$ 200
Type	[1],[3]	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate
[1]	(1) Floating rates are based on 3-month LIBOR.
[2]	(2) Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.
[3]	(3) Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

Regulatory Matters, Commitmen93

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Environmental Remediation Obligations [Abstract]
Current	$ 37	$ 42
Non-current	348	326
Total environmental liabilities	$ 385	$ 368

Derivative Assets And Liabili94

Derivative Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Asset Derivatives	$ 363	$ 454
Liability Derivatives	(672)	(532)
Designated as Hedging Instrument [Member]
Asset Derivatives	0	38
Liability Derivatives	(4)	(3)
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Asset Derivatives	0	38
Liability Derivatives	(4)	(3)
Not Designated as Hedging Instrument [Member]
Asset Derivatives	363	416
Liability Derivatives	(668)	(529)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Asset Derivatives	338	353
Liability Derivatives	(416)	(306)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Asset Derivatives	25	63
Liability Derivatives	(58)	(47)
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Asset Derivatives	0	0
Liability Derivatives	(193)	(171)
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]
Asset Derivatives	0	0
Liability Derivatives	(1)	(5)
Broker cleared derivative contracts [Member]
Asset Derivatives	338	391
Liability Derivatives	$ (420)	$ (309)

Regulatory Matters, Commitmen95

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingincies and Enviironmental (Schedule of Rental Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Rent Expense, Contingent Rentals	$ 23	$ 26	$ 24
Rental expense(1)	129	205	98
Less: Sublease rental income	(30)	(16)	(26)
Rental expense, net	$ 99	$ 189	$ 72

Derivative Assets And Liabili96

Derivative Assets And Liabilities Derivative Assets and Lianilities (Offsetting Agreements Netting Table) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Asset Derivatives	$ 363	$ 454
Derivative Liability, Fair Value, Gross Liability	(672)	(532)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(4)	(17)
Derivative Liability, Fair Value, Amount Offset Against Collateral	4	17
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(338)	(309)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	338	309
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	21	128
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(330)	(206)
Without offsetting agreements [Member]
Asset Derivatives	0	0
Derivative Liability, Fair Value, Gross Liability	(194)	(176)
OTC Contracts [Member]
Asset Derivatives	25	63
Derivative Liability, Fair Value, Gross Liability	(58)	(47)
Broker cleared derivative contracts [Member]
Asset Derivatives	338	391
Derivative Liability, Fair Value, Gross Liability	$ (420)	$ (309)

Derivative Assets And Liabili97

Derivative Assets And Liabilities (Derivative Amount Of Gain (Loss) Recognized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	$ 0	$ 0	$ (3)
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	14	21	(8)
Amount of Gain/(Loss) Recognized in Income on Derivatives	(220)	(2)	39
Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	0	0	(3)
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	14	21	(8)
Interest Rate Derivatives [Member] | Losses On Non-Hedged Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(12)	(18)	(157)
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	4	12	3
Non Trading [Member] | Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(177)	15	199
Trading [Member] | Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (35)	$ (11)	$ (6)

Retirement Benefits (Narrative)

Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
ETP [Member]
Retirement Benefits [Line Items]
Defined Contribution Plan, Cost Recognized	$ 44	$ 40	$ 50
Sunoco [Member]
Retirement Benefits [Line Items]
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent	$ 200
Pension Benefits
Retirement Benefits [Line Items]
Large Cap US Equitiies	100.00%	100.00%
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 12
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 26
Other Postretirement Benefits
Retirement Benefits [Line Items]
Large Cap US Equitiies	31.00%	56.00%
Fixed Income Securities	66.00%	33.00%
Cash Fund Investments	3.00%	11.00%
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 10
Other Postretirement Benefits | Equity [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	25.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	35.00%
Other Postretirement Benefits | Fixed Income Investments [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum	65.00%
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum	75.00%
Other Postretirement Benefits | Cash [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum	10.00%

Retirement Benefits (Obligation

Retirement Benefits (Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Change in benefit obligation:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	$ 0	$ 0
Change in plan assets:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0
Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Interest Cost	3	25
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	15
Defined Benefit Plan, Fair Value of Plan Assets	12	15
Other Postretirement Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	181	203
Defined Benefit Plan, Interest Cost	4	4
Defined Benefit Plan, Plan Amendments	0	0
Defined Benefit Plan, Benefits Paid	(21)	(20)
Defined Benefit Plan, Actuarial Gain (Loss)	2	(6)
Defined Benefit Plan, Benefit Obligation	166	181
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	261	272
Defined Benefit Plan, Actual Return on Plan Assets	6	0
Defined Benefit Plan, Contributions by Employer	10	9
Defined Benefit Plan, Benefits Paid	(21)	(20)
Defined Benefit Plan, Fair Value of Plan Assets	256	261
Defined Benefit Plan, Funded Status of Plan	(90)	(80)
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	114	103
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	(2)	(2)
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	(23)	(22)
Defined Benefit Plan, Amounts Recognized in Balance Sheet	89	79
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Actuarial Gain (Loss), before Tax	(13)	(18)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	15	16
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	2	(2)
Funded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0
Change in plan assets:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0
Funded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	20	718
Defined Benefit Plan, Interest Cost	1	23
Defined Benefit Plan, Plan Amendments	0	0
Defined Benefit Plan, Benefits Paid	(1)	(46)
Defined Benefit Plan, Actuarial Gain (Loss)	(2)	16
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements		(691)
Defined Benefit Plan, Benefit Obligation	18	20
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	15	598
Defined Benefit Plan, Actual Return on Plan Assets	(2)	16
Defined Benefit Plan, Contributions by Employer	0	138
Defined Benefit Plan, Benefits Paid	(1)	(46)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements		(691)
Defined Benefit Plan, Fair Value of Plan Assets	12	15
Defined Benefit Plan, Funded Status of Plan	6	5
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	0	0
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	0	0
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	(6)	(5)
Defined Benefit Plan, Amounts Recognized in Balance Sheet	(6)	(5)
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Actuarial Gain (Loss), before Tax	0	2
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	0	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	0	2
Unfunded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0
Change in plan assets:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0
Unfunded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	57	65
Defined Benefit Plan, Interest Cost	2	2
Defined Benefit Plan, Plan Amendments	0	0
Defined Benefit Plan, Benefits Paid	(7)	(8)
Defined Benefit Plan, Actuarial Gain (Loss)	(1)	(2)
Defined Benefit Plan, Benefit Obligation	51	57
Change in plan assets:
Defined Benefit Plan, Benefits Paid	(7)	(8)
Defined Benefit Plan, Funded Status of Plan	51	57
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent	0	0
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	(7)	(9)
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	(44)	(48)
Defined Benefit Plan, Amounts Recognized in Balance Sheet	(51)	(57)
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Actuarial Gain (Loss), before Tax	0	4
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, before Tax	0	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	0	4
Change in Plan Assets [Member] | Unfunded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0
Change in plan assets:
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0
Change in Plan Assets [Member] | Unfunded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefits Paid	0	0
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Actual Return on Plan Assets	0	0
Defined Benefit Plan, Contributions by Employer	0	0
Defined Benefit Plan, Benefits Paid	0	0
Defined Benefit Plan, Fair Value of Plan Assets	$ 0	$ 0

Retirement Benefits (Accumulate

Retirement Benefits (Accumulated Benefit Obligation In Excess of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	$ 166	$ 181
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	256	261
Funded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation	18	20
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	18	20
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	12	15
Unfunded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation	51	57
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	51	57
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	$ 0	$ 0

Retirement Benefits (Net Period

Retirement Benefits (Net Periodic Benefit Costs Schedule) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost	$ 3	$ 25
Defined Benefit Plan, Expected Return on Plan Assets	(1)	(16)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0
Defined Benefit Plan, Amortization of Gains (Losses)	0	0
Net Periodic Benefit Costs, Settlements	0	32
Defined Benefit Plan, Net Periodic Benefit Cost	2	41
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost	4	4
Defined Benefit Plan, Expected Return on Plan Assets	(8)	(8)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	1	1
Defined Benefit Plan, Amortization of Gains (Losses)	0	0
Net Periodic Benefit Costs, Settlements	0	0
Defined Benefit Plan, Net Periodic Benefit Cost	$ (3)	$ (3)

Retirement Benefits (Benefit As

Retirement Benefits (Benefit Assumptions) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year	6.73%	7.16%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	4.96%	5.39%
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2,021	2,018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.65%	3.59%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.60%	3.65%
Expected long term return on assets, tax exempt accounts	3.50%	7.50%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.34%	2.38%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.06%	2.79%
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 256	$ 261	$ 272
Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12	15
Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	23	18
Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	142	141
Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12	15
Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	91	102
Level 1 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	165	159
Level 1 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12	0
Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	23	18
Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	142	141
Level 1 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12	0
Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	91	102
Level 2 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	15
Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	15
Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	91	102
Level 3 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 0	$ 0

Retirement Benefits (Benefit Pa

Retirement Benefits (Benefit Payments) (Details) $ in Millions	Dec. 31, 2016USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2,017	$ 12
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member]
Defined Benefit Plan Disclosure [Line Items]
2,017	26
2,018	25
2,019	23
2,020	22
2,021	19
2022-2026	39
Funded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2,017	1
2,018	1
2,019	1
2,020	1
2,021	1
2022-2026	6
Unfunded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2,017	7
2,018	7
2,019	6
2,020	6
2,021	5
2022-2026	$ 17

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenue	$ 221	$ 290	$ 965

Reportable Segments (Operating

Reportable Segments (Operating Segments) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues	$ 8,899	$ 7,705	$ 7,415	$ 6,083	$ 7,744	$ 8,473	$ 9,423	$ 8,564	$ 30,102	$ 34,204	$ 52,639
Cost of products sold									22,636	27,435	45,861
Depreciation, depletion and amortization									2,166	1,904	1,669
Equity in earnings from unconsolidated affiliates									270	276	332
Investment In ETP [Member]
Revenues									21,827	34,292	55,475
Cost of products sold									15,394	27,029	48,414
Depreciation, depletion and amortization									1,986	1,929	1,669
Equity in earnings from unconsolidated affiliates									336	469	332
Investment In Sunoco LP [Member]
Revenues									8,296	10,538	4,291
Cost of products sold									7,459	9,902	4,214
Depreciation, depletion and amortization									126	103	31
Investment in Lake Charles LNG [Member]
Depreciation, depletion and amortization									39	39	39
Corporate and Other [Member]
Depreciation, depletion and amortization									15	17	16
Adjustments and Eliminations [Member]
Revenues									(218)	(10,842)	(7,343)
Cost of products sold									(217)	(9,496)	(6,767)
Depreciation, depletion and amortization									0	(184)	(86)
Equity in earnings from unconsolidated affiliates									(66)	(193)	0
External Customers [Member]
Revenues									8,287	10,527	4,291
External Customers [Member] | Investment In ETP [Member]
Revenues									21,618	34,156	55,475
External Customers [Member] | Investment In Sunoco LP [Member]
Revenues									8,287	10,527	4,291
External Customers [Member] | Investment in Lake Charles LNG [Member]
Revenues									197	216	216
Intersegment [Member] | Investment In ETP [Member]
Revenues									209	136	0
Intersegment [Member] | Investment In Sunoco LP [Member]
Revenues									$ 9	$ 11	$ 0

Reportable Segments (Equity in

Reportable Segments (Equity in earnings of unconsolidated affiliates) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Equity in earnings from unconsolidated affiliates	$ 270	$ 276	$ 332
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Equity in earnings from unconsolidated affiliates	336	469	332
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Equity in earnings from unconsolidated affiliates	$ (66)	$ (193)	$ 0

Reportable Segments Reportable

Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Adjusted EBITDA		$ 6,007	$ 5,935	$ 5,840
Depreciation, depletion and amortization		(2,166)	(1,904)	(1,669)
Interest expense, net of interest capitalized		(1,803)	(1,621)	(1,368)
Gains on acquisitions		(83)	0	0
Gain on sale of AmeriGas common units		0	0	177
Impairment of investment in affiliate		(308)	0	0
Impairment losses		970	339	370
Losses on interest rate derivatives		(12)	(18)	(157)
Non-cash unit-based compensation expense		(70)	(91)	(82)
Losses on interest rate derivatives		(136)	(65)	116
Losses on extinguishments of debt		0	(43)	(25)
Inventory valuation adjustments	$ (120)	267	(229)	(445)
Adjusted EBITDA related to discontinued operations		(293)	(345)	(208)
Adjusted EBITDA related to unconsolidated affiliates		(675)	(713)	(748)
Equity in earnings from unconsolidated affiliates		270	276	332
Other, net		78	21	(74)
Income from continuing operations before income tax expense		272	864	1,319
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA		5,605	5,714	5,710
Depreciation, depletion and amortization		(1,986)	(1,929)	(1,669)
Equity in earnings from unconsolidated affiliates		336	469	332
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA		665	719	332
Depreciation, depletion and amortization		(126)	(103)	(31)
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA		179	196	195
Depreciation, depletion and amortization		(39)	(39)	(39)
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA		(170)	(104)	(97)
Depreciation, depletion and amortization		(15)	(17)	(16)
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA		(272)	(590)	(300)
Depreciation, depletion and amortization		0	184	86
Equity in earnings from unconsolidated affiliates		$ (66)	$ (193)	$ 0

Reportable Segments (Assets Seg

Reportable Segments (Assets Segments)(Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Assets	$ 79,011	$ 71,189	$ 64,279
Investment In ETP [Member]
Assets	70,191	65,173	62,518
Investment In Sunoco LP [Member]
Assets	8,701	8,842	8,773
Investment in Lake Charles LNG [Member]
Assets	1,508	1,369	1,210
Corporate and Other [Member]
Assets	711	638	1,119
Adjustments and Eliminations [Member]
Assets	$ (2,100)	$ (4,833)	$ (9,341)

Reporting Segments (Additions T

Reporting Segments (Additions To Property Plant And Equipment Including Acquisitions Net Of Contributions In Aid Of Construction Costs Segments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	$ 6,249	$ 8,536	$ 5,559
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	5,810	8,167	5,494
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	439	491	154
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	0	1	1
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	$ 0	$ (123)	$ (90)

Reportable Segments (Advances t

Reportable Segments (Advances to and investments in affiliates) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Advances to and investments in unconsolidated affiliates	$ 3,040	$ 3,462	$ 3,659
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Advances to and investments in unconsolidated affiliates	4,280	5,003	3,760
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Advances to and investments in unconsolidated affiliates	$ (1,240)	$ (1,541)	$ (101)

Reportable Segments ETP Revenue

Reportable Segments ETP Revenue (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenue from External Customer [Line Items]
Revenues	$ 8,899	$ 7,705	$ 7,415	$ 6,083	$ 7,744	$ 8,473	$ 9,423	$ 8,564	$ 30,102	$ 34,204	$ 52,639
External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									8,287	10,527	4,291
Investment In ETP [Member]
Revenue from External Customer [Line Items]
Revenues									21,827	34,292	55,475
Investment In ETP [Member] | Intrastate Transportation And Storage [Member]
Revenue from External Customer [Line Items]
Revenues									2,155	1,912	2,645
Investment In ETP [Member] | Interstate Transportation and Storage [Member]
Revenue from External Customer [Line Items]
Revenues									946	1,008	1,057
Investment In ETP [Member] | Midstream [Member]
Revenue from External Customer [Line Items]
Revenues									2,342	2,607	4,770
Investment In ETP [Member] | NGL and refined products transportation and services [Member]
Revenue from External Customer [Line Items]
Revenues									5,973	4,569	4,746
Investment In ETP [Member] | Crude oil transportation and services [Member]
Revenue from External Customer [Line Items]
Revenues									7,539	8,980	16,904
Investment In ETP [Member] | Other Segments [Member]
Revenue from External Customer [Line Items]
Revenues									2,872	15,216	25,353
Investment In ETP [Member] | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									21,618	34,156	55,475
Investment In ETP [Member] | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues									$ 209	$ 136	$ 0

Reportable Segments Regency Rev

Reportable Segments Regency Revenue (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenue from External Customer [Line Items]
Revenues	$ 8,899	$ 7,705	$ 7,415	$ 6,083	$ 7,744	$ 8,473	$ 9,423	$ 8,564	$ 30,102	$ 34,204	$ 52,639
External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									8,287	10,527	4,291
Investment In Sunoco LP [Member]
Revenue from External Customer [Line Items]
Revenues									8,296	10,538	4,291
Investment In Sunoco LP [Member] | Retail [Member]
Revenue from External Customer [Line Items]
Revenues									301	334	43
Investment In Sunoco LP [Member] | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues									8,287	10,527	4,291
Investment In Sunoco LP [Member] | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues									9	11	0
Investment In Sunoco LP [Member] | Wholesale [Member]
Revenue from External Customer [Line Items]
Revenues									$ 7,995	$ 10,204	$ 4,248

Reportable Segments (Lake Charl

Reportable Segments (Lake Charles Revenue) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues	$ 8,899	$ 7,705	$ 7,415	$ 6,083	$ 7,744	$ 8,473	$ 9,423	$ 8,564	$ 30,102	$ 34,204	$ 52,639
External Customers [Member]
Revenues									8,287	10,527	4,291
Investment in Lake Charles LNG [Member] | External Customers [Member]
Revenues									$ 197	$ 216	$ 216

Quarterly Financial Data (Un115

Quarterly Financial Data (Unaudited) (Schedule of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 8,899	$ 7,705	$ 7,415	$ 6,083	$ 7,744	$ 8,473	$ 9,423	$ 8,564	$ 30,102	$ 34,204	$ 52,639
Operating income (loss)	(236)	646	805	695	210	573	878	589	1,910	2,250	2,372
Net income (loss)	(760)	41	424	336	(138)	238	772	221	41	1,093	1,124
Limited Partners’ interest in net income	$ 226	$ 207	$ 239	$ 311	$ 312	$ 291	$ 298	$ 282	$ 983	$ 1,183	$ 629
Basic net income per limited partner unit	$ 0.22	$ 0.20	$ 0.23	$ 0.30	$ 0.30	$ 0.28	$ 0.28	$ 0.26	$ 0.94	$ 1.11	$ 0.58
Diluted net income per limited partner unit	$ 0.21	$ 0.19	$ 0.23	$ 0.30	$ 0.30	$ 0.28	$ 0.28	$ 0.26	$ 0.92	$ 1.11	$ 0.58

Quarterly Financial Data (Un116

Quarterly Financial Data (Unaudited) Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Impairment losses	$ 970	$ 339	$ 370
Impairment of investment in an unconsolidated affiliate	308	$ 0	$ 0
MEP [Member]
Impairment losses	$ 308

Supplemental Financial State117

Supplemental Financial Statement Information (Schedule Of Balance Sheets) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash and cash equivalents	$ 463	$ 581	$ 836	$ 579
Accounts receivable from related companies	47	119
Other current assets	503	593
Total current assets	6,985	5,410
Property, Plant and Equipment, Net	53,253	46,784
Advances to and investments in unconsolidated affiliates	3,040	3,462	3,659
Intangible assets, net	5,489	4,896
Goodwill	5,170	5,485	5,871
OTHER NON-CURRENT ASSETS, net	816	711
Total assets	79,011	71,189	64,279
Accounts Payable, Current	3,502	2,274
Accounts payable to related companies	42	28
Interest payable	545	519
Accrued and other current liabilities	2,367	2,408
Total current liabilities	7,277	4,910
Long-term debt, less current maturities	42,608	36,837
Other non-current liabilities	1,055	1,002
COMMITMENTS AND CONTINGENCIES
General Partner	(3)	(2)
Common Unitholders (1,046,947,157 and 1,044,767,336 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively)	(1,871)	(952)
Class D Units (2,156,000 units authorized, issued and outstanding as of December 31, 2015)	0	22
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016)	180	0
Accumulated other comprehensive loss	0	0
Total partners’ deficit	(1,694)	(932)
Total liabilities and equity	79,011	71,189
Parent Company [Member]
Cash and cash equivalents	2	1	$ 2	$ 8
Accounts receivable from related companies	55	34
Total current assets	57	35
Property, Plant and Equipment, Net	36	20
Advances to and investments in unconsolidated affiliates	5,088	5,764
Intangible assets, net	1	6
Goodwill	9	9
OTHER NON-CURRENT ASSETS, net	10	10
Total assets	5,201	5,844
Accounts Payable, Current	1	0
Accounts payable to related companies	22	111
Interest payable	66	66
Accrued and other current liabilities	3	1
Total current liabilities	92	178
Long-term debt, less current maturities	6,358	6,332
NOTE PAYABLE TO AFFILIATE	443	265
Other non-current liabilities	2	1
COMMITMENTS AND CONTINGENCIES
General Partner	(3)	(2)
Common Unitholders (1,046,947,157 and 1,044,767,336 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively)	(1,871)	(952)
Class D Units (2,156,000 units authorized, issued and outstanding as of December 31, 2015)	0	22
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016)	180	0
Total partners’ deficit	(1,694)	(932)
Total liabilities and equity	$ 5,201	$ 5,844

Supplemental Financial State118

Supplemental Financial Statement Information (Schedule Of Statements Of Operations) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES									$ (693)	$ (548)	$ (556)
Interest expense, net of interest capitalized									(1,803)	(1,621)	(1,368)
Equity in earnings from unconsolidated affiliates									270	276	332
Gains on interest rate derivatives									(12)	(18)	(157)
Losses on extinguishments of debt									0	(43)	(25)
Other, net									132	20	(12)
Income tax expense									(248)	(148)	325
NET INCOME ATTRIBUTABLE TO PARTNERS									995	1,189	633
General Partner’s interest in net income									3	3	2
Convertible Unitholders’ interest in income									9	0	0
Class D Unitholder’s interest in net income									0	3	2
Limited Partners’ interest in net income	$ 226	$ 207	$ 239	$ 311	$ 312	$ 291	$ 298	$ 282	983	1,183	629
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES									(185)	(112)	(111)
Interest expense, net of interest capitalized									(327)	(294)	(205)
Equity in earnings from unconsolidated affiliates									1,511	1,601	955
Other, net									(4)	(5)	(5)
INCOME BEFORE INCOME TAXES									995	1,190	634
Income tax expense									0	1	1
NET INCOME ATTRIBUTABLE TO PARTNERS									995	1,189	633
General Partner’s interest in net income									3	3	2
Convertible Unitholders’ interest in income									9	0	0
Class D Unitholder’s interest in net income									0	3	2
Limited Partners’ interest in net income									$ 983	$ 1,183	$ 629

Supplemental Financial State119

Supplemental Financial Statement Information (Schedule Of Statements Of Cash Flows) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$ 3,269	$ 2,905	$ 2,885
Cash paid for Bakken Pipeline Transaction	(1,398)	(777)	(2,367)
Proceeds from the sale of other assets	35	14	54
Contributions to unconsolidated affiliates	68	45	334
Capital expenditures	(7,719)	(9,021)	(5,369)
Net cash used in investing activities	(8,930)	(9,683)	(6,868)
Proceeds from borrowings	25,785	26,455	18,375
Repayments of long-term debt	(19,076)	(19,828)	(13,886)
Distributions to partners	(1,022)	(1,090)	(821)
Cash received from affiliate notes	5,317	0	0
Units repurchased under buyback program	0	(1,064)	(1,000)
Debt issuance costs	(52)	(75)	(77)
Net cash provided by financing activities	5,927	6,785	3,877
Increase (decrease) in cash and cash equivalents	(118)	(255)	257
Cash and cash equivalents, beginning of period	581	836	579
Cash and cash equivalents, end of period	463	581	836
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	918	1,103	816
Cash paid for Bakken Pipeline Transaction	0	(817)	0
Contributions to unconsolidated affiliates	70	0	118
Capital expenditures	(16)	(19)	0
Payments to Acquire Additional Interest in Subsidiaries	0	0	(800)
Net cash used in investing activities	(86)	(836)	(918)
Proceeds from borrowings	225	3,672	3,020
Repayments of long-term debt	(210)	(1,985)	(1,142)
Distributions to partners	(1,022)	(1,090)	(821)
Cash received from affiliate notes	176	210	54
Units repurchased under buyback program	0	(1,064)	(1,000)
Debt issuance costs	0	(11)	(15)
Net cash provided by financing activities	(831)	(268)	96
Increase (decrease) in cash and cash equivalents	1	(1)	(6)
Cash and cash equivalents, beginning of period	1	2	8
Cash and cash equivalents, end of period	$ 2	$ 1	$ 2

Supplemental Financial State120

Supplemental Financial Statement Information Supplemental Financial Information (Balance Sheet Units) (Details) - shares	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Authorized	1,046,947,157	1,044,767,336
Issued	1,046,947,157	1,044,767,336
Outstanding	1,046,947,157	1,044,767,336	1,077,500,000	1,119,800,000
Preferred Units, Authorized	329,299,267	0
Preferred Units, Issued	329,299,267	0
Preferred Units, Outstanding	329,299,267	0
Class D Units [Member]
Authorized	0	2,156,000
Issued	0	2,156,000
Outstanding	0	2,156,000