Energy Transfer 10-K 24 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Feb. 17, 2017	Jun. 30, 2016
Document Information [Line Items]
Entity Current Reporting Status	Yes
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Entity Registrant Name	Energy Transfer Partners, L.P.
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Central Index Key	1,012,569
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		551,551,441
Entity Public Float			$ 19,000
Entity Common Stock, Shares Outstanding	2,016
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 360	$ 527
Accounts receivable, net	3,002	2,118
Accounts receivable from related companies	209	268
Inventories	1,712	1,213
Derivative assets	20	40
Other current assets	426	532
Total current assets	5,729	4,698
Property, plant and equipment	58,220	50,869
Accumulated depreciation and depletion	(7,303)	(5,782)
PROPERTY, PLANT AND EQUIPMENT, net	50,917	45,087
Advances to and investments in unconsolidated affiliates	4,280	5,003
Other non-current assets, net	672	536
Intangible assets, net	4,696	4,421
Goodwill	3,897	5,428
Total assets	70,191	65,173
Current liabilities:
Accounts payable	2,900	1,859
Accounts payable to related companies	43	25
Derivative liabilities	166	63
Accrued and other current liabilities	1,905	2,048
Current maturities of long-term debt	1,189	126
Total current liabilities	6,203	4,121
Long-term debt, less current maturities	31,741	28,553
Long-term notes payable – related company	250	233
Non-current derivative liabilities	76	137
Deferred income taxes	4,394	4,082
Other non-current liabilities	952	968
Series A Preferred Units	33	33
Redeemable noncontrolling interests	15	15
Equity:
General Partner	206	306
Limited Partners:
Common Unitholders (529,869,235 and 505,645,703 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively)	14,946	17,043
Class E Unitholders (8,853,832 units authorized, issued and outstanding – held by subsidiary)	0	0
Class G Unitholders (90,706,000 units authorized, issued and outstanding – held by subsidiary)	0	0
Class H Unitholders (81,001,069 units authorized, issued and outstanding as of December 31, 2016 and 2015)	3,480	3,469
Class I Unitholders (100 units authorized, issued and outstanding)	2	14
Class K Unitholders (101,525,429 and 0 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively – held by subsidiary)	0	0
Accumulated other comprehensive income	8	4
Total partners’ capital	18,642	20,836
Noncontrolling interest	7,885	6,195
Total equity	26,527	27,031
Total liabilities and equity	$ 70,191	$ 65,173

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2016	Dec. 31, 2015
Common Units
Units - Authorized	529,689,235	505,645,703
Units - Issued	529,689,235	505,645,703
Units - Outstanding	529,689,235	505,645,703
Class E Units
Units - Authorized	8,853,832	8,853,832
Units - Issued	8,853,832	8,853,832
Units - Outstanding	8,853,832	8,853,832
Class G Units
Units - Authorized	90,706,000	90,706,000
Units - Issued	90,706,000	90,706,000
Units - Outstanding	90,706,000	90,706,000
Class H Units
Units - Authorized	81,001,069	81,001,069
Units - Issued	81,001,069	81,001,069
Units - Outstanding	81,001,069	81,001,069
Class I Units
Units - Authorized	100	100
Units - Issued	100	100
Units - Outstanding	100	100
Class K Units [Member]
Units - Authorized	101,525,429	0
Units - Issued	101,525,429	0
Units - Outstanding	101,525,429	0

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
REVENUES:
Natural gas sales	$ 3,619	$ 3,671	$ 5,386
NGL sales	4,841	3,936	5,845
Crude sales	6,766	8,378	16,416
Gathering, transportation and other fees	4,003	3,997	3,517
Refined product sales (see Note 3)	1,047	9,958	19,437
Other (see Note 3)	1,551	4,352	4,874
Total revenues	21,827	34,292	55,475
COSTS AND EXPENSES:
Cost of products sold (see Note 3)	15,394	27,029	48,414
Operating expenses (see Note 3)	1,484	2,261	2,059
Depreciation, depletion and amortization	1,986	1,929	1,669
Selling, general and administrative (see Note 3)	348	475	520
Impairment losses	813	339	370
Total costs and expenses	20,025	32,033	53,032
OPERATING INCOME	1,802	2,259	2,443
OTHER INCOME (EXPENSE):
Interest expense, net	(1,317)	(1,291)	(1,165)
Equity in earnings from unconsolidated affiliates	59	469	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	131	22	(12)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)	438	1,398	1,593
Income tax expense (benefit) from continuing operations	(186)	(123)	358
INCOME FROM CONTINUING OPERATIONS	624	1,521	1,235
Income from discontinued operations	0	0	64
NET INCOME	624	1,521	1,299
Less: Net income attributable to noncontrolling interest	327	157	116
Less: Net loss attributable to predecessor	0	(34)	(153)
NET INCOME ATTRIBUTABLE TO PARTNERS	297	1,398	1,336
General Partner’s interest in net income	948	1,064	513
Class H Unitholder’s interest in net income	351	258	217
Class I Unitholder’s interest in net income	8	94	0
Common Unitholders’ interest in net income (loss)	$ (1,010)	$ (18)	$ 606
INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT:
Basic income (loss) from continuing operations per Common Unit	$ (2.06)	$ (0.09)	$ 1.58
Diluted income (loss) from continuing operations per Common Unit	(2.06)	(0.10)	1.58
NET INCOME (LOSS) PER COMMON UNIT:
Basic	(2.06)	(0.09)	1.77
Diluted	$ (2.06)	$ (0.10)	$ 1.77

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	$ 624	$ 1,521	$ 1,299
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)
Total other comprehensive income	4	60	(117)
Comprehensive income	628	1,581	1,182
Less: Comprehensive income attributable to noncontrolling interest	327	157	116
Less: Comprehensive loss attributable to predecessor	0	(34)	(153)
Comprehensive income attributable to partners	$ 301	$ 1,458	$ 1,219

CONSOLIDATED STATEMENT OF EQUIT

CONSOLIDATED STATEMENT OF EQUITY - USD ($) $ in Millions	Total	General Partner	Limited Partner [Member]	Class H [Member]	Class I Units	AOCI Attributable to Parent [Member]	Noncontrolling Interest [Member]	Predecessor Equity [Member]	PennTex Acquisition [Member]	PennTex Acquisition [Member]Limited Partner [Member]
Balance at Dec. 31, 2013	$ 18,694	$ 171	$ 9,797	$ 1,511	$ 0	$ 61	$ 3,780	$ 3,374
Increase (Decrease) in Unitholders' Equity
Distributions to partners	(1,964)	(500)	(1,252)	(212)	0	0	0	0
Predecessor distributions to partners	(645)	0	0	0	0	0	0	(645)
Distributions to noncontrolling interest	(241)	0	0	0	0	0	(241)	0
Units issued for cash	1,382	0	1,382	0	0	0	0	0
Predecessor units issued for cash	1,227	0	0	0	0	0	0	1,227
Capital contributions from noncontrolling interest	67	0	0	0	0	0	67	0
Predecessor equity issued for acquisitions, net of cash received | Hoover Midstream Acquisition [Member]	4,281	0	0	0	0	0	0	4,281
Susser Merger | Susser Merger [Member]	1,534	0	908	0	0	0	626	0
Susser Merger									$ 0
Subsidiary units issued for cash	1,244	1	174	0	0	0	1,069	0
Lake Charles LNG Transaction | Lake Charles LNG Transaction [Member]	(1,167)	0	(1,167)	0	0	0	0	0
Acquisition and disposition of noncontrolling interest	(325)	(1)	(79)	0	0	0	(245)	0
Other comprehensive income, net of tax	(117)	0	0	0	0	(117)	0	0
Other, net	42	0	61	(4)	0	0	(19)	4
Net income	1,299	513	606	217	0	0	116	(153)
Class H Unitholder’s interest in net income	217
Net Income (Loss) Allocated to General Partners	513
Less: Net income attributable to noncontrolling interest	116
Balance at Dec. 31, 2014	25,311	184	10,430	1,512	0	(56)	5,153	8,088
Increase (Decrease) in Unitholders' Equity
Distributions to partners	(3,134)	(944)	(1,863)	(247)	(80)	0	0	0
Predecessor distributions to partners	(202)	0	0	0	0	0	0	(202)
Distributions to noncontrolling interest	(338)	0	0	0	0	0	(338)	0
Units issued for cash	1,428	0	1,428	0	0	0	0	0
Predecessor units issued for cash	34	0	0	0	0	0	0	34
Regency Merger	0	0	7,890	0	0	0	0	(7,890)
Capital contributions from noncontrolling interest	875	0	0	0	0	0	875	0
Susser Merger									$ 0
Subsidiary units issued for cash	1,519	2	298	0	0	0	1,219	0
Exchange of equity and Controlling Interest in a Subsidiary | Bakken Pipeline Transaction [Member]	1,019	0	(999)	1,946	0	0	72	0
Exchange of equity and Controlling Interest in a Subsidiary | Sunoco LP Exchange [Member]	(992)	0	(52)	0	0	0	(940)	0
Exchange of equity and Controlling Interest in a Subsidiary | Susser Exchange Transaction [Member]	(68)	0	(68)	0	0	0	0	0
Acquisition and disposition of noncontrolling interest	(65)	0	(26)	0	0	0	(39)	0
Other comprehensive income, net of tax	60	0	0	0	0	60	0	0
Other, net	63	0	23	0	0	0	36	4
Net income	1,521	1,064	(18)	258	94	0	157	(34)
Class H Unitholder’s interest in net income	258
Net Income (Loss) Allocated to General Partners	1,064
Less: Net income attributable to noncontrolling interest	157
Balance at Dec. 31, 2015	27,031	306	17,043	3,469	14	4	6,195	0
Increase (Decrease) in Unitholders' Equity
Distributions to partners	(3,542)	(1,048)	(2,134)	(340)	(20)	0	0	0
Distributions to noncontrolling interest	(481)	0	0	0	0	0	(481)	0
Units issued for cash	1,098	0	1,098	0	0	0	0	0
Predecessor units issued for cash	0
Capital contributions from noncontrolling interest	236	0	0	0	0	0	236	0
Susser Merger	543	0		0	0	0	236	0		$ 307
Subsidiary units issued for cash	1,388	0	37	0	0	0	1,351	0
Exchange of equity and Controlling Interest in a Subsidiary	(405)	0	(405)	0	0	0	0	0
Other comprehensive income, net of tax	4	0	0	0	0	4	0	0
Other, net	31	0	10	0	0	0	21	0
Net income	624	948	(1,010)	351	8	0	327	0
Class H Unitholder’s interest in net income	351
Net Income (Loss) Allocated to General Partners	948
Less: Net income attributable to noncontrolling interest	327
Balance at Dec. 31, 2016	$ 26,527	$ 206	$ 14,946	$ 3,480	$ 2	$ 8	$ 7,885	$ 0

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	$ 624	$ 1,521	$ 1,299
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,986	1,929	1,669
Deferred income taxes	(169)	202	(49)
Amortization included in interest expense	(20)	(36)	(60)
Inventory valuation adjustments	(170)	104	473
Unit-based compensation expense	80	79	68
Impairment losses	813	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
Distributions on unvested awards	(25)	(16)	(16)
Equity in earnings of unconsolidated affiliates	(59)	(469)	(332)
Distributions from unconsolidated affiliates	406	440	291
Other non-cash	(271)	(22)	(72)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	(117)	(1,367)	(320)
Net cash provided by operating activities	3,303	2,747	3,169
INVESTING ACTIVITIES:
Cash transferred to ETE in connection with the Sunoco LP Exchange	0	(114)	0
Cash paid for acquisition of a noncontrolling interest	0	(129)	(325)
Cash paid for Susser Merger, net of cash received	0	0	808
Cash paid for all other acquisitions	(159)	(675)	(472)
Capital expenditures, excluding allowance for equity funds used during construction	(7,550)	(9,098)	(5,213)
Cash paid for all other acquisitions	71	80	45
Contributions to unconsolidated affiliates	(59)	(45)	(399)
Distributions from unconsolidated affiliates in excess of cumulative earnings	135	124	136
Proceeds from sale of discontinued operations	0	0	77
Proceeds from the sale of assets	25	23	61
Change in restricted cash	14	19	172
Other	1	(16)	(18)
Net cash used in investing activities	(6,390)	(7,820)	(6,692)
FINANCING ACTIVITIES:
Proceeds from borrowings	19,916	22,462	15,354
Repayments of long-term debt	(15,799)	(17,843)	(12,702)
Proceeds from affiliate notes	4,997	233	0
Repayments on affiliate notes	4,873	0	0
Units issued for cash	1,098	1,428	1,382
Predecessor units issued for cash	0	34	1,227
Subsidiary units issued for cash	1,388	1,519	1,244
Capital contributions from noncontrolling interest	236	841	67
Distributions to partners	3,542	3,134	1,964
Predecessor distributions to partners	0	(202)	(645)
Distributions to noncontrolling interest	(481)	(338)	(241)
Debt issuance costs	(22)	(63)	(63)
Other	2	0	(41)
Net cash provided by financing activities	2,920	4,937	3,618
Increase (decrease) in cash and cash equivalents	(167)	(136)	95
Cash and cash equivalents, beginning of period	527	663	568
Cash and cash equivalents, end of period	360	527	663
Legacy Sunoco, Inc. [Member]
INVESTING ACTIVITIES:
Proceeds from the sale of AmeriGas common units	2,200	0	0
Bakken Pipeline Transaction [Member]
INVESTING ACTIVITIES:
Proceeds from sale of noncontrolling interest	0	980	0
Susser Exchange Transaction [Member]
INVESTING ACTIVITIES:
Proceeds from sale of noncontrolling interest	0	967	0
Rover Pipeline Sale [Member]
INVESTING ACTIVITIES:
Proceeds from sale of noncontrolling interest	0	64	0
AmeriGas [Member]
INVESTING ACTIVITIES:
Proceeds from the sale of AmeriGas common units	0	0	814
Eagle Rock Midstream Acquisition [Member]
INVESTING ACTIVITIES:
Cash paid for predecessor acquisitions, net of cash received	0	0	(762)
Vitol Acquisition [Member]
INVESTING ACTIVITIES:
Cash paid for all other acquisitions	769	0	0
PennTex Acquisition [Member]
INVESTING ACTIVITIES:
Cash paid for all other acquisitions	$ 299	$ 0	$ 0

Operations and Organization (No

Operations and Organization (Notes)	12 Months Ended
	Dec. 31, 2016
Operations And Organization [Abstract]
OPERATIONS AND ORGANIZATION	OPERATIONS AND BASIS OF PRESENTATION: Organization. The consolidated financial statements presented herein contain the results of Energy Transfer Partners, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETP”). The Partnership is managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner. The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales. The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States. The Partnership owns a controlling interest in Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of crude oil, NGL and refined products pipelines. The Partnership owns a controlling interest in PennTex, a publicly traded Delaware limited partnership that provides natural gas gathering and processing and residue gas and natural gas liquids transportation services to producers. Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity. Management evaluated subsequent events through the date the financial statements were issued. The Partnership owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, these undivided interests are consolidated proportionately.

Estimates, Significant Accounti

Estimates, Significant Accounting Policies and Balance Sheet Detials (Notes)	12 Months Ended
	Dec. 31, 2016
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Estimates Significant Accounting Policies And Balance Sheet Detail Text Block	ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL: Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates. New Accounting Pronouncements 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. 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 a material impact on the Partnership’s 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. 2016-17, 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. The 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 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. Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues. Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors. NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer. In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized. We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations. Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs. Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2016 2015 2014 Accounts receivable $ (919 ) $ 819 $ 600 Accounts receivable from related companies 30 (243 ) (22 ) Inventories (368 ) (351 ) 51 Other current assets 83 (178 ) 150 Other non-current assets, net (78 ) 188 (6 ) Accounts payable 972 (1,215 ) (851 ) Accounts payable to related companies 29 (160 ) 3 Accrued and other current liabilities 39 (83 ) (191 ) Other non-current liabilities 33 (219 ) (73 ) Price risk management assets and liabilities, net 62 75 19 Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (117 ) $ (1,367 ) $ (320 ) Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2016 2015 2014 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 822 $ 896 $ 643 Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP 194 — — Net gains from subsidiary common unit transactions 37 300 175 NON-CASH FINANCING ACTIVITIES: Issuance of Common Units in connection with the PennTex Acquisition $ 307 $ — $ — Issuance of Common Units in connection with the Regency Merger — 9,250 — Issuance of Class H Units in connection with the Bakken Pipeline Transaction — 1,946 — Issuance of Common Units in connection with the Susser Merger — — 908 Contribution of property, plant and equipment from noncontrolling interest — 34 — Long-term debt assumed and non-compete agreement notes payable issued in acquisitions — — 564 Predecessor equity issuances of common units in connection with Regency’s acquisitions — — 4,281 Long-term debt assumed or exchanged in Regency’s acquisitions — — 2,386 Redemption of Common Units in connection with the Bakken Pipeline Transaction — 999 — Redemption of Common Units in connection with the Sunoco LP Exchange — 52 — Redemption of Common Units in connection with the Lake Charles LNG Transaction — — 1,167 SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 1,411 $ 1,467 $ 1,232 Cash paid for (refund of) income taxes (229 ) 71 344 Accounts Receivable Our midstream, NGL and intrastate transportation and storage operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. Master setoff agreements are put in place with counterparties where appropriate to mitigate risk. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. Our investment in Sunoco Logistics segment extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Based on that review, a letter of credit or other security may be required. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted. We have a diverse portfolio of customers, however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due. We enter into netting arrangements with counterparties to the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets. Inventories Inventories 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 113 104 Spare parts and other 217 270 Total inventories $ 1,712 $ 1,213 During the years ended December 31, 2016 and 2015, the Partnership recorded write-downs of $170 million and $104 million , respectively, on its crude oil, refined products and NGL inventories as a result of declines in the market price of these products. The write-downs were calculated based upon current replacement costs. We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations. Other Current Assets Other current assets consisted of the following: December 31, 2016 2015 Deposits paid to vendors $ 74 $ 74 Income taxes receivable 128 291 Prepaid expenses and other 224 167 Total other current assets $ 426 $ 532 Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2016, the Partnership recorded a $133 million fixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the liquids transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds. Components and useful lives of property, plant and equipment were as follows: December 31, 2016 2015 Land and improvements $ 659 $ 686 Buildings and improvements (1 to 45 years) 1,784 1,526 Pipelines and equipment (5 to 83 years) 35,923 33,148 Natural gas and NGL storage facilities (5 to 46 years) 1,515 391 Bulk storage, equipment and facilities (2 to 83 years) 3,677 2,853 Retail equipment (2 to 99 years) — 401 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) 517 743 Construction work-in-process 10,096 7,844 58,220 50,869 Less – Accumulated depreciation and depletion (7,303 ) (5,782 ) Property, plant and equipment, net $ 50,917 $ 45,087 We recognized the following amounts for the periods presented: Years Ended December 31, 2016 2015 2014 Depreciation and depletion expense $ 1,793 $ 1,713 $ 1,457 Capitalized interest, excluding AFUDC 200 163 101 Advances to and Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. 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) $ 3 $ 11 Regulatory assets 86 90 Deferred charges 217 198 Restricted funds 190 192 Long-term affiliated receivable 90 — Other 86 45 Total other non-current assets, net $ 672 $ 536 (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) $ 5,362 $ (737 ) $ 4,601 $ (554 ) Patents (10 years) 48 (21 ) 48 (16 ) Trade Names (20 years) 66 (22 ) 66 (18 ) Other (1 to 15 years) 2 (2 ) 6 (3 ) Total amortizable intangible assets $ 5,478 $ (782 ) $ 4,721 $ (591 ) Non-amortizable intangible assets: Trademarks — — 291 — Total intangible assets $ 5,478 $ (782 ) $ 5,012 $ (591 ) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2016 2015 2014 Reported in depreciation, depletion and amortization $ 193 $ 216 $ 212 Estimated aggregate amortization expense for the next five years is as follows: Years Ending December 31: 2017 $ 213 2018 213 2019 211 2020 211 2021 211 We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. In 2015, we recorded $24 million of intangible asset impairments related to the liquids transportation and services segment primarily due to an expected decrease in future cash flows. Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream Liquids Transportation and Services Investment in Sunoco Logistics All Other Total Balance, December 31, 2014 $ 10 $ 1,011 $ 767 $ 432 $ 1,358 $ 4,064 $ 7,642 Reduction due to Sunoco LP deconsolidation — — — — — (2,018 ) (2,018 ) Impaired — (99 ) — (106 ) — — (205 ) Other — — (49 ) — — 58 9 Balance, December 31, 2015 10 912 718 326 1,358 2,104 5,428 Acquired — — 177 — 251 — 428 Reduction due to contribution of legacy Sunoco, Inc. retail business — — — — — (1,289 ) (1,289 ) Impaired — (638 ) (32 ) — — — (670 ) Balance, December 31, 2016 $ 10 $ 274 $ 863 $ 326 $ 1,609 $ 815 $ 3,897 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 segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of: (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 im

Acquisitions, Divestitures and

Acquisitions, Divestitures and Related Transactions (Notes)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
ACQUISITIONS AND DIVESTITURE	ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS: 2016 Transactions ETP and Sunoco Logistics Merger In November 2016, ETP and Sunoco Logistics entered into a merger agreement providing for the acquisition of ETP by Sunoco Logistics in a unit-for-unit transaction. Under the terms of the transaction, ETP unitholders will receive 1.5 common units of Sunoco Logistics for each common unit of ETP they own. Under the terms of the merger agreement, Sunoco Logistics’ general partner will be merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. The transaction is expected to close in April 2017. 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. In connection with this transaction, the Partnership deconsolidated the legacy Sunoco, Inc. retail business, including goodwill of $1.29 billion and intangible assets of $294 million . The results of Sunoco, LLC and the legacy Sunoco, Inc. retail business’ operations have not been presented as discontinued operations and Sunoco, Inc.’s retail business assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements. Following is a summary of amounts reflected for the prior periods in ETP’s consolidated statements of operations related to Sunoco, LLC and the legacy Sunoco, Inc. retail business, which operations are no longer consolidated for the current period in 2016: Years Ended December 31, 2015 2014 Revenues $ 12,482 $ 22,487 Cost of products sold 11,174 21,155 Operating expenses 798 727 Selling, general and administrative expenses 106 99 2015 Transactions Sunoco LP In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million . Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued $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 21 million ETP common units owned by ETE (the “Sunoco LP Exchange”). In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years , which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. In connection with this transaction, the Partnership deconsolidated Sunoco LP, including goodwill of $1.81 billion and intangible assets of $982 million related to Sunoco LP. The Partnership continues to hold 37.8 million Sunoco LP common units accounted for under the equity method. The results of Sunoco LP’s operations have not been presented as discontinued operations and Sunoco LP’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements. Bakken Pipeline In March 2015, ETE transferred 30.8 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally 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, the Partnership also issued to ETE 100 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 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 the Partnership merged with Regency, with Regency surviving as a wholly-owned subsidiary of the Partnership (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.4124 Partnership common units. ETP issued 172.2 million Partnership common units to Regency unitholders, including 15.5 million units issued to Partnership subsidiaries. The 1.9 million outstanding Regency series A preferred units were converted into corresponding new Partnership 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 the Partnership by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years. The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger. ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor. 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 15.8 million ETP Common Units. The Susser Merger broadens our 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 We 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, 2014. Our consolidated statements of operations for the year ended December 31, 2014 reflected revenue and net income related to Susser of $2.32 billion and $105 million , respectively. No pro forma information has been presented, as the impact of these acquisitions was not material in relation to ETP’s 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. 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 18.7 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). This transaction was effective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG, including goodwill of $184 million and intangible assets of $50 million related to Lake Charles LNG. The results of Lake Charles LNG’s operations have not been presented as discontinued operations and Lake Charles LNG’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements due to the continuing involvement among the entities. 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 common units and 6.3 million Class F Units, all of which have subsequently converted into ETP common units), and ETP ( 2.2 million Common Units).

Advances to and Investments in

Advances to and Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2016
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Investments in and Advances to Affiliates, Schedule of Investments [Text Block]	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: 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 Sunoco LP 1,225 1,380 Others 443 627 Total $ 4,280 $ 5,003 Citrus ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. AmeriGas In 2012, we received 29.6 million AmeriGas common units in connection with the contribution of our propane operations. During the year ended December 31, 2014, we 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 all other segment. FEP We have a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. Our investment in FEP is reflected in the interstate transportation and storage segment. MEP We own a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures . Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016. HPC We own a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. Our investment in HPC is reflected in the intrastate transportation and storage segment. Sunoco LP Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from the Partnership. As a result, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. As of December 31, 2016 , the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 44.3% of Sunoco LP’s total outstanding common units, and is reflected in the all other segment. Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, AmeriGas, Citrus, FEP, HPC, MEP and Sunoco LP (on a 100% basis) for all periods presented: December 31, 2016 2015 Current assets $ 2,109 $ 1,646 Property, plant and equipment, net 13,355 12,611 Other assets 6,557 5,485 Total assets $ 22,021 $ 19,742 Current liabilities $ 2,547 $ 1,517 Non-current liabilities 12,899 10,428 Equity 6,575 7,797 Total liabilities and equity $ 22,021 $ 19,742 Years Ended December 31, 2016 2015 2014 Revenue $ 19,207 $ 20,961 $ 4,925 Operating income 933 1,620 1,071 Net income 196 894 577 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

Net Income Per Limited Partner

Net Income Per Limited Partner Unit (Notes)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
NET INCOME PER LIMITED PARTNER UNIT	NET INCOME (LOSS) PER LIMITED PARTNER UNIT: The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit. Years Ended December 31, 2016 2015 2014 Income from continuing operations $ 624 $ 1,521 $ 1,235 Less: Income from continuing operations attributable to noncontrolling interest 327 157 116 Less: Loss from continuing operations attributable to predecessor — (34 ) (153 ) Income from continuing operations, net of noncontrolling interest 297 1,398 1,272 General Partner’s interest in income from continuing operations 948 1,064 513 Class H Unitholder’s interest in income from continuing operations 351 258 217 Class I Unitholder’s interest in income from continuing operations 8 94 — Common Unitholders’ interest in income (loss) from continuing operations (1,010 ) (18 ) 542 Additional earnings allocated to General Partner (10 ) (5 ) (4 ) Distributions on employee unit awards, net of allocation to General Partner (19 ) (16 ) (13 ) Income (loss) from continuing operations available to Common Unitholders $ (1,039 ) $ (39 ) $ 525 Weighted average Common Units – basic 505.5 432.8 331.5 Basic income (loss) from continuing operations per Common Unit $ (2.06 ) $ (0.09 ) $ 1.58 Income (loss) from continuing operations available to Common Unitholders $ (1,039 ) $ (39 ) $ 525 Loss attributable to ETP Series A Preferred Units — (6 ) — $ (1,039 ) $ (45 ) $ 525 Weighted average Common Units – basic 505.5 432.8 331.5 Dilutive effect of unvested Unit Awards — — 1.3 Dilutive effect of Preferred Units — 0.7 — Weighted average Common Units – diluted 505.5 433.5 332.8 Diluted income (loss) from continuing operations per Common Unit $ (2.06 ) $ (0.10 ) $ 1.58 Basic income from discontinued operations per Common Unit $ — $ — $ 0.19 Diluted income from discontinued operations per Common Unit $ — $ — $ 0.19

Debt Obligations (Notes)

Debt Obligations (Notes)	12 Months Ended
	Dec. 31, 2016
Debt Obligations [Abstract]
DEBT OBLIGATIONS	DEBT OBLIGATIONS: Our debt obligations consist of the following: December 31, 2016 2015 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 15, 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 — Other 30 32 32,930 28,679 Less: current maturities 1,189 126 $ 31,741 $ 28,553 (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 $64 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: 2017 $ 1,812 2018 1,650 2019 5,045 2020 3,167 2021 1,900 Thereafter 19,420 Total $ 32,994 Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap. ETP 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. 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). The Partnership may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually. The ETP senior notes are unsecured obligations of the Partnership and the obligation of the Partnership to repay the ETP senior notes is not guaranteed by any of the Partnership’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, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually. Panhandle Junior Subordinated Notes The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175% . The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 3.77% at December 31, 2016 . 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. Credit Facilities and Commercial Paper 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% . Covenants Related to Our Credit Agreements Covenants Related to ETP The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions. The ETP Credit 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 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. Compliance with our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2016 .

Series A Preferred Units (Notes

Series A Preferred Units (Notes)	12 Months Ended
	Dec. 31, 2016
Temporary Equity Disclosure [Abstract]
Preferred Units [Text Block]	SERIES A PREFERRED UNITS: The Series A 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 Preferred Units are entitled to a preferential quarterly cash distribution of $0.445 per Preferred Unit if outstanding on the record dates of the Partnership’s common unit distributions. Holders of the 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 common units issuable upon conversion of the 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 Preferred Units were convertible into 0.9 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 (Notes)

Equity (Notes)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
EQUITY	EQUITY: Limited Partner interests are represented by Common, Class E Units, Class G Units, Class H and Class I Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance. IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiary of ETE, owns all of the IDRs. Common Units The change in Common Units was as follows: Years Ended December 31, 2016 2015 2014 Number of Common Units, beginning of period 505.6 355.5 333.8 Common Units redeemed in connection with certain transactions (17.8 ) (51.8 ) (18.7 ) Common Units issued in connection with certain acquisitions 8.9 172.2 15.8 Common Units issued in connection with the Distribution Reinvestment Plan 6.6 7.7 2.8 Common Units issued in connection with Equity Distribution Agreements 26.1 21.1 21.4 Issuance of Common Units under equity incentive plans 0.5 0.9 0.4 Number of Common Units, end of period 529.9 505.6 355.5 Our Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.” Equity Distribution Program From time to time, we have sold Common Units through equity distribution agreements. Such sales of Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreements. In July 2016, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.50 billion . During the year ended December 31, 2016 , we issued 26.1 million units for $891 million , net of commissions of $8 million . As of December 31, 2016 , $936 million of our Common Units remained available to be issued under our currently effective equity distribution agreement. Equity Incentive Plan Activity We issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations. Distribution Reinvestment Program Our Distribution Reinvestment Plan (the “DRIP”) provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units. 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 17.1 million Common Units. As of December 31, 2016 , a total of 4.9 million Common Units remain available to be issued under the existing registration statement. January 2017 Private Placement In January 2017, the Partnership sold 15.8 million ETP Common Units to ETE in a private placement transaction for gross proceeds of approximately $568 million . Class E Units The Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year, with any excess thereof available for distribution to Unitholders other than the holders of Class E Units in proportion to their respective interests. The Class E Units are treated 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 Class E Units at a future date. All of the 8.9 million Class E Units outstanding are held by a subsidiary and are reported as treasury units. Class G Units In conjunction with the Sunoco Merger, we amended our partnership agreement to create Class F Units. The number of Class F Units issued was determined at the closing of the Sunoco Merger and equaled 90.7 million , which included 40 million Class F Units issued in exchange for cash contributed by Sunoco, Inc. to us immediately prior to or concurrent with the closing of the Sunoco Merger. The Class F Units generally did not have any voting rights. The Class F Units were entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class F Unit per year. In April 2013, all of the outstanding Class F Units were exchanged for Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are held by a subsidiary and therefore are reflected as treasury units in the consolidated financial statements. Class H Units and Class I Units Currently Outstanding 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 and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. Bakken Pipeline Transactions In March 2015, ETE transferred 30.8 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally 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, the Partnership also issued to ETE 100 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 Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. In connection with the transaction, ETP issued 100 Class I Units. The Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the Class I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the Class I Units and (ii) after making cash distributions to Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in our Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ending March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” 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, the Partnership issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in the Partnership, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units 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 With respect to our investment in Sunoco Logistics, we account for the difference between the carrying amount of our investment in and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions. As a result of Sunoco Logistics’ issuances of common units during the year ended December 31, 2016 , we recognized increases in partners’ capital of $37 million . 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. Quarterly Distributions of Available Cash The Partnership Agreement requires that we distribute all of our Available Cash to our Unitholders and our General Partner within forty-five 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 of our fiscal quarters, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the General Partner in its sole discretion to provide for the proper conduct of our 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 our Partnership Agreement. Our distributions of Available Cash from operating surplus, excluding incentive distributions, to our General Partner and Limited Partner interests are based on their respective interests as of the distribution record date. Incentive distributions allocated to our General Partner are determined based on the amount by which quarterly distribution to common Unitholders exceed certain specified target levels, as set forth in our Partnership Agreement. Distributions declared during the periods presented were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2013 February 7, 2014 February 14, 2014 $ 0.9200 March 31, 2014 May 5, 2014 May 15, 2014 0.9350 June 30, 2014 August 4, 2014 August 14, 2014 0.9550 September 30, 2014 November 3, 2014 November 14, 2014 0.9750 December 31, 2014 February 6, 2015 February 13, 2015 0.9950 March 31, 2015 May 8, 2015 May 15, 2015 1.0150 June 30, 2015 August 6, 2015 August 14, 2015 1.0350 September 30, 2015 November 5, 2015 November 16, 2015 1.0550 December 31, 2015 February 8, 2016 February 16, 2016 1.0550 March 31, 2016 May 6, 2016 May 16, 2016 1.0550 June 30, 2016 August 8, 2016 August 15, 2016 1.0550 September 30, 2016 November 7, 2016 November 14, 2016 1.0550 December 31, 2016 February 7, 2017 February 14, 2017 1.0550 ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units: Total Year 2017 $ 626 2018 138 2019 128 Each year beyond 2019 33 Sunoco Logistics Quarterly Distributions of Available Cash Distributions declared during the periods presented 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 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 Accumulated Other Comprehensive Income 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 — Total AOCI, net of tax $ 8 $ 4 The table below sets forth the tax amounts included in the respective components of other comprehensive income: 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

Unit-Based Compensation Plans (

Unit-Based Compensation Plans (Notes)	12 Months Ended
	Dec. 31, 2016
Deferred Compensation Arrangements [Abstract]
UNIT-BASED COMPENSATION PLANS	UNIT-BASED COMPENSATION PLANS: ETP Unit-Based Compensation Plan We have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2016 , an aggregate total of 1.8 million ETP Common Units remain available to be awarded under our equity incentive plans. Restricted Units We have granted restricted unit awards to employees that vest over a specified time period, typically a five -year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five -year service vesting requirement. The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2015 4.8 $ 47.61 Awards granted 2.5 35.73 Awards vested (0.8 ) 53.22 Awards forfeited (0.2 ) 48.39 Unvested awards as of December 31, 2016 6.3 41.53 During the years ended December 31, 2016, 2015, and 2014 , the weighted average grant-date fair value per unit award granted was $35.73 , $35.21 and $60.85 , respectively. The total fair value of awards vested was $28 million , $49 million and $26 million , respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2016 , a total of 6.3 million unit awards remain unvested, for which ETP expects to recognize a total of $179 million in compensation expense over a weighted average period of 2.1 years . Cash Restricted Units. The Partnership has also granted cash restricted units, which vest 100% at the end of the third year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting. As of December 31, 2016 , a total of 0.2 million unvested cash restricted units were outstanding. Based on the trading price of ETP Common Units at December 31, 2016 , the Partnership expects to recognize $3 million of unit-based compensation expense related to non-vested cash restricted units over a period of 1.0 year . Sunoco Logistics Unit-Based Compensation Plan Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units, phantom unit awards, unit appreciation rights, unrestricted unit awards and other unit-based awards. Restricted Units Sunoco Logistics has granted restricted unit awards to employees and directors that entitle the grantees to receive Sunoco Logistics common units or, at the discretion of the Sunoco Logistics compensation committee, an amount of cash equivalent to the value of common units upon vesting. Sunoco Logistics’ outstanding restricted unit awards are time-vested grants, the vesting of which occurs over a five-year period, and is conditioned solely upon continued employment or service as of the applicable vesting date. These unit awards entitle the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by Sunoco Logistics during the period the restricted unit is outstanding. The following table summarizes the activity of the Sunoco Logistics restricted unit awards: Number of Sunoco Logistics Units Weighted Average Grant-Date Fair Value Per Sunoco Logistics Unit Unvested awards as of December 31, 2015 2.5 $ 33.16 Awards granted 1.3 23.21 Awards vested (0.5 ) 34.19 Awards forfeited (0.1 ) 33.72 Unvested awards as of December 31, 2016 3.2 28.57 During the years ended December 31, 2016 , 2015 and 2014 , the weighted average grant-date fair value per unit award granted was $23.21 , $29.54 and $41.59 , respectively. The total fair value of restricted unit awards vested for the years ended December 31, 2016 , 2015 and 2014 , was $12 million , $8 million , and $30 million , respectively, based on the market price of Sunoco Logistics’ common units as of the vesting date. As of December 31, 2016 , estimated compensation cost related to non-vested awards not yet recognized was $57 million , and the weighted average period over which this cost is expected to be recognized in expense is 3.0 years .

Income Taxes

Income Taxes	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) are summarized as follows: Years Ended December 31, 2016 2015 2014 Current expense (benefit): Federal $ 18 $ (274 ) $ 321 State (35 ) (51 ) 86 Total (17 ) (325 ) 407 Deferred expense (benefit): Federal (173 ) 231 (50 ) State 4 (29 ) 1 Total (169 ) 202 (49 ) Total income tax expense (benefit) from continuing operations $ (186 ) $ (123 ) $ 358 Historically, our effective 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 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: Years Ended December 31, 2016 2015 2014 Income tax expense at U.S. statutory rate of 35 percent $ 154 $ 490 $ 558 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax (519 ) (515 ) (341 ) Nondeductible goodwill included in the Lake Charles LNG Transaction — — 105 Goodwill impairments 223 — — State income taxes (net of federal income tax effects) (17 ) (37 ) 54 Dividend Received Deduction (15 ) (24 ) — Audit Settlement — (7 ) — Premium on debt retirement — — (10 ) Foreign — — (8 ) Other (12 ) (30 ) — Income tax expense (benefit) from continuing operations $ (186 ) $ (123 ) $ 358 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 $ 380 $ 155 Pension and other postretirement benefits 30 36 Long term debt 32 61 Other 84 142 Total deferred income tax assets 526 394 Valuation allowance (118 ) (121 ) Net deferred income tax assets $ 408 $ 273 Deferred income tax liabilities: Properties, plants and equipment $ (1,054 ) $ (1,305 ) Investment in unconsolidated affiliates (3,728 ) (2,889 ) Trademarks — (112 ) Other (20 ) (49 ) Total deferred income tax liabilities (4,802 ) (4,355 ) Accumulated deferred income taxes $ (4,394 ) $ (4,082 ) 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 $ (4,082 ) $ (4,331 ) ETE Acquisition of general partner of Sunoco LP — 490 Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) (460 ) — Tax provision 169 (202 ) Other (21 ) (39 ) Net deferred income tax liability, end of year $ (4,394 ) $ (4,082 ) ETP Holdco and other corporate subsidiaries have federal net operating loss carryforward of $580 million , all of which will expire in 2032 through 2035 . Our corporate subsidiaries have $52 million of federal alternative minimum tax credits at December 31, 2016 . Our corporate subsidiaries have state net operating loss carryforward benefits of $124 million , net of federal tax, which expire between 2017 and 2036 . A valuation allowance of $118 million is applicable to the state net operating loss carryforward benefits primarily attributable to significant restrictions 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 — 20 Additions attributable to tax positions taken in prior years 18 178 — 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 this litigation, it will receive tax refunds of approximately $530 million . However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the financial statements as of December 31, 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. ETP and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

Regulatory Matters, Commitments

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Notes)	12 Months Ended
	Dec. 31, 2016
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Commitments Contingencies and Guarantees [Text Block]	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: Contingent Residual Support Agreement – AmeriGas In connection with the closing of the contribution of its propane operations in January 2012, ETP 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. ETP believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations. ETP’s joint venture agreements require that it funds its proportionate share of capital contributions to its unconsolidated affiliates. Such contributions will depend upon ETP’s unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034 . The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: Years Ended December 31, 2016 2015 2014 Rental expense (1) $ 81 $ 176 $ 159 Less: Sublease rental income (1 ) (16 ) (26 ) Rental expense, net $ 80 $ 160 $ 133 (1) Includes contingent rentals totaling $26 million and $24 million for the years ended December 31, 2015 and 2014 , respectively. Future minimum lease commitments for such leases are: Years Ending December 31: 2017 $ 38 2018 30 2019 28 2020 28 2021 35 Thereafter 133 Future minimum lease commitments 292 Less: Sublease rental income (14 ) Net future minimum lease commitments $ 278 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 or 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 2017. 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 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 TRO 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 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. 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 $53 million and $40 million , respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period. The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. No amounts have been recorded in our December 31, 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 31, 2016 and will continue to assess its potential exposure to the allegations as the matter progresses. As of December 31, 2016 , the Agreed Order is in the approval process with the Texas Commission on Environmental Quality and includes a $21,000 Supplemental Environmental Project. Environmental Matters Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position. Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs. Environmental Remediation Our subsidiaries are responsible for environmental remediation at certain sites, including the following: • Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties. • Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons. • Currently operating Sunoco, Inc. retail sites. • Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites. • Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2016 , Sunoco, Inc. had been named as a PRP at approximately 50 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant. To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets. The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements. December 31, 2016 2015 Current $ 32 $ 41 Non-current 313 326 Total environmental liabilities $ 345 $ 367 In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. During the years ended December 31, 2016 and 2015 , the Partnership recorded $43 million and $38 million , respectively, of expenditures related to environmental cleanup programs. On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period. On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued an NOV/ FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 and EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position. Our pipeline operations are subject to regulation by the U.S. Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and ma

Derivative assets and liabiltie

Derivative assets and liabilties (Notes)	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 segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We use derivatives in our liquids transportation and services segment 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 financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy. The following table details our outstanding commodity-related derivatives: December 31, 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 (2,240,000 ) 2017 (939,000 ) 2016-2017 Corn (Bushels) – Futures — — 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 were designated as hedges for accounting purposes: Term Type (1) Notional Amount Outstanding December 31, 2016 December 31, 2015 July 2016 (2) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate $ — $ 200 July 2017 (3) Forward-starting to pay a fixed rate of 3.90% and receive a floating rate 500 300 July 2018 (3) Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200 200 July 2019 (3) Forward-starting to pay a fixed rate of 3.25% and receive a floating rate 200 200 December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 1,200 March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300 300 (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward-starting swaps have terms of 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 terms of 30 years with a mandatory termination date the same as the effective date. Credit Risk Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance. The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income. Derivative Summary The following table provides a summary of our derivative assets and liabilities: Fair Value of Derivative Instruments Asset Derivatives Liability Derivatives December 31, 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 24 57 (52 ) (41 ) Interest rate derivatives — — (193 ) (171 ) Embedded derivatives in ETP Preferred Units — — (1 ) (5 ) 362 410 (662 ) (523 ) Total derivatives $ 362 $ 448 $ (666 ) $ (526 ) 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) 24 57 (52 ) (41 ) Broker cleared derivative contracts Other current assets 338 391 (420 ) (309 ) 362 448 (666 ) (526 ) 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 $ 20 $ 122 $ (324 ) $ (200 ) We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date. The following tables summarize the amounts recognized with respect to our derivative financial instruments: Location of Gain/(Loss) 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 (173 ) 23 199 Interest rate derivatives Losses on interest rate derivatives (12 ) (18 ) (157 ) Embedded derivatives Other, net 4 12 3 Total $ (216 ) $ 6 $ 39

Retirement Benefits (Notes)

Retirement Benefits (Notes)	12 Months Ended
	Dec. 31, 2016
RETIREMENT BENEFITS
Pension and Other Postretirement Benefits Disclosure	RETIREMENT BENEFITS: Savings and Profit Sharing Plans We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $44 million , $39 million and $50 million to these 401(k) savings plans 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 $ 180 $ 718 $ 65 $ 202 Interest cost 1 2 4 23 2 4 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 51 165 20 57 180 Change in plan assets: Fair value of plan assets at beginning of period 15 — 253 598 — 265 Return on plan assets and other (2 ) — 6 16 — — Employer contributions — — 10 138 — 8 Benefits paid, net (1 ) — (21 ) (46 ) — (20 ) Settlements — — — (691 ) — — Fair value of plan assets at end of period 12 — 248 15 — 253 Amount underfunded (overfunded) at end of period $ 6 $ 51 $ (83 ) $ 5 $ 57 $ (73 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 108 $ — $ — $ 97 Current liabilities — (7 ) (2 ) — (9 ) (2 ) Non-current liabilities (6 ) (44 ) (23 ) (5 ) (48 ) (22 ) $ (6 ) $ (51 ) $ 83 $ (5 ) $ (57 ) $ 73 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain $ — $ — $ (12 ) $ 2 $ 4 $ (17 ) Prior service cost — — 14 — — 15 $ — $ — $ 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 $ 165 20 57 $ 180 Fair value of plan assets 12 — 248 15 — 253 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 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 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 approximately 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 approximately 100% equities as of December 31, 2015 . The fair value of 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) 134 134 — — Fixed income securities 91 — 91 — Total $ 248 $ 157 $ 91 $ — (1) Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016 . 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) 133 133 — — Fixed income securities 102 — 102 — Total $ 253 $ 151 $ 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 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 (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS: ETE has agreements with subsidiaries to provide or receive various general and administrative services. ETE pays us to provide services on its behalf and on behalf of other subsidiaries of ETE, which includes the reimbursement of various operating and general and administrative expenses incurred by us on behalf of ETE and its subsidiaries. In January 2016, ETE and ETP agreed to extend the $95 million annual management fee paid to ETP through 2016. The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. The following table summarizes the affiliate revenues on our consolidated statements of operations: Years Ended December 31, 2016 2015 2014 Affiliated revenues $ 377 $ 417 $ 965 The following table summarizes the related company balances on our consolidated balance sheets: December 31, 2016 2015 Accounts receivable from related companies: ETE $ 22 $ 110 Sunoco LP 96 3 PES 6 10 FGT 15 13 Lake Charles LNG 4 36 Trans-Pecos Pipeline, LLC 1 29 Comanche Trail Pipeline, LLC — 22 Other 65 45 Total accounts receivable from related companies $ 209 $ 268 Accounts payable to related companies: ETE $ — $ 1 Sunoco LP 20 5 FGT 1 1 Lake Charles LNG 3 3 Other 19 15 Total accounts payable to related companies $ 43 $ 25 December 31, 2016 2015 Long-term notes receivable (payable) – related companies: Sunoco LP $ 87 $ (233 ) Phillips 66 (250 ) — Net long-term notes receivable (payable) – related companies $ (163 ) $ (233 )

Reportable Segments (Notes)

Reportable Segments (Notes)	12 Months Ended
	Dec. 31, 2016
Reportable Segments [Abstract]
REPORTABLE SEGMENTS	REPORTABLE SEGMENTS: Our financial statements currently reflect the following reportable segments, which conduct their business in the United States, as follows: • intrastate transportation and storage; • interstate transportation and storage; • midstream; • liquids transportation and services; • investment in Sunoco Logistics; and • all other. The Partnership previously presented its retail marketing business as a separate reportable segment. Due to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP. As of December 31, 2016 , the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 44.3% of Sunoco LP’s total outstanding common units. This equity method investment in Sunoco LP has now been aggregated into the all other segment. Consequently, the retail marketing business that was previously consolidated has also been aggregated in the all other segment for all periods presented. Intersegment and intrasegment transactions are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our liquids transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our investment in Sunoco Logistics segment are primarily reflected in crude sales. Revenues from our all other segment are primarily reflected in refined product sales. We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership. The following tables present financial information by segment: Years Ended December 31, 2016 2015 2014 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,155 $ 1,912 $ 2,645 Intersegment revenues 458 338 212 2,613 2,250 2,857 Interstate transportation and storage: Revenues from external customers 946 1,008 1,057 Intersegment revenues 23 17 15 969 1,025 1,072 Midstream: Revenues from external customers 2,342 2,607 4,770 Intersegment revenues 2,837 2,449 2,053 5,179 5,056 6,823 Liquids transportation and services: Revenues from external customers 4,498 3,247 3,730 Intersegment revenues 299 249 181 4,797 3,496 3,911 Investment in Sunoco Logistics: Revenues from external customers 9,015 10,302 17,920 Intersegment revenues 136 184 168 9,151 10,486 18,088 All other: Revenues from external customers 2,871 15,216 25,353 Intersegment revenues 400 558 465 3,271 15,774 25,818 Eliminations (4,153 ) (3,795 ) (3,094 ) Total revenues $ 21,827 $ 34,292 $ 55,475 Years Ended December 31, 2016 2015 2014 Cost of products sold: Intrastate transportation and storage $ 1,897 $ 1,554 $ 2,169 Midstream 3,381 3,264 4,893 Liquids transportation and services 3,673 2,597 3,166 Investment in Sunoco Logistics 7,658 9,307 17,135 All other 2,942 14,029 24,129 Eliminations (4,157 ) (3,722 ) (3,078 ) Total cost of products sold $ 15,394 $ 27,029 $ 48,414 Years Ended December 31, 2016 2015 2014 Depreciation, depletion and amortization: Intrastate transportation and storage $ 144 $ 129 $ 125 Interstate transportation and storage 207 210 203 Midstream 844 720 569 Liquids transportation and services 156 126 113 Investment in Sunoco Logistics 446 382 296 All other 189 362 363 Total depreciation, depletion and amortization $ 1,986 $ 1,929 $ 1,669 Years Ended December 31, 2016 2015 2014 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 35 $ 32 $ 27 Interstate transportation and storage 193 197 196 Midstream 19 (19 ) 10 Liquids transportation and services 3 (2 ) (3 ) Investment in Sunoco Logistics 34 21 23 All other (225 ) 240 79 Total equity in earnings of unconsolidated affiliates $ 59 $ 469 $ 332 Years Ended December 31, 2016 2015 2014 Segment Adjusted EBITDA: Intrastate transportation and storage $ 613 $ 543 $ 559 Interstate transportation and storage 1,117 1,155 1,212 Midstream 1,133 1,237 1,318 Liquids transportation and services 968 744 591 Investment in Sunoco Logistics 1,233 1,153 971 All other 541 882 1,059 Total Segment Adjusted EBITDA 5,605 5,714 5,710 Depreciation, depletion and amortization (1,986 ) (1,929 ) (1,669 ) Interest expense, net (1,317 ) (1,291 ) (1,165 ) Gains on acquisitions 83 — — Gain on sale of AmeriGas common units — — 177 Impairment losses (813 ) (339 ) (370 ) Losses on interest rate derivatives (12 ) (18 ) (157 ) Non-cash unit-based compensation expense (80 ) (79 ) (68 ) Unrealized gains (losses) on commodity risk management activities (131 ) (65 ) 112 Inventory valuation adjustments 170 (104 ) (473 ) Losses on extinguishments of debt — (43 ) (25 ) Adjusted EBITDA related to discontinued operations — — (27 ) Adjusted EBITDA related to unconsolidated affiliates (946 ) (937 ) (748 ) Equity in earnings from unconsolidated affiliates 59 469 332 Impairment of investment in an unconsolidated affiliate (308 ) — — Other, net 114 20 (36 ) Income from continuing operations before income tax expense (benefit) $ 438 $ 1,398 $ 1,593 December 31, 2016 2015 2014 Assets: Intrastate transportation and storage $ 5,164 $ 4,882 $ 4,983 Interstate transportation and storage 10,833 11,345 10,779 Midstream 18,011 17,111 15,562 Liquids transportation and services 11,296 7,235 4,568 Investment in Sunoco Logistics 18,819 15,423 13,619 All other 6,068 9,177 13,007 Total assets $ 70,191 $ 65,173 $ 62,518 Years Ended December 31, 2016 2015 2014 Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis): Intrastate transportation and storage $ 76 $ 105 $ 169 Interstate transportation and storage 280 860 411 Midstream 1,255 2,172 1,298 Liquids transportation and services 2,316 2,109 427 Investment in Sunoco Logistics 1,739 2,126 2,510 All other 144 795 679 Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis) $ 5,810 $ 8,167 $ 5,494 December 31, 2016 2015 2014 Advances to and investments in unconsolidated affiliates: Intrastate transportation and storage $ 387 $ 406 $ 423 Interstate transportation and storage 2,149 2,516 2,649 Midstream 111 117 138 Liquids transportation and services 29 32 31 Investment in Sunoco Logistics 224 247 226 All other 1,380 1,685 293 Total advances to and investments in unconsolidated affiliates $ 4,280 $ 5,003 $ 3,760

Quarterly Financial Data (Notes

Quarterly Financial Data (Notes)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
QUARTERLY FINANCIAL DATA (UNAUDITED)	QUARTERLY FINANCIAL DATA (UNAUDITED): Summarized unaudited quarterly financial data is presented below. The sum of net income per Limited Partner unit by quarter does not equal the net income per limited partner unit for the year due to the computation of income allocation between the General Partner and Limited Partners and variations in the weighted average units outstanding used in computing such amounts. Quarters Ended March 31 June 30 September 30 December 31 Total Year 2016: Revenues $ 4,481 $ 5,289 $ 5,531 $ 6,526 $ 21,827 Operating income (loss) 614 715 638 (165 ) 1,802 Net income (loss) 376 472 138 (362 ) 624 Common Unitholders’ interest in net income (loss) (67 ) 60 (241 ) (762 ) (1,010 ) Basic net income (loss) per Common Unit $ (0.15 ) $ 0.10 $ (0.49 ) $ (1.47 ) $ (2.06 ) Diluted net income (loss) per Common Unit $ (0.15 ) $ 0.10 $ (0.49 ) $ (1.47 ) $ (2.06 ) Quarters Ended March 31 June 30 September 30 December 31 Total Year 2015: Revenues $ 10,326 $ 11,540 $ 6,601 $ 5,825 $ 34,292 Operating income 608 888 576 187 2,259 Net income 268 839 393 21 1,521 Common Unitholders’ interest in net income (loss) (48 ) 298 59 (327 ) (18 ) Basic net income (loss) per Common Unit $ (0.17 ) $ 0.67 $ 0.11 $ (0.68 ) $ (0.09 ) Diluted net income (loss) per Common Unit $ (0.17 ) $ 0.67 $ 0.10 $ (0.68 ) $ (0.10 ) The three months ended December 31, 2016 and 2015 reflected the unfavorable impacts of $27 million and $120 million , respectively, related to non-cash inventory valuation adjustments primarily in our investment in Sunoco Logistics and all other segments. The three months ended December 31, 2016 and 2015 reflected the recognition of impairment losses of $813 million and $339 million , respectively. Impairment losses in 2016 were primarily related to our PEPL reporting unit, Sea Robin reporting unit and midstream midcontinent operations. In 2015 , impairment losses were primarily related to Lone Star Refinery Services operations and our Transwestern pipeline. The three months ended September 30, 2016 reflected the recognition of a non-cash impairment of our investment in MEP of $308 million in our interstate transportation and storage segment. For certain periods reflected above, distributions paid for the period exceeded net income attributable to partners. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.

Estimates, Significant Accoun24

Estimates, Significant Accounting Policies and Balance Sheet Detials (Policy)	12 Months Ended
	Dec. 31, 2016
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
New Accounting Pronouncements, Policy [Policy Text Block]	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. 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 a material impact on the Partnership’s 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. 2016-17, 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. The 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 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. Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues. Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors. NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer. In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized. We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
Regulatory Accounting - Regulatory Assets and Liabilities	Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information	Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
Accounts Receivable	Accounts Receivable Our midstream, NGL and intrastate transportation and storage operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. Master setoff agreements are put in place with counterparties where appropriate to mitigate risk. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. Our investment in Sunoco Logistics segment extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Based on that review, a letter of credit or other security may be required. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted. We have a diverse portfolio of customers, however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due. We enter into netting arrangements with counterparties to the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
Inventories	Inventories 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 113 104 Spare parts and other 217 270 Total inventories $ 1,712 $ 1,213 During the years ended December 31, 2016 and 2015, the Partnership recorded write-downs of $170 million and $104 million , respectively, on its crude oil, refined products and NGL inventories as a result of declines in the market price of these products. The write-downs were calculated based upon current replacement costs. We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2016, the Partnership recorded a $133 million fixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the liquids transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
Advances to and Investment in Affiliates	Advances to and Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies.
Other Noncurrent Assets [Policy Text Block]	Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2016 2015 Unamortized financing costs (1) $ 3 $ 11 Regulatory assets 86 90 Deferred charges 217 198 Restricted funds 190 192 Long-term affiliated receivable 90 — Other 86 45 Total other non-current assets, net $ 672 $ 536 (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 Disclosure [Text Block]	Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: December 31, 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) $ 5,362 $ (737 ) $ 4,601 $ (554 ) Patents (10 years) 48 (21 ) 48 (16 ) Trade Names (20 years) 66 (22 ) 66 (18 ) Other (1 to 15 years) 2 (2 ) 6 (3 ) Total amortizable intangible assets $ 5,478 $ (782 ) $ 4,721 $ (591 ) Non-amortizable intangible assets: Trademarks — — 291 — Total intangible assets $ 5,478 $ (782 ) $ 5,012 $ (591 ) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2016 2015 2014 Reported in depreciation, depletion and amortization $ 193 $ 216 $ 212 Estimated aggregate amortization expense for the next five years is as follows: Years Ending December 31: 2017 $ 213 2018 213 2019 211 2020 211 2021 211 We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. In 2015, we recorded $24 million of intangible asset impairments related to the liquids transportation and services segment primarily due to an expected decrease in future cash flows.
Goodwill	Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream Liquids Transportation and Services Investment in Sunoco Logistics All Other Total Balance, December 31, 2014 $ 10 $ 1,011 $ 767 $ 432 $ 1,358 $ 4,064 $ 7,642 Reduction due to Sunoco LP deconsolidation — — — — — (2,018 ) (2,018 ) Impaired — (99 ) — (106 ) — — (205 ) Other — — (49 ) — — 58 9 Balance, December 31, 2015 10 912 718 326 1,358 2,104 5,428 Acquired — — 177 — 251 — 428 Reduction due to contribution of legacy Sunoco, Inc. retail business — — — — — (1,289 ) (1,289 ) Impaired — (638 ) (32 ) — — — (670 ) Balance, December 31, 2016 $ 10 $ 274 $ 863 $ 326 $ 1,609 $ 815 $ 3,897 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 segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of: (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. Below is a schedule of AROs by segment recorded as other non-current liabilities in ETP’s consolidated balance sheets: December 31, 2016 2015 Interstate transportation and storage $ 54 $ 58 Investment in Sunoco Logistics 88 88 All other 28 66 $ 170 $ 212 Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely. Long-lived assets related to AROs aggregated $14 million and $18 million , and were reflected as property, plant and equipment on our balance sheet as of December 31, 2016 and 2015 , respectively. In addition, the Partnership had $13 million and $6 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2016 and 2015, respectively.
Accrued and Other Current Liabilities	Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: December 31, 2016 2015 Interest payable $ 440 $ 425 Customer advances and deposits 56 95 Accrued capital expenditures 749 743 Accrued wages and benefits 212 218 Taxes payable other than income taxes 63 76 Exchanges payable 208 105 Other 177 386 Total accrued and other current liabilities $ 1,905 $ 2,048 Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Redeemable Noncontrolling Interest [Text Block]	Redeemable Noncontrolling Interests The noncontrolling interest holders in one of 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 ETP’s consolidated balance sheet.
Environmental Costs, Policy [Policy Text Block]	Environmental Remediation We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2016 was $33.85 billion and $32.93 billion , respectively. As of December 31, 2015 , the aggregate fair value and carrying amount of our debt obligations was $25.71 billion and $28.68 billion , respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. 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	Contributions in Aid of Construction Costs On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs	Shipping and Handling Costs Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.
Costs and Expenses	Costs and Expenses Costs of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel. We record the collection of taxes to be remitted to government authorities on a net basis except for our all other segment in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). For the year ended December 31, 2016 , due to the dropdown of our retail assets to Sunoco LP, no excise taxes were collected. For the years ended December 31, 2015 and 2014 , excise taxes collected by our all other segment were $1.85 billion and $2.46 billion , respectively.
Consolidation, Subsidiary Stock Issuances, Policy [Policy Text Block]	Issuances of Subsidiary Units We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.
Income Tax, Policy [Policy Text Block]	Income Taxes ETP is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”). As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETP would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 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 and until July 31, 2015, Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques. At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period. If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations. Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]	Unit-Based Compensation For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pension and Other Postretirement Plans, Policy [Policy Text Block]	Pensions and Other Postretirement Benefit Plans 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, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.

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Estimates, Significant Accounting Policies and Balance Sheet Detials (Tables)	12 Months Ended
	Dec. 31, 2016
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Net change in operating assets and liabilities (net of acquisitions)	The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2016 2015 2014 Accounts receivable $ (919 ) $ 819 $ 600 Accounts receivable from related companies 30 (243 ) (22 ) Inventories (368 ) (351 ) 51 Other current assets 83 (178 ) 150 Other non-current assets, net (78 ) 188 (6 ) Accounts payable 972 (1,215 ) (851 ) Accounts payable to related companies 29 (160 ) 3 Accrued and other current liabilities 39 (83 ) (191 ) Other non-current liabilities 33 (219 ) (73 ) Price risk management assets and liabilities, net 62 75 19 Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (117 ) $ (1,367 ) $ (320 )
Non-cash investing and financing activities and supplemental cash flow information	Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2016 2015 2014 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 822 $ 896 $ 643 Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP 194 — — Net gains from subsidiary common unit transactions 37 300 175 NON-CASH FINANCING ACTIVITIES: Issuance of Common Units in connection with the PennTex Acquisition $ 307 $ — $ — Issuance of Common Units in connection with the Regency Merger — 9,250 — Issuance of Class H Units in connection with the Bakken Pipeline Transaction — 1,946 — Issuance of Common Units in connection with the Susser Merger — — 908 Contribution of property, plant and equipment from noncontrolling interest — 34 — Long-term debt assumed and non-compete agreement notes payable issued in acquisitions — — 564 Predecessor equity issuances of common units in connection with Regency’s acquisitions — — 4,281 Long-term debt assumed or exchanged in Regency’s acquisitions — — 2,386 Redemption of Common Units in connection with the Bakken Pipeline Transaction — 999 — Redemption of Common Units in connection with the Sunoco LP Exchange — 52 — Redemption of Common Units in connection with the Lake Charles LNG Transaction — — 1,167 SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 1,411 $ 1,467 $ 1,232 Cash paid for (refund of) income taxes (229 ) 71 344
Inventory	Inventories consisted of the following: December 31, 2016 2015 Natural gas and NGLs $ 699 $ 415 Crude oil 683 424 Refined products 113 104 Spare parts and other 217 270 Total inventories $ 1,712 $ 1,213
Other Current Assets	Other current assets consisted of the following: December 31, 2016 2015 Deposits paid to vendors $ 74 $ 74 Income taxes receivable 128 291 Prepaid expenses and other 224 167 Total other current assets $ 426 $ 532
Components and useful lives of property, plant and equipment	Components and useful lives of property, plant and equipment were as follows: December 31, 2016 2015 Land and improvements $ 659 $ 686 Buildings and improvements (1 to 45 years) 1,784 1,526 Pipelines and equipment (5 to 83 years) 35,923 33,148 Natural gas and NGL storage facilities (5 to 46 years) 1,515 391 Bulk storage, equipment and facilities (2 to 83 years) 3,677 2,853 Retail equipment (2 to 99 years) — 401 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) 517 743 Construction work-in-process 10,096 7,844 58,220 50,869 Less – Accumulated depreciation and depletion (7,303 ) (5,782 ) Property, plant and equipment, net $ 50,917 $ 45,087
Depreciation expense	We recognized the following amounts for the periods presented: Years Ended December 31, 2016 2015 2014 Depreciation and depletion expense $ 1,793 $ 1,713 $ 1,457 Capitalized interest, excluding AFUDC 200 163 101
Other non-current assets	Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization.
Components and useful lives of intangibles assets	Components and useful lives of intangible assets were as follows: December 31, 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) $ 5,362 $ (737 ) $ 4,601 $ (554 ) Patents (10 years) 48 (21 ) 48 (16 ) Trade Names (20 years) 66 (22 ) 66 (18 ) Other (1 to 15 years) 2 (2 ) 6 (3 ) Total amortizable intangible assets $ 5,478 $ (782 ) $ 4,721 $ (591 ) Non-amortizable intangible assets: Trademarks — — 291 — Total intangible assets $ 5,478 $ (782 ) $ 5,012 $ (591 )
Amortization expense of intangible assets	Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2016 2015 2014 Reported in depreciation, depletion and amortization $ 193 $ 216 $ 212
Amortization expense, expected	Estimated aggregate amortization expense for the next five years is as follows: Years Ending December 31: 2017 $ 213 2018 213 2019 211 2020 211 2021 211
Changes in carrying amount of goodwill	Changes in the carrying amount of goodwill were as follows: Intrastate Transportation and Storage Interstate Transportation and Storage Midstream Liquids Transportation and Services Investment in Sunoco Logistics All Other Total Balance, December 31, 2014 $ 10 $ 1,011 $ 767 $ 432 $ 1,358 $ 4,064 $ 7,642 Reduction due to Sunoco LP deconsolidation — — — — — (2,018 ) (2,018 ) Impaired — (99 ) — (106 ) — — (205 ) Other — — (49 ) — — 58 9 Balance, December 31, 2015 10 912 718 326 1,358 2,104 5,428 Acquired — — 177 — 251 — 428 Reduction due to contribution of legacy Sunoco, Inc. retail business — — — — — (1,289 ) (1,289 ) Impaired — (638 ) (32 ) — — — (670 ) Balance, December 31, 2016 $ 10 $ 274 $ 863 $ 326 $ 1,609 $ 815 $ 3,897
Schedule of Asset Retirement Obligations [Table Text Block]	Below is a schedule of AROs by segment recorded as other non-current liabilities in ETP’s consolidated balance sheets: December 31, 2016 2015 Interstate transportation and storage $ 54 $ 58 Investment in Sunoco Logistics 88 88 All other 28 66 $ 170 $ 212 Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Accounts payable and accrued liabilities	Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Summary of fair value of financials	The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2016 and 2015 based on inputs used to derive their fair values: Fair Value Total Fair Value Measurements at December 31, 2016 Level 1 Level 2 Level 3 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 14 $ 14 $ — $ — Swing Swaps IFERC 2 — 2 — Fixed Swaps/Futures 96 96 — — Forward Physical Swaps 1 — 1 — Power: Forwards 4 — 4 — Futures 1 1 — — Options – Calls 1 1 — — Natural Gas Liquids – Forwards/Swaps 233 233 — — Refined Products – Futures 1 1 — — Crude – Futures 9 9 — — Total commodity derivatives 362 355 7 — Total assets $ 362 $ 355 $ 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 (17 ) (17 ) — — Crude – Futures (13 ) (13 ) — — Total commodity derivatives (472 ) (464 ) (8 ) — Total liabilities $ (666 ) $ (464 ) $ (201 ) $ (1 ) Fair Value Total Fair Value Measurements at December 31, 2015 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 Swaps 4 — 4 — Power: Forwards 22 — 22 — Futures 3 3 — — Options – Puts 1 1 — — Options – Calls 1 1 — — Natural Gas Liquids – Forwards/Swaps 99 99 — — Refined Products – Futures 9 9 — — Crude – Futures 9 9 — — Total commodity derivatives 448 414 34 — Total assets $ 448 $ 414 $ 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 ) — — Crude – Futures (5 ) (5 ) — — Total commodity derivatives (350 ) (318 ) (32 ) — Total liabilities $ (526 ) $ (318 ) $ (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 %
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	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, Divestitures an26

Acquisitions, Divestitures and Related Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
PennTex Acquisition [Member]
Summary Of Preliminary Assets And Liability Acquired	The total purchase price was allocated as follows: At November 1, 2016 Total current assets $ 34 Property, plant and equipment 393 Goodwill (1) 177 Intangible assets 446 1,050 Total current liabilities 6 Long-term debt, less current maturities 164 Other non-current liabilities 17 Noncontrolling interest 236 423 Total consideration 627 Cash received 21 Total consideration, net of cash received $ 606 (1) None of the goodwill is expected to be deductible for tax purposes. The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Susser Merger [Member]
Summary Of Preliminary Assets And Liability Acquired	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]
Summary Of Preliminary Assets And Liability Acquired	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
PVR Acquisition [Member]
Summary Of Preliminary Assets And Liability Acquired	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. 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.
Sunoco LP and Legacy Sunoco Inc. [Member]
Additional Financial Information Disclosure [Text Block]	Following is a summary of amounts reflected for the prior periods in ETP’s consolidated statements of operations related to Sunoco, LLC and the legacy Sunoco, Inc. retail business, which operations are no longer consolidated for the current period in 2016: Years Ended December 31, 2015 2014 Revenues $ 12,482 $ 22,487 Cost of products sold 11,174 21,155 Operating expenses 798 727 Selling, general and administrative expenses 106 99

Advances to and Investments i27

Advances to and Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2016
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Investments in and Advances to Affiliates [Table Text Block]	The carrying values of the Partnership’s 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 Sunoco LP 1,225 1,380 Others 443 627 Total $ 4,280 $ 5,003
Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block]	Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, AmeriGas, Citrus, FEP, HPC, MEP and Sunoco LP (on a 100% basis) for all periods presented: December 31, 2016 2015 Current assets $ 2,109 $ 1,646 Property, plant and equipment, net 13,355 12,611 Other assets 6,557 5,485 Total assets $ 22,021 $ 19,742 Current liabilities $ 2,547 $ 1,517 Non-current liabilities 12,899 10,428 Equity 6,575 7,797 Total liabilities and equity $ 22,021 $ 19,742 Years Ended December 31, 2016 2015 2014 Revenue $ 19,207 $ 20,961 $ 4,925 Operating income 933 1,620 1,071 Net income 196 894 577 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

Net Income Per Limited Partne28

Net Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Schedule of Earnings Per Unit, Basic and Diluted	The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit. Years Ended December 31, 2016 2015 2014 Income from continuing operations $ 624 $ 1,521 $ 1,235 Less: Income from continuing operations attributable to noncontrolling interest 327 157 116 Less: Loss from continuing operations attributable to predecessor — (34 ) (153 ) Income from continuing operations, net of noncontrolling interest 297 1,398 1,272 General Partner’s interest in income from continuing operations 948 1,064 513 Class H Unitholder’s interest in income from continuing operations 351 258 217 Class I Unitholder’s interest in income from continuing operations 8 94 — Common Unitholders’ interest in income (loss) from continuing operations (1,010 ) (18 ) 542 Additional earnings allocated to General Partner (10 ) (5 ) (4 ) Distributions on employee unit awards, net of allocation to General Partner (19 ) (16 ) (13 ) Income (loss) from continuing operations available to Common Unitholders $ (1,039 ) $ (39 ) $ 525 Weighted average Common Units – basic 505.5 432.8 331.5 Basic income (loss) from continuing operations per Common Unit $ (2.06 ) $ (0.09 ) $ 1.58 Income (loss) from continuing operations available to Common Unitholders $ (1,039 ) $ (39 ) $ 525 Loss attributable to ETP Series A Preferred Units — (6 ) — $ (1,039 ) $ (45 ) $ 525 Weighted average Common Units – basic 505.5 432.8 331.5 Dilutive effect of unvested Unit Awards — — 1.3 Dilutive effect of Preferred Units — 0.7 — Weighted average Common Units – diluted 505.5 433.5 332.8 Diluted income (loss) from continuing operations per Common Unit $ (2.06 ) $ (0.10 ) $ 1.58 Basic income from discontinued operations per Common Unit $ — $ — $ 0.19 Diluted income from discontinued operations per Common Unit $ — $ — $ 0.19

Debt Obligations (Tables)

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Obligations [Abstract]
Debt instruments	Our debt obligations consist of the following: December 31, 2016 2015 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 15, 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 — Other 30 32 32,930 28,679 Less: current maturities 1,189 126 $ 31,741 $ 28,553
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 $64 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: 2017 $ 1,812 2018 1,650 2019 5,045 2020 3,167 2021 1,900 Thereafter 19,420 Total $ 32,994

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Schedule of Capital Units [Table Text Block]	The change in Common Units was as follows: Years Ended December 31, 2016 2015 2014 Number of Common Units, beginning of period 505.6 355.5 333.8 Common Units redeemed in connection with certain transactions (17.8 ) (51.8 ) (18.7 ) Common Units issued in connection with certain acquisitions 8.9 172.2 15.8 Common Units issued in connection with the Distribution Reinvestment Plan 6.6 7.7 2.8 Common Units issued in connection with Equity Distribution Agreements 26.1 21.1 21.4 Issuance of Common Units under equity incentive plans 0.5 0.9 0.4 Number of Common Units, end of period 529.9 505.6 355.5
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, including distributions on Class I Units: Total Year 2017 $ 626 2018 138 2019 128 Each year beyond 2019 33
Comprehensive Income (Loss) Note [Text Block]	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 — Total AOCI, net of tax $ 8 $ 4
Schedule of taxes related to accumulated other comprehensive income [Table Text Block]	The table below sets forth the tax amounts included in the respective components of other comprehensive income: December 31, 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
ETP [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Distributions declared during the periods presented were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2013 February 7, 2014 February 14, 2014 $ 0.9200 March 31, 2014 May 5, 2014 May 15, 2014 0.9350 June 30, 2014 August 4, 2014 August 14, 2014 0.9550 September 30, 2014 November 3, 2014 November 14, 2014 0.9750 December 31, 2014 February 6, 2015 February 13, 2015 0.9950 March 31, 2015 May 8, 2015 May 15, 2015 1.0150 June 30, 2015 August 6, 2015 August 14, 2015 1.0350 September 30, 2015 November 5, 2015 November 16, 2015 1.0550 December 31, 2015 February 8, 2016 February 16, 2016 1.0550 March 31, 2016 May 6, 2016 May 16, 2016 1.0550 June 30, 2016 August 8, 2016 August 15, 2016 1.0550 September 30, 2016 November 7, 2016 November 14, 2016 1.0550 December 31, 2016 February 7, 2017 February 14, 2017 1.0550
Sunoco Logistics [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Distributions declared during the periods presented 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 [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 Plans31

Unit-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
UNIT-BASED COMPENSATION PLANS	UNIT-BASED COMPENSATION PLANS: ETP Unit-Based Compensation Plan We have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2016 , an aggregate total of 1.8 million ETP Common Units remain available to be awarded under our equity incentive plans. Restricted Units We have granted restricted unit awards to employees that vest over a specified time period, typically a five -year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five -year service vesting requirement. The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2015 4.8 $ 47.61 Awards granted 2.5 35.73 Awards vested (0.8 ) 53.22 Awards forfeited (0.2 ) 48.39 Unvested awards as of December 31, 2016 6.3 41.53 During the years ended December 31, 2016, 2015, and 2014 , the weighted average grant-date fair value per unit award granted was $35.73 , $35.21 and $60.85 , respectively. The total fair value of awards vested was $28 million , $49 million and $26 million , respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2016 , a total of 6.3 million unit awards remain unvested, for which ETP expects to recognize a total of $179 million in compensation expense over a weighted average period of 2.1 years . Cash Restricted Units. The Partnership has also granted cash restricted units, which vest 100% at the end of the third year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting. As of December 31, 2016 , a total of 0.2 million unvested cash restricted units were outstanding. Based on the trading price of ETP Common Units at December 31, 2016 , the Partnership expects to recognize $3 million of unit-based compensation expense related to non-vested cash restricted units over a period of 1.0 year . Sunoco Logistics Unit-Based Compensation Plan Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units, phantom unit awards, unit appreciation rights, unrestricted unit awards and other unit-based awards. Restricted Units Sunoco Logistics has granted restricted unit awards to employees and directors that entitle the grantees to receive Sunoco Logistics common units or, at the discretion of the Sunoco Logistics compensation committee, an amount of cash equivalent to the value of common units upon vesting. Sunoco Logistics’ outstanding restricted unit awards are time-vested grants, the vesting of which occurs over a five-year period, and is conditioned solely upon continued employment or service as of the applicable vesting date. These unit awards entitle the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by Sunoco Logistics during the period the restricted unit is outstanding. The following table summarizes the activity of the Sunoco Logistics restricted unit awards: Number of Sunoco Logistics Units Weighted Average Grant-Date Fair Value Per Sunoco Logistics Unit Unvested awards as of December 31, 2015 2.5 $ 33.16 Awards granted 1.3 23.21 Awards vested (0.5 ) 34.19 Awards forfeited (0.1 ) 33.72 Unvested awards as of December 31, 2016 3.2 28.57 During the years ended December 31, 2016 , 2015 and 2014 , the weighted average grant-date fair value per unit award granted was $23.21 , $29.54 and $41.59 , respectively. The total fair value of restricted unit awards vested for the years ended December 31, 2016 , 2015 and 2014 , was $12 million , $8 million , and $30 million , respectively, based on the market price of Sunoco Logistics’ common units as of the vesting date. As of December 31, 2016 , estimated compensation cost related to non-vested awards not yet recognized was $57 million , and the weighted average period over which this cost is expected to be recognized in expense is 3.0 years .
Activity of the awards granted to employees and non-employee directors	The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2015 4.8 $ 47.61 Awards granted 2.5 35.73 Awards vested (0.8 ) 53.22 Awards forfeited (0.2 ) 48.39 Unvested awards as of December 31, 2016 6.3 41.53
Sunoco Logistics [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
UNIT-BASED COMPENSATION PLANS	The following table summarizes the activity of the Sunoco Logistics restricted unit awards: Number of Sunoco Logistics Units Weighted Average Grant-Date Fair Value Per Sunoco Logistics Unit Unvested awards as of December 31, 2015 2.5 $ 33.16 Awards granted 1.3 23.21 Awards vested (0.5 ) 34.19 Awards forfeited (0.1 ) 33.72 Unvested awards as of December 31, 2016 3.2 28.57

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	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) are summarized as follows: Years Ended December 31, 2016 2015 2014 Current expense (benefit): Federal $ 18 $ (274 ) $ 321 State (35 ) (51 ) 86 Total (17 ) (325 ) 407 Deferred expense (benefit): Federal (173 ) 231 (50 ) State 4 (29 ) 1 Total (169 ) 202 (49 ) Total income tax expense (benefit) from continuing operations $ (186 ) $ (123 ) $ 358
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Historically, our effective 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 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: Years Ended December 31, 2016 2015 2014 Income tax expense at U.S. statutory rate of 35 percent $ 154 $ 490 $ 558 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax (519 ) (515 ) (341 ) Nondeductible goodwill included in the Lake Charles LNG Transaction — — 105 Goodwill impairments 223 — — State income taxes (net of federal income tax effects) (17 ) (37 ) 54 Dividend Received Deduction (15 ) (24 ) — Audit Settlement — (7 ) — Premium on debt retirement — — (10 ) Foreign — — (8 ) Other (12 ) (30 ) — Income tax expense (benefit) from continuing operations $ (186 ) $ (123 ) $ 358
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 $ 380 $ 155 Pension and other postretirement benefits 30 36 Long term debt 32 61 Other 84 142 Total deferred income tax assets 526 394 Valuation allowance (118 ) (121 ) Net deferred income tax assets $ 408 $ 273 Deferred income tax liabilities: Properties, plants and equipment $ (1,054 ) $ (1,305 ) Investment in unconsolidated affiliates (3,728 ) (2,889 ) Trademarks — (112 ) Other (20 ) (49 ) Total deferred income tax liabilities (4,802 ) (4,355 ) Accumulated deferred income taxes $ (4,394 ) $ (4,082 )
Balance Sheet Classification of Deferred Taxes [Table Text Block]	The table below provides a rollforward of the net deferred income tax liability as follows: December 31, 2016 2015 Net deferred income tax liability, beginning of year $ (4,082 ) $ (4,331 ) ETE Acquisition of general partner of Sunoco LP — 490 Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) (460 ) — Tax provision 169 (202 ) Other (21 ) (39 ) Net deferred income tax liability, end of year $ (4,394 ) $ (4,082 )
Schedule of Unrecognized Tax Benefits Rollforward [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 — 20 Additions attributable to tax positions taken in prior years 18 178 — 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

Regulatory Matters, Commitmen33

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Tables)	12 Months Ended
	Dec. 31, 2016
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Operating Leases of Lessee Disclosure [Table Text Block]	We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034 . The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: Years Ended December 31, 2016 2015 2014 Rental expense (1) $ 81 $ 176 $ 159 Less: Sublease rental income (1 ) (16 ) (26 ) Rental expense, net $ 80 $ 160 $ 133 (1) Includes contingent rentals totaling $26 million and $24 million for the years ended December 31, 2015 and 2014 , respectively.
Future Minimum Lease Commitments	Future minimum lease commitments for such leases are: Years Ending December 31: 2017 $ 38 2018 30 2019 28 2020 28 2021 35 Thereafter 133 Future minimum lease commitments 292 Less: Sublease rental income (14 ) Net future minimum lease commitments $ 278
Environmental Exit Costs by Cost [Table Text Block]	The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements. December 31, 2016 2015 Current $ 32 $ 41 Non-current 313 326 Total environmental liabilities $ 345 $ 367

Derivative assets and liabilt34

Derivative assets and liabilties (Tables)	12 Months Ended
	Dec. 31, 2016
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
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 (2,240,000 ) 2017 (939,000 ) 2016-2017 Corn (Bushels) – Futures — — 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	Term Type (1) Notional Amount Outstanding December 31, 2016 December 31, 2015 July 2016 (2) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate $ — $ 200 July 2017 (3) Forward-starting to pay a fixed rate of 3.90% and receive a floating rate 500 300 July 2018 (3) Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200 200 July 2019 (3) Forward-starting to pay a fixed rate of 3.25% and receive a floating rate 200 200 December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 1,200 March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300 300 (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward-starting swaps have terms of 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 terms of 30 years with a mandatory termination date the same as the effective date.
Fair Value of derivative instruments	The following table provides a summary of our derivative assets and liabilities: Fair Value of Derivative Instruments Asset Derivatives Liability Derivatives December 31, 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 24 57 (52 ) (41 ) Interest rate derivatives — — (193 ) (171 ) Embedded derivatives in ETP Preferred Units — — (1 ) (5 ) 362 410 (662 ) (523 ) Total derivatives $ 362 $ 448 $ (666 ) $ (526 )
Offsetting Assets Table Text Block [Table Text Block]	The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 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) 24 57 (52 ) (41 ) Broker cleared derivative contracts Other current assets 338 391 (420 ) (309 ) 362 448 (666 ) (526 ) 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 $ 20 $ 122 $ (324 ) $ (200 )
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	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 )
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Years Ended December 31, 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 )
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 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 (173 ) 23 199 Interest rate derivatives Losses on interest rate derivatives (12 ) (18 ) (157 ) Embedded derivatives Other, net 4 12 3 Total $ (216 ) $ 6 $ 39

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]	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 $ 180 $ 718 $ 65 $ 202 Interest cost 1 2 4 23 2 4 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 51 165 20 57 180 Change in plan assets: Fair value of plan assets at beginning of period 15 — 253 598 — 265 Return on plan assets and other (2 ) — 6 16 — — Employer contributions — — 10 138 — 8 Benefits paid, net (1 ) — (21 ) (46 ) — (20 ) Settlements — — — (691 ) — — Fair value of plan assets at end of period 12 — 248 15 — 253 Amount underfunded (overfunded) at end of period $ 6 $ 51 $ (83 ) $ 5 $ 57 $ (73 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 108 $ — $ — $ 97 Current liabilities — (7 ) (2 ) — (9 ) (2 ) Non-current liabilities (6 ) (44 ) (23 ) (5 ) (48 ) (22 ) $ (6 ) $ (51 ) $ 83 $ (5 ) $ (57 ) $ 73 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain $ — $ — $ (12 ) $ 2 $ 4 $ (17 ) Prior service cost — — 14 — — 15 $ — $ — $ 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 $ 165 20 57 $ 180 Fair value of plan assets 12 — 248 15 — 253
Schedule of Net Benefit Costs [Table Text Block]	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 Settlements — — 32 — Net periodic benefit cost $ 2 $ (3 ) $ 41 $ (3 )
Schedule of Benefit Obligations Assumptions [Table Text Block]	The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 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 Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]	The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: December 31, 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 approximately 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 approximately 100% equities as of December 31, 2015 . The fair value of 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) 134 134 — — Fixed income securities 91 — 91 — Total $ 248 $ 157 $ 91 $ — (1) Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016 . 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) 133 133 — — Fixed income securities 102 — 102 — Total $ 253 $ 151 $ 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]	Panhandle and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: 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

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Schedule Of Related Party Transactions By Related Party [Table Text Block]	The following table summarizes the affiliate revenues on our consolidated statements of operations: Years Ended December 31, 2016 2015 2014 Affiliated revenues $ 377 $ 417 $ 965
Related Party Balances For Period Presented [Table Text Block]	The following table summarizes the related company balances on our consolidated balance sheets: December 31, 2016 2015 Accounts receivable from related companies: ETE $ 22 $ 110 Sunoco LP 96 3 PES 6 10 FGT 15 13 Lake Charles LNG 4 36 Trans-Pecos Pipeline, LLC 1 29 Comanche Trail Pipeline, LLC — 22 Other 65 45 Total accounts receivable from related companies $ 209 $ 268 Accounts payable to related companies: ETE $ — $ 1 Sunoco LP 20 5 FGT 1 1 Lake Charles LNG 3 3 Other 19 15 Total accounts payable to related companies $ 43 $ 25 December 31, 2016 2015 Long-term notes receivable (payable) – related companies: Sunoco LP $ 87 $ (233 ) Phillips 66 (250 ) — Net long-term notes receivable (payable) – related companies $ (163 ) $ (233 )

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2016
Reportable Segments [Abstract]
Reportable segments	The following tables present financial information by segment: Years Ended December 31, 2016 2015 2014 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,155 $ 1,912 $ 2,645 Intersegment revenues 458 338 212 2,613 2,250 2,857 Interstate transportation and storage: Revenues from external customers 946 1,008 1,057 Intersegment revenues 23 17 15 969 1,025 1,072 Midstream: Revenues from external customers 2,342 2,607 4,770 Intersegment revenues 2,837 2,449 2,053 5,179 5,056 6,823 Liquids transportation and services: Revenues from external customers 4,498 3,247 3,730 Intersegment revenues 299 249 181 4,797 3,496 3,911 Investment in Sunoco Logistics: Revenues from external customers 9,015 10,302 17,920 Intersegment revenues 136 184 168 9,151 10,486 18,088 All other: Revenues from external customers 2,871 15,216 25,353 Intersegment revenues 400 558 465 3,271 15,774 25,818 Eliminations (4,153 ) (3,795 ) (3,094 ) Total revenues $ 21,827 $ 34,292 $ 55,475 Years Ended December 31, 2016 2015 2014 Cost of products sold: Intrastate transportation and storage $ 1,897 $ 1,554 $ 2,169 Midstream 3,381 3,264 4,893 Liquids transportation and services 3,673 2,597 3,166 Investment in Sunoco Logistics 7,658 9,307 17,135 All other 2,942 14,029 24,129 Eliminations (4,157 ) (3,722 ) (3,078 ) Total cost of products sold $ 15,394 $ 27,029 $ 48,414 Years Ended December 31, 2016 2015 2014 Depreciation, depletion and amortization: Intrastate transportation and storage $ 144 $ 129 $ 125 Interstate transportation and storage 207 210 203 Midstream 844 720 569 Liquids transportation and services 156 126 113 Investment in Sunoco Logistics 446 382 296 All other 189 362 363 Total depreciation, depletion and amortization $ 1,986 $ 1,929 $ 1,669 Years Ended December 31, 2016 2015 2014 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 35 $ 32 $ 27 Interstate transportation and storage 193 197 196 Midstream 19 (19 ) 10 Liquids transportation and services 3 (2 ) (3 ) Investment in Sunoco Logistics 34 21 23 All other (225 ) 240 79 Total equity in earnings of unconsolidated affiliates $ 59 $ 469 $ 332 Years Ended December 31, 2016 2015 2014 Segment Adjusted EBITDA: Intrastate transportation and storage $ 613 $ 543 $ 559 Interstate transportation and storage 1,117 1,155 1,212 Midstream 1,133 1,237 1,318 Liquids transportation and services 968 744 591 Investment in Sunoco Logistics 1,233 1,153 971 All other 541 882 1,059 Total Segment Adjusted EBITDA 5,605 5,714 5,710 Depreciation, depletion and amortization (1,986 ) (1,929 ) (1,669 ) Interest expense, net (1,317 ) (1,291 ) (1,165 ) Gains on acquisitions 83 — — Gain on sale of AmeriGas common units — — 177 Impairment losses (813 ) (339 ) (370 ) Losses on interest rate derivatives (12 ) (18 ) (157 ) Non-cash unit-based compensation expense (80 ) (79 ) (68 ) Unrealized gains (losses) on commodity risk management activities (131 ) (65 ) 112 Inventory valuation adjustments 170 (104 ) (473 ) Losses on extinguishments of debt — (43 ) (25 ) Adjusted EBITDA related to discontinued operations — — (27 ) Adjusted EBITDA related to unconsolidated affiliates (946 ) (937 ) (748 ) Equity in earnings from unconsolidated affiliates 59 469 332 Impairment of investment in an unconsolidated affiliate (308 ) — — Other, net 114 20 (36 ) Income from continuing operations before income tax expense (benefit) $ 438 $ 1,398 $ 1,593 December 31, 2016 2015 2014 Assets: Intrastate transportation and storage $ 5,164 $ 4,882 $ 4,983 Interstate transportation and storage 10,833 11,345 10,779 Midstream 18,011 17,111 15,562 Liquids transportation and services 11,296 7,235 4,568 Investment in Sunoco Logistics 18,819 15,423 13,619 All other 6,068 9,177 13,007 Total assets $ 70,191 $ 65,173 $ 62,518 Years Ended December 31, 2016 2015 2014 Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis): Intrastate transportation and storage $ 76 $ 105 $ 169 Interstate transportation and storage 280 860 411 Midstream 1,255 2,172 1,298 Liquids transportation and services 2,316 2,109 427 Investment in Sunoco Logistics 1,739 2,126 2,510 All other 144 795 679 Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis) $ 5,810 $ 8,167 $ 5,494 December 31, 2016 2015 2014 Advances to and investments in unconsolidated affiliates: Intrastate transportation and storage $ 387 $ 406 $ 423 Interstate transportation and storage 2,149 2,516 2,649 Midstream 111 117 138 Liquids transportation and services 29 32 31 Investment in Sunoco Logistics 224 247 226 All other 1,380 1,685 293 Total advances to and investments in unconsolidated affiliates $ 4,280 $ 5,003 $ 3,760

Quarterly Financial Data (Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information [Table Text Block]	Quarters Ended March 31 June 30 September 30 December 31 Total Year 2016: Revenues $ 4,481 $ 5,289 $ 5,531 $ 6,526 $ 21,827 Operating income (loss) 614 715 638 (165 ) 1,802 Net income (loss) 376 472 138 (362 ) 624 Common Unitholders’ interest in net income (loss) (67 ) 60 (241 ) (762 ) (1,010 ) Basic net income (loss) per Common Unit $ (0.15 ) $ 0.10 $ (0.49 ) $ (1.47 ) $ (2.06 ) Diluted net income (loss) per Common Unit $ (0.15 ) $ 0.10 $ (0.49 ) $ (1.47 ) $ (2.06 )	Quarters Ended March 31 June 30 September 30 December 31 Total Year 2015: Revenues $ 10,326 $ 11,540 $ 6,601 $ 5,825 $ 34,292 Operating income 608 888 576 187 2,259 Net income 268 839 393 21 1,521 Common Unitholders’ interest in net income (loss) (48 ) 298 59 (327 ) (18 ) Basic net income (loss) per Common Unit $ (0.17 ) $ 0.67 $ 0.11 $ (0.68 ) $ (0.09 ) Diluted net income (loss) per Common Unit $ (0.17 ) $ 0.67 $ 0.10 $ (0.68 ) $ (0.10 )

Operations and Organization (Na

Operations and Organization (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended			12 Months Ended
	Oct. 31, 2015	Jul. 31, 2015	Apr. 30, 2015	Dec. 31, 2016
Payments to Acquire Businesses, Gross	$ 382
Dropdown of Sunoco LLC Interest [Member]
Payments to Acquire Businesses, Gross			$ 775
Business Combination, Consideration Transferred			$ 816
Sunoco LP Exchange [Member]
Stock Repurchased During Period, Shares		21,000,000
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			0.4124
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			172,200,000
Relinquishment of Incentive Distributions				$ 320
ETP Subsidiaries [Member] | Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			15,500,000
ETP Series A Preferred Units [Member] | Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			1,900,000
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

Estimates, Significant Accoun40

Estimates, Significant Accounting Policies and Balance Sheet Detials (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Deferred Tax Liabilities, Gross	$ 4,802	$ 4,355
Tangible Asset Impairment Charges	133	110
ARO Underlying Asset	14	18
Asset Retirement Obligation, Legally Restricted Assets, Fair Value	13	6
Impairment of Intangible Assets, Finite-lived		24
Inventory Write-down	(170)	104
Impairment losses	670	205
Goodwill, Written off Related to Sale of Business Unit	1,289	2,018
Long-term Debt, Fair Value	33,850	25,710
Goodwill acquired	428
Goodwill	3,897	5,428	$ 7,642
Long-term Debt	32,930	28,679
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	$ 0
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives	3 years
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives	46 years
Maximum [Member] | Patents [Member]
Useful Lives	10 years
Interstate Transportation and Storage [Member]
Impairment losses	$ (638)	(99)
Goodwill, Written off Related to Sale of Business Unit	0	0
Goodwill acquired	0
Goodwill	274	912	1,011
Liquids Transportation And Services [Member]
Impairment losses	0	(106)
Goodwill, Written off Related to Sale of Business Unit	0	0
Goodwill acquired	0
Goodwill	326	326	432
Midstream [Member]
Tangible Asset Impairment Charges	10
Impairment losses	(32)	0
Goodwill, Written off Related to Sale of Business Unit	0	0
Goodwill acquired	177
Goodwill	863	718	767
Retail Marketing [Member]
Excise Taxes Collected	$ 0	$ 1,850	$ 2,460

Estimates, Significant Accoun41

Estimates, Significant Accounting Policies and Balance Sheet Detials (Net change in operating assets and liabilities (net of acquisitions) included in cash flows) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Accounts receivable	$ (919)	$ 819	$ 600
Accounts receivable from related companies	30	(243)	(22)
Inventories	(368)	(351)	51
Other current assets	83	(178)	150
Other non-current assets, net	(78)	188	(6)
Accounts payable	972	(1,215)	(851)
Accounts payable to related companies	29	(160)	3
Accrued and other current liabilities	39	(83)	(191)
Other non-current liabilities	33	(219)	(73)
Price risk management assets and liabilities, net	62	75	19
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$ (117)	$ (1,367)	$ (320)

Estimates, Significant Accoun42

Estimates, Significant Accounting Policies and Balance Sheet Detials (Non-cash investing and financing activities and supplemental cash flow information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	$ 822	$ 896	$ 643
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP	194	0	0
Net gains from subsidiary common unit transactions	37	300	175
Contribution of property, plant and equipment from noncontrolling interest	0	34	0
Issuance of Common Units in connection with acquisitions	543
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	0	0	564
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	0	1,946	0
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	1,411	1,467	1,232
Cash paid for (refund of) income taxes		71	344
Proceeds from Income Tax Refunds	(229)
PennTex Acquisition [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Issuance of Common Units in connection with acquisitions		0	0
Regency Merger [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Issuance of Common Units in connection with acquisitions	0	9,250	0
Susser Merger [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Issuance of Common Units in connection with acquisitions	0	0	908
Lake Charles LNG Transaction [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Lake Charles LNG Transaction	0	0	1,167
Predecessor Acquisitions [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Issuance of Common Units in connection with acquisitions	0	0	4,281
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	0	0	2,386
Bakken Pipeline Transaction [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Lake Charles LNG Transaction	0	999	0
Sunoco LP Exchange [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Lake Charles LNG Transaction	$ 0	$ 52	$ 0

Estimates, Significant Accoun43

Estimates, Significant Accounting Policies and Balance Sheet Detials (Inventory) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Natural gas and NGLs	$ 699	$ 415
Crude oil	683	424
Refined products	113	104
Spare parts and other	217	270
Total inventories	$ 1,712	$ 1,213

Estimates, Significant Accoun44

Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Deposits paid to vendors	$ 74	$ 74
Income taxes receivable	128	291
Prepaid expenses and other	224	167
Total other current assets	$ 426	$ 532

Estimates, Significant Accoun45

Estimates, Significant Accounting Policies and Balance Sheet Detials (Components and useful lives of property, plant and equipment) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment, Gross	$ 58,220	$ 50,869
Less - Accumulated depreciation	(7,303)	(5,782)
Property, plant and equipment, net	50,917	45,087
Land and improvements
Property, Plant and Equipment, Gross	659	686
Buildings and improvements (1 to 45 years)
Property, Plant and Equipment, Gross	1,784	1,526
Pipelines and equipment (5 to 83 years)
Property, Plant and Equipment, Gross	35,923	33,148
Natural gas and NGL storage facilities (5 to 46 years)
Property, Plant and Equipment, Gross	1,515	391
Bulk storage, equipment and facilities (2 to 83 years)
Property, Plant and Equipment, Gross	3,677	2,853
Retail equipment (2 to 99 years)
Property, Plant and Equipment, Gross	0	401
Vehicles (1 to 25 years)
Property, Plant and Equipment, Gross	241	220
Right of way (20 to 83 years)
Property, Plant and Equipment, Gross	3,374	2,573
Natural resources
Property, Plant and Equipment, Gross	434	484
Other (1 to 40 years)
Property, Plant and Equipment, Gross	517	743
Construction Work-In-Process [Member]
Property, Plant and Equipment, Gross	$ 10,096	$ 7,844
Minimum [Member] | Buildings and improvements (1 to 45 years)
Property, plant and equipment useful life, minimum in years	1 year
Minimum [Member] | Pipelines and equipment (5 to 83 years)
Property, plant and equipment useful life, minimum in years	5 years
Minimum [Member] | Natural gas and NGL storage facilities (5 to 46 years)
Property, plant and equipment useful life, minimum in years	5 years
Minimum [Member] | Bulk storage, equipment and facilities (2 to 83 years)
Property, plant and equipment useful life, minimum in years	2 years
Minimum [Member] | Tanks and other equipment (5 to 40 years)
Property, plant and equipment useful life, minimum in years	5 years
Minimum [Member] | Retail equipment (2 to 99 years)
Property, plant and equipment useful life, minimum in years	2 years
Minimum [Member] | Vehicles (1 to 25 years)
Property, plant and equipment useful life, minimum in years	1 year
Minimum [Member] | Right of way (20 to 83 years)
Property, plant and equipment useful life, minimum in years	20 years
Minimum [Member] | Furniture and fixtures (2 to 25 years)
Property, plant and equipment useful life, minimum in years
Minimum [Member] | Other (1 to 40 years)
Property, plant and equipment useful life, minimum in years	1 year
Maximum [Member] | Buildings and improvements (1 to 45 years)
Property, plant and equipment useful life, minimum in years	45 years
Maximum [Member] | Pipelines and equipment (5 to 83 years)
Property, plant and equipment useful life, minimum in years	83 years
Maximum [Member] | Natural gas and NGL storage facilities (5 to 46 years)
Property, plant and equipment useful life, minimum in years	46 years
Maximum [Member] | Bulk storage, equipment and facilities (2 to 83 years)
Property, plant and equipment useful life, minimum in years	83 years
Maximum [Member] | Tanks and other equipment (5 to 40 years)
Property, plant and equipment useful life, minimum in years	40 years
Maximum [Member] | Retail equipment (2 to 99 years)
Property, plant and equipment useful life, minimum in years	99 years
Maximum [Member] | Vehicles (1 to 25 years)
Property, plant and equipment useful life, minimum in years	25 years
Maximum [Member] | Right of way (20 to 83 years)
Property, plant and equipment useful life, minimum in years	83 years
Maximum [Member] | Furniture and fixtures (2 to 25 years)
Property, plant and equipment useful life, minimum in years
Maximum [Member] | Other (1 to 40 years)
Property, plant and equipment useful life, minimum in years	40 years

Estimates, Significant Accoun46

Estimates, Significant Accounting Policies and Balance Sheet Detials (Schedule of Property, Plant and Equipment Depreciation and Capitalized Interest Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Depreciation and depletion expense	$ 1,793	$ 1,713	$ 1,457
Capitalized interest, excluding AFUDC	$ 200	$ 163	$ 101

Estimates, Significant Accoun47

Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Non-Current Assets) (Details) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Unamortized financing costs(1)	[1]	$ 3	$ 11
Regulatory assets		86	90
Deferred charges		217	198
Restricted funds		190	192
Long-term affiliated receivable		90	0
Other		86	45
Total other non-current assets, net		$ 672	$ 536
[1]	(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.

Estimates, Significant Accoun48

Estimates, Significant Accounting Policies and Balance Sheet Detials (Intangible assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Gross Carrying Amount	$ 5,478	$ 5,012
Accumulated Amortization	(782)	(591)
Customer relationships, contracts and agreements (3 to 46 years)
Gross Carrying Amount	5,362	4,601
Accumulated Amortization	(737)	(554)
Patents (10 years)
Gross Carrying Amount	48	48
Accumulated Amortization	(21)	(16)
Trade Names (20 years)
Gross Carrying Amount	66	66
Accumulated Amortization	(22)	(18)
Other (1 to 15 years)
Gross Carrying Amount	2	6
Accumulated Amortization	(2)	(3)
Total amortizable intangible assets
Gross Carrying Amount	5,478	4,721
Accumulated Amortization	(782)	(591)
Trademarks
Gross Carrying Amount	0	291
Accumulated Amortization	$ 0	$ 0
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives	46 years
Maximum [Member] | Patents (10 years)
Useful Lives	10 years
Maximum [Member] | Trade Names (20 years)
Useful Lives	20 years
Maximum [Member] | Other (1 to 15 years)
Useful Lives	15 years
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives	3 years
Minimum [Member] | Other (1 to 15 years)
Useful Lives	1 year

Estimates, Significant Accoun49

Estimates, Significant Accounting Policies and Balance Sheet Detials (Amortization expense of intangible assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Depreciation And Amortization [Member]
Reported in depreciation, depletion and amortization	$ 193	$ 216	$ 212

Estimates, Significant Accoun50

Estimates, Significant Accounting Policies and Balance Sheet Detials (Estimated aggregate amortization expense) (Details) $ in Millions	Dec. 31, 2016USD ($)
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
2,017	$ 213
2,018	213
2,019	211
2,020	211
2,021	$ 211

Estimates, Significant Accoun51

Estimates, Significant Accounting Policies and Balance Sheet Detials (Changes in the carrying amount of goodwill) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Goodwill, Beginning Balance	$ 5,428	$ 7,642
Goodwill acquired	428
Impairment losses	(670)	(205)
Goodwill, Written off Related to Sale of Business Unit	(1,289)	(2,018)
Other		9
Goodwill, Ending Balance	3,897	5,428
Intrastate Transportation And Storage [Member]
Goodwill, Beginning Balance	10	10
Goodwill acquired	0
Impairment losses	0	0
Goodwill, Written off Related to Sale of Business Unit	0	0
Other		0
Goodwill, Ending Balance	10	10
Interstate Transportation and Storage [Member]
Goodwill, Beginning Balance	912	1,011
Goodwill acquired	0
Impairment losses	638	99
Goodwill, Written off Related to Sale of Business Unit	0	0
Other		0
Goodwill, Ending Balance	274	912
Midstream [Member]
Goodwill, Beginning Balance	718	767
Goodwill acquired	177
Impairment losses	32	0
Goodwill, Written off Related to Sale of Business Unit	0	0
Other		(49)
Goodwill, Ending Balance	863	718
Liquids Transportation And Services [Member]
Goodwill, Beginning Balance	326	432
Goodwill acquired	0
Impairment losses	0	106
Goodwill, Written off Related to Sale of Business Unit	0	0
Other		0
Goodwill, Ending Balance	326	326
Investment in Sunoco Logistics [Member]
Goodwill, Beginning Balance	1,358	1,358
Goodwill acquired	251
Impairment losses	0	0
Goodwill, Written off Related to Sale of Business Unit	0	0
Other		0
Goodwill, Ending Balance	1,609	1,358
Other Segments [Member]
Goodwill, Beginning Balance	2,104	4,064
Goodwill acquired	0
Impairment losses	0	0
Goodwill, Written off Related to Sale of Business Unit	(1,289)	(2,018)
Other		58
Goodwill, Ending Balance	$ 815	$ 2,104

Estimates, Significant Accoun52

Estimates, Significant Accounting Policies and Balance Sheet Detials (Asset Retirement Obligations) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation	$ 170	$ 212
Interstate Transportation and Storage [Member]
Asset Retirement Obligation	54	58
Investment in Sunoco Logistics [Member]
Asset Retirement Obligation	88	88
Other Segments [Member]
Asset Retirement Obligation	$ 28	$ 66

Estimates, Significant Accoun53

Estimates, Significant Accounting Policies and Balance Sheet Detials (Accrued and Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Other Information [Abstract]
Interest payable	$ 440	$ 425
Customer advances and deposits	56	95
Accrued capital expenditures	749	743
Accrued wages and benefits	212	218
Taxes payable other than income taxes	63	76
Exchanges payable	208	105
Other	177	386
Total accrued and other current liabilities	$ 1,905	$ 2,048

Estimates, Significant Accoun54

Estimates, Significant Accounting Policies and Balance Sheet Detials (Assets and liabilities measured and recorded at fair value on a recurring basis) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	$ 362	$ 448
Assets, Fair Value Disclosure, Recurring	362	448
Interest rate derivatives, Liabilities	(193)	(171)
Embedded derivatives in the ETP Preferred Units	(1)	(5)
Price Risk Derivative Liabilities, at Fair Value	(472)	(350)
Liabilities, Fair Value Disclosure, Recurring	(666)	(526)
Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	233	99
Price Risk Derivative Liabilities, at Fair Value	(273)	(89)
Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	4	22
Price Risk Derivative Liabilities, at Fair Value	(5)	(22)
Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	9
Price Risk Derivative Liabilities, at Fair Value	(17)
Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	3
Price Risk Derivative Liabilities, at Fair Value	(1)	(2)
Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	9	9
Price Risk Derivative Liabilities, at Fair Value	(13)	(5)
Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	4
Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	14	16
Price Risk Derivative Liabilities, at Fair Value	(11)	(16)
Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	2	10
Price Risk Derivative Liabilities, at Fair Value	(3)	(12)
Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	96	274
Price Risk Derivative Liabilities, at Fair Value	(149)	(203)
Options - Puts [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(1)
Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	1
Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	355	414
Assets, Fair Value Disclosure, Recurring	355	414
Interest rate derivatives, Liabilities	0	0
Embedded derivatives in the ETP Preferred Units	0	0
Price Risk Derivative Liabilities, at Fair Value	(464)	(318)
Liabilities, Fair Value Disclosure, Recurring	(464)	(318)
Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	233	99
Price Risk Derivative Liabilities, at Fair Value	(273)	(89)
Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	9
Price Risk Derivative Liabilities, at Fair Value	(17)
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	3
Price Risk Derivative Liabilities, at Fair Value	(1)	(2)
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	9	9
Price Risk Derivative Liabilities, at Fair Value	(13)	(5)
Fair Value, Inputs, Level 1 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Fair Value, Inputs, Level 1 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	14	16
Price Risk Derivative Liabilities, at Fair Value	(11)	(16)
Fair Value, Inputs, Level 1 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	2
Price Risk Derivative Liabilities, at Fair Value	0	(2)
Fair Value, Inputs, Level 1 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	96	274
Price Risk Derivative Liabilities, at Fair Value	(149)	(203)
Fair Value, Inputs, Level 1 [Member] | Options - Puts [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(1)
Fair Value, Inputs, Level 1 [Member] | Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	1
Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	7	34
Assets, Fair Value Disclosure, Recurring	7	34
Interest rate derivatives, Liabilities	(193)	(171)
Embedded derivatives in the ETP Preferred Units	0	0
Price Risk Derivative Liabilities, at Fair Value	(8)	(32)
Liabilities, Fair Value Disclosure, Recurring	(201)	(203)
Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	4	22
Price Risk Derivative Liabilities, at Fair Value	(5)	(22)
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	4
Fair Value, Inputs, Level 2 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	2	8
Price Risk Derivative Liabilities, at Fair Value	(3)	(10)
Fair Value, Inputs, Level 2 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Options - Puts [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Inputs, Level 2 [Member] | Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Fair Value, Inputs, Level 3 [Member]
Liabilities, Fair Value Disclosure, Recurring	(1)
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Assets, Fair Value Disclosure, Recurring	0	0
Interest rate derivatives, Liabilities	0	0
Embedded derivatives in the ETP Preferred Units	(1)	(5)
Price Risk Derivative Liabilities, at Fair Value	0	0
Liabilities, Fair Value Disclosure, Recurring	(1)	(5)
Fair Value, Inputs, Level 3 [Member] | Forward Swaps [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 3 [Member] | Forward Swaps [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 3 [Member] | Future [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0
Fair Value, Inputs, Level 3 [Member] | Future [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 3 [Member] | Future [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 3 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Fair Value, Inputs, Level 3 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 3 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 3 [Member] | Options - Puts [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Inputs, Level 3 [Member] | Options - Calls [Member] | Commodity Derivatives - Power [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	$ 0	$ 0

Estimates, Significant Accoun55

Estimates, Significant Accounting Policies and Balance Sheet Detials (Unobservable Inputs and Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Amount of Gain (Loss) Recognized In Income On Derivatives	$ (216)	$ 6	$ 39
Fair Value, Embedded Derivatives, Significant Unobservable Input, Volatility	31.73%
Fair Value Embedde Derivatives, Significant Unobservable Input, Credit Spread	5.12%
Fair Value, Measurements, Recurring [Member]
Liabilities, Fair Value Disclosure, Recurring	$ (666)	(526)
Fair Value, Inputs, Level 3 [Member]
Liabilities, Fair Value Disclosure, Recurring	(1)
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value		5
Liabilities, Fair Value Disclosure, Recurring	(1)	(5)
Embedded Derivatives in Preferred Units [Member] | Other Income (Expenses) [Member]
Amount of Gain (Loss) Recognized In Income On Derivatives	$ 4	$ 12	$ 3

Estimates, Significant Accoun56

Estimates, Significant Accounting Policies and Balance Sheet Detials (Costs and expenses) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Retail Marketing [Member]
Excise Taxes Collected	$ 0	$ 1,850	$ 2,460

Acquisitions, Divestitures an57

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

1 Months Ended

12 Months Ended

Feb. 28, 2017

Nov. 30, 2016USD ($)barrels

Aug. 31, 2016USD ($)

Apr. 30, 2016

Mar. 31, 2016USD ($)shares

Oct. 31, 2015USD ($)

Dec. 31, 2013

Dec. 31, 2016USD ($)

Nov. 01, 2016USD ($)

Aug. 01, 2016

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Business Acquisition [Line Items]

Property, Plant and Equipment, Net

$ 50,917,000,000

$ 45,087,000,000

Payments to Acquire Businesses, Gross

$ 382,000,000

Goodwill

3,897,000,000

5,428,000,000

$ 7,642,000,000

Intangible assets, net

4,696,000,000

4,421,000,000

Pending SXL and ETP Merger [Member]

Business Acquisition [Line Items]

Conversion Rate of Units in Merger, Per Unit

1.5

PennTex Acquisition [Member]

Business Acquisition [Line Items]

Business Acquisition, Goodwill, Expected Tax Deductible Amount

$ 0

Total consideration, net of cash received

$ 606,000,000

Business Combination, Consideration Transferred

$ 627,000,000

Vitol Acquisition [Member]

Business Acquisition [Line Items]

Total consideration, net of cash received

769,000,000

Net Working Capital

13,000,000

Property, Plant and Equipment, Net

286,000,000

Business Combination, Consideration Transferred

760,000,000

Goodwill

251,000,000

Intangible assets, net

$ 313,000,000

Crude Oil Terminal, Capacity, Bbls | barrels

2

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%

Bakken Holdings Company LLC [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

40.00%

Legacy Sunoco, Inc. [Member]

Business Acquisition [Line Items]

Goodwill

1,290,000,000

Intangible assets, net

294,000,000

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

Business Acquisition [Line Items]

Line of Credit Facility, Maximum Borrowing Capacity

2,500,000,000

Bayou Bridge Pipeline LLC [Member] | ETP and Sunoco Logistics [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

30.00%

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%

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%

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] | Dakota Access and ETCOC [Member] | Phillips 66 Company [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

25.00%

Subsequent Event [Member] | Dakota Access and ETCOC [Member] | Bakken Pipeline Investments LLC [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

75.00%

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

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

25.00%

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

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

38.25%

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

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

36.75%

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

Business Acquisition [Line Items]

Revolving credit facilities

$ 1,100,000,000

$ 0

Acquisitions, Divestitures an58

Acquisitions, Divestitures and Related Transactions (2015 Transactions) (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 ($)shares

Dec. 31, 2015USD ($)shares

Dec. 31, 2014USD ($)shares

Sep. 30, 2015shares

Jun. 30, 2015USD ($)

Dec. 31, 2011shares

Business Acquisition [Line Items]

Payments to Acquire Businesses, Gross

$ 382

Partners' Capital Account, Units, Redeemed | shares

17,800,000

51,800,000

18,700,000

Goodwill

$ 3,897

$ 5,428

$ 7,642

Intangible assets, net

$ 4,696

$ 4,421

Equity Method Investment, Ownership Percentage

44.30%

Partners' Capital Account, Units | shares

529,900,000

505,600,000

355,500,000

333,800,000

Class H Units

Business Acquisition [Line Items]

Partners' Capital Account, Units | shares

50,200,000

50,200,000

Allocation of Profits, Losses and Other by Sunoco, Percent

90.05%

Class B Units [Member]

Business Acquisition [Line Items]

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

9,400,000

Regency Merger [Member]

Business Acquisition [Line Items]

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

0.4124

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

172,200,000

Relinquishment of Incentive Distributions

$ 320

Dropdown of Sunoco LLC Interest [Member]

Business Acquisition [Line Items]

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

31.58%

Business Combination, Consideration Transferred

$ 816

Gallons of motor fuel distributed | gallons

5.3

Payments to Acquire Businesses, Gross

$ 775

Equity Issued in Business Combination, Fair Value Disclosure

$ 41

Dropdown of Susser [Member]

Business Acquisition [Line Items]

Payments to Acquire Businesses, Gross

$ 970

Business Combination, Consideration Transferred, Equity Interests Issued and Issuable

$ 970

Sunoco LP Exchange [Member]

Business Acquisition [Line Items]

Stock Repurchased During Period, Shares | shares

21,000,000

IDR Subsidies

$ 35

Term of IDR Subsidy

10 years

Bakken Pipeline Transaction [Member]

Business Acquisition [Line Items]

Business Combination, Consideration Transferred

$ 879

Partners' Capital Account, Units, Redeemed | shares

30,800,000

Class I Distributions

$ 55

30

Bakken Pipeline Transaction [Member] | Class H Units

Business Acquisition [Line Items]

Partners' Capital Account, Units, Redeemed | shares

30,800,000

Allocation of Profits, Losses and Other by Sunoco, Percent

90.05%

90.05%

Bakken Pipeline Transaction [Member] | Class I Units

Business Acquisition [Line Items]

Partners' Capital Account, Units | shares

100

100

Susser [Member] | Dropdown of Susser [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

100.00%

Sunoco LP [Member]

Business Acquisition [Line Items]

Goodwill

$ 1,810

Intangible assets, net

$ 982

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

Business Acquisition [Line Items]

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

22,000,000

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

Business Acquisition [Line Items]

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

79,308

Legacy Sunoco, Inc. [Member]

Business Acquisition [Line Items]

Goodwill

1,290

Intangible assets, net

294

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

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

45.00%

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

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

100.00%

Bakken Holdings Company LLC [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

40.00%

Dakota Access and ETCOC [Member]

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

75.00%

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

Business Acquisition [Line Items]

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

10,900,000

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

Business Acquisition [Line Items]

Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest

60.00%

ETP Subsidiaries [Member] | Regency Merger [Member]

Business Acquisition [Line Items]

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

15,500,000

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

Business Acquisition [Line Items]

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

1,900,000

Common Units | Sunoco LP [Member]

Business Acquisition [Line Items]

Investment Owned, Balance, Shares | shares

37,800,000

Relinquishment, Year 1 [Member] | Regency Merger [Member]

Business Acquisition [Line Items]

Relinquishment of Incentive Distributions

80

Relinquishment, Years 2 through 5 [Member] | Regency Merger [Member]

Business Acquisition [Line Items]

Relinquishment of Incentive Distributions

$ 60

Acquisitions, Divestitures an59

Acquisitions, Divestitures and Related Transactions (2014 Narrative) (Details)	Jan. 12, 2012shares	Oct. 31, 2015USD ($)	Oct. 31, 2014USD ($)shares	Aug. 31, 2014USD ($)shares	Mar. 21, 2014USD ($)$ / sharesshares	Feb. 28, 2014USD ($)shares	Apr. 30, 2013shares	Dec. 31, 2016USD ($)	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 ($)shares	Dec. 31, 2014USD ($)shares	Feb. 01, 2017	Oct. 01, 2014	Aug. 29, 2014USD ($)	Jul. 01, 2014USD ($)	Jan. 10, 2014shares
Business Acquisition [Line Items]
Revenues								$ 6,526,000,000	$ 5,531,000,000	$ 5,289,000,000	$ 4,481,000,000	$ 5,825,000,000	$ 6,601,000,000	$ 11,540,000,000	$ 10,326,000,000	$ 21,827,000,000	$ 34,292,000,000	$ 55,475,000,000
Net income								$ (362,000,000)	$ 138,000,000	$ 472,000,000	$ 376,000,000	$ 21,000,000	$ 393,000,000	$ 839,000,000	$ 268,000,000	624,000,000	1,521,000,000	1,299,000,000
Payments to Acquire Businesses, Gross		$ 382,000,000
Partners' Capital Account, Sale of Units																$ 1,098,000,000	$ 1,428,000,000	$ 1,382,000,000
Partners' Capital Account, Units, Redeemed | shares																17,800,000	51,800,000	18,700,000
Goodwill, Written off Related to Sale of Business Unit																$ (1,289,000,000)	$ (2,018,000,000)
Related Party Transaction, Amounts of Transaction																75,000,000
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP																194,000,000	0	$ 0
Number of Regency Common Units to be Issued in Acquisition Per Share | shares					1.02
Susser Merger [Member]
Business Acquisition [Line Items]
Business Acquisition, Goodwill, Expected Tax Deductible Amount																					$ 0
Payments to Acquire Businesses, Gross				$ 1,800,000,000
Business Combination, Consideration Transferred				$ 875,000,000
Number of Stores																					630
Total current assets																					$ 446,000,000
Property, plant and equipment																					1,069,000,000
Intangible assets																					611,000,000
Other non-current assets																					17,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets																					3,877,000,000
Total current liabilities																					377,000,000
Long-term debt, less current maturities																					564,000,000
Deferred income taxes																					488,000,000
Other non-current liabilities																					39,000,000
Noncontrolling interest																					626,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities																					2,094,000,000
Total consideration																					1,783,000,000
Cash received																					67,000,000
Total consideration, net of cash received																					$ 1,716,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares				15,800,000
MACS Transaction [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred			$ 768,000,000
Lake Charles LNG Transaction [Member]
Business Acquisition [Line Items]
Partners' Capital Account, Units, Redeemed | shares						18,700,000
Goodwill, Written off Related to Sale of Business Unit						$ 184,000,000
Indefinite-lived Intangible Assets, Written off Related to Sale of Business Unit						$ 50,000,000
Sunoco LP [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred			$ 556,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares			4,000,000	11,000,000
PVR Acquisition [Member]
Business Acquisition [Line Items]
Business Acquisition, Goodwill, Expected Tax Deductible Amount					$ 0
Revenues					956,000,000
Net income					166,000,000
Total current assets					149,000,000
Property, plant and equipment					2,716,000,000
Intangible assets					2,717,000,000
Other non-current assets					18,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets					6,032,000,000
Total current liabilities					168,000,000
Long-term debt, less current maturities					1,788,000,000
Other non-current liabilities					30,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities					2,085,000,000
Total consideration					3,947,000,000
Eagle Rock Midstream Acquisition [Member]
Business Acquisition [Line Items]
Revenues																903,000,000
Net income																$ 30,000,000
Total current assets																						$ 120,000,000
Property, plant and equipment																						1,295,000,000
Other non-current assets																						4,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets																						1,468,000,000
Total current liabilities																						116,000,000
Long-term debt, less current maturities																						499,000,000
Other non-current liabilities																						12,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities																						627,000,000
Total consideration, net of cash received																						$ 841,000,000
Sunoco LP [Member]
Business Acquisition [Line Items]
Partners' Capital Account, Sale of Units																		$ 405,000,000
Partners' Capital Account, Units, Sale of Units | shares																		9,100,000
AmeriGas [Member]
Business Acquisition [Line Items]
Debt instrument interest rate																			7.00%
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	29,600,000
ETP [Member]
Business Acquisition [Line Items]
Debt instrument interest rate								6.50%								6.50%
Regency | PVR Acquisition [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross					36,000,000
Business Combination, Consideration Transferred					$ 5,700,000,000
Business Acquisition, Share Price | $ / shares					$ 27.82
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP					$ 1,800,000,000
Regency | Eagle Rock Midstream Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred																$ 1,300,000,000
Proceeds from Issuance of Common Stock																$ 400,000,000
Stock Issued During Period, Shares, Acquisitions | shares																8,200,000
Susser [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs																	25,000,000
Revenues																	2,320,000,000
Net income																	$ 105,000,000
Incentive Distribution Rights																					100.00%
Common Units | Regency | SUGS Contribution [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares							31,400,000
Class F Units [Member] | Regency | SUGS Contribution [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares							6,300,000
Panhandle [Member] | ETP [Member]
Business Acquisition [Line Items]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | shares																							2,200,000
8.375% Senior Notes due June 1, 2019 [Member] | Regency
Business Acquisition [Line Items]
Senior Notes								$ 499,000,000								$ 499,000,000
Company-operated [Member] | MACS Transaction [Member]
Business Acquisition [Line Items]
Number of Stores																				110
Dealer-operated [Member] | MACS Transaction [Member]
Business Acquisition [Line Items]
Number of Stores																				200
7.60% Senior Notes due February 1, 2024
Business Acquisition [Line Items]
Debt instrument interest rate																							7.60%
8.25% Senior Notes due November 15, 2029
Business Acquisition [Line Items]
Debt instrument interest rate																							8.25%

Acquisitions, Divestitures an60

Acquisitions, Divestitures and Related Transactions (Summary of Preliminary Assets And LiabilityAcquired) (Details) - USD ($) $ in Millions		Nov. 01, 2016	Aug. 29, 2014	Jul. 01, 2014	Mar. 21, 2014
Susser Merger [Member]
Business Acquisition [Line Items]
Total current assets			$ 446
Property, plant and equipment			1,069
Intangible assets			611
Goodwill1	[1]		1,734
Other non-current assets			17
Total assets acquired (excluding cash)			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
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities			2,094
Business Combination, Cost of Acquired Entity, Purchase Price			1,783
Total consideration, net of cash received			1,716
Cash received			$ 67
PVR Acquisition [Member]
Business Acquisition [Line Items]
Total current assets					$ 149
Property, plant and equipment					2,716
Investment in unconsolidated affiliates					62
Intangible assets					2,717
Goodwill1					370
Other non-current assets					18
Total assets acquired (excluding cash)					6,032
Total current liabilities					168
Long-term debt, less current maturities					1,788
Premium related to senior notes					99
Other non-current liabilities					30
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities					2,085
Business Combination, Cost of Acquired Entity, Purchase Price					$ 3,947
Eagle Rock Midstream Acquisition [Member]
Business Acquisition [Line Items]
Total current assets				$ 120
Property, plant and equipment				1,295
Goodwill1				49
Other non-current assets				4
Total assets acquired (excluding cash)				1,468
Total current liabilities				116
Long-term debt, less current maturities				499
Other non-current liabilities				12
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities				627
Total consideration, net of cash received				$ 841
PennTex Acquisition [Member]
Business Acquisition [Line Items]
Total current assets		$ 34
Property, plant and equipment		393
Intangible assets		446
Goodwill1		177
Total assets acquired (excluding cash)		1,050
Total current liabilities		6
Long-term debt, less current maturities		164
Other non-current liabilities		17
Noncontrolling interest		236
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities		423
Business Combination, Cost of Acquired Entity, Purchase Price		627
Total consideration, net of cash received		606
Cash received		$ 21
[1]	(1) None of the goodwill is expected to be deductible for tax purposes

Acquisitions, Divestitures an61

Acquisitions, Divestitures and Related Transactions Selected Financial Data (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	$ 6,526	$ 5,531	$ 5,289	$ 4,481	$ 5,825	$ 6,601	$ 11,540	$ 10,326	$ 21,827	$ 34,292	$ 55,475
Cost of products sold (see Note 3)									15,394	27,029	48,414
Operating expenses (see Note 3)									1,484	2,261	2,059
Selling, general and administrative (see Note 3)									$ 348	475	520
Sunoco LP and Legacy Sunoco Inc. [Member]
Revenues										12,482	22,487
Cost of products sold (see Note 3)										11,174	21,155
Operating expenses (see Note 3)										798	727
Selling, general and administrative (see Note 3)										$ 106	$ 99

Advances to and Investments i62

Advances to and Investments in Unconsolidated Affiliates (Narrative) (Details) - USD ($) shares in Millions, $ in Millions	Jan. 12, 2012	Oct. 31, 2015	Jul. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				44.30%
Impairment losses				$ 813	$ 339	$ 370
Payments to Acquire Businesses, Gross		$ 382
Advances to and investments in unconsolidated affiliates				4,280	5,003	3,760
Goodwill				$ 3,897	5,428	7,642
AmeriGas common units sold by ETP				(18.9)
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP				$ 194	$ 0	$ 0
Investments in and Advances to Affiliates, Balance, Shares				43.5
FGT
Schedule of Investments [Line Items]
Percentage Ownership Operating Facility				100.00%
AmeriGas [Member]
Schedule of Investments [Line Items]
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
Citrus [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Business Acquisition, Percentage of Voting Interests Acquired				50.00%
FEP [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
MEP [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Impairment losses				$ 308
RIGS Haynesville Partnership Co. [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				49.99%
Sunoco LP Exchange [Member] | Sunoco GP [Member]
Schedule of Investments [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%

Advances to and Investments i63

Advances to and Investments in Unconsolidated Affiliates (Investments in Unconsolidated Affiliates) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Advances to and investments in unconsolidated affiliates	$ 4,280	$ 5,003	$ 3,760
Citrus [Member]
Schedule of Equity Method Investments [Line Items]
Advances to and investments in unconsolidated affiliates	1,729	1,739
Other Affiliates [Member]
Schedule of Equity Method Investments [Line Items]
Advances to and investments in unconsolidated affiliates	443	627
Sunoco LP [Member]
Schedule of Equity Method Investments [Line Items]
Advances to and investments in unconsolidated affiliates	1,225	1,380
RIGS Haynesville Partnership Co. [Member]
Schedule of Equity Method Investments [Line Items]
Advances to and investments in unconsolidated affiliates	382	402
MEP [Member]
Schedule of Equity Method Investments [Line Items]
Advances to and investments in unconsolidated affiliates	318	660
FEP [Member]
Schedule of Equity Method Investments [Line Items]
Advances to and investments in unconsolidated affiliates	101	115
AmeriGas [Member]
Schedule of Equity Method Investments [Line Items]
Advances to and investments in unconsolidated affiliates	$ 82	$ 80

Advances to and Investments i64

Advances to and Investments in Unconsolidated Affiliates (Summarized Financial Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Investments in and Advances to Affiliates [Line Items]
Revenue	$ 19,207	$ 20,961	$ 4,925
Operating income	933	1,620	1,071
Net income	196	894	$ 577
Current assets	2,109	1,646
Property, plant and equipment, net	13,355	12,611
Other assets	6,557	5,485
Total assets	22,021	19,742
Current liabilities	2,547	1,517
Non-current liabilities	12,899	10,428
Equity	6,575	7,797
Total liabilities and equity	$ 22,021	$ 19,742

Net Income Per Limited Partne65

Net Income Per Limited Partner Unit (A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income from continuing operations	$ 624	$ 1,521	$ 1,235
Less: Income from continuing operations attributable to noncontrolling interest	327	157	116
Less: Net loss attributable to predecessor	0	(34)	(153)
Income from continuing operations, net of noncontrolling interest	297	1,398	1,272
General Partner’s interest in income from continuing operations	(948)	(1,064)	(513)
Class H Unitholder’s interest in income from continuing operations	(351)	(258)	(217)
Class I Unitholder’s interest in income from continuing operations	(8)	(94)	0
Common Unitholders’ interest in income (loss) from continuing operations	(1,010)	(18)	542
Additional earnings allocated to General Partner	(10)	(5)	(4)
Distributions on employee unit awards, net of allocation to General Partner	19	16	13
Income (loss) from continuing operations available to Common Unitholders	(1,039)	(39)	525
Loss attributable to ETP Series A Preferred Units	0	(6)	0
Net Income (Loss) Available to Common Stockholders, Diluted	$ (1,039)	$ (45)	$ 525
Weighted average Common Units – basic	505.5	432.8	331.5
Basic income (loss) from continuing operations per Common Unit	$ (2.06)	$ (0.09)	$ 1.58
Dilutive effect of unvested Unit Awards	0	0	1.3
Dilutive effect of Preferred Units	0	0.7	0
Weighted average Common Units – diluted	505.5	433.5	332.8
Diluted income (loss) from continuing operations per Common Unit	$ (2.06)	$ (0.10)	$ 1.58
Basic income from discontinued operations per Common Unit	0	0	0.19
Diluted income from discontinued operations per Common Unit	$ 0	$ 0	$ 0.19

Debt Obligations (Narrative) (D

Debt Obligations (Narrative) (Details) $ in Millions		1 Months Ended		12 Months Ended
		Feb. 28, 2017USD ($)	Jan. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Feb. 01, 2017	Oct. 05, 2012USD ($)
Unamortized Discounts, Premiums, Fair Value Adjustments and Deferred Debt Issuance Costs				$ (64)
Long-term Debt				32,930	$ 28,679
Proceeds from borrowings				19,916	22,462	$ 15,354
Repayments of Long-term Debt				15,799	17,843	$ 12,702
AmeriGas [Member]
Repayments of Senior Debt		$ 378
Senior note interest rate							7.00%
Sunoco [Member]
Long-term Debt				474	485
ETP [Member]
Long-term Debt				$ 22,067	20,633
Senior note interest rate				6.50%
Senior note maturity date				May 15, 2021
Leverage Ratio Maximum				5
Maximum Leverage Ratio Permitted				5.5
Panhandle [Member]
Long-term Debt				$ 1,135	1,160
Sunoco Logistics [Member]
Long-term Debt				$ 7,313	5,590
Maximum Consolidated EBITDA ratio				5
Adjusted EBITDA Ratio				4.4
Bakken Project [Member]
Long-term Debt				$ 1,087	0
PennTex [Member]
Leverage Ratio Maximum				4.75
Minimum interest coverage ratio				2.50
Bakken Project $2.50 billion Credit Facility due August 2019 [Member]
Minimum debt service coverage ratio				1.20
Acquisition Period [Member] | Sunoco Logistics [Member]
Maximum Consolidated EBITDA ratio				5.5
5.75% Senior Notes due January 15, 2017 | Sunoco [Member]
Senior note principal amount				$ 400	400
Senior note interest rate				5.75%
Senior note maturity date				Jan. 15, 2017
4.40% Senior Notes due April 1, 2021 | Sunoco Logistics [Member]
Senior note principal amount				$ 600	600
Senior note interest rate				4.40%
Senior note maturity date				Apr. 1, 2021
4.25% Senior Notes due April 1, 2024 | Sunoco Logistics [Member]
Senior note principal amount				$ 500	500
Senior note interest rate				4.25%
Senior note maturity date				Apr. 1, 2024
5.30% Senior Notes due April 1, 2044 | Sunoco Logistics [Member]
Senior note principal amount				$ 700	700
Senior note interest rate				5.30%
Senior note maturity date				Apr. 1, 2044
3.45% Senior Notes due January 15, 2023 | Sunoco Logistics [Member]
Senior note principal amount				$ 350	350
Senior note interest rate				3.45%
Senior note maturity date				Jan. 15, 2023
4.95% Senior Notes due January 15, 2043 | Sunoco Logistics [Member]
Senior note principal amount				$ 350	350
Senior note interest rate				4.95%
Senior note maturity date				Jan. 15, 2043
Junior Subordinated Debt [Member] | Variable Rate Portion of Debt [Member] | Panhandle [Member]
Senior note principal amount				$ 54
3.60% Senior Notes due February 1, 2023 | ETP [Member]
Senior note principal amount				$ 800	800
Senior note interest rate				3.60%
Senior note maturity date				Feb. 1, 2023
5.15% Senior Notes due February 1, 2043 | ETP [Member]
Senior note principal amount				$ 450	450
Senior note interest rate				5.15%
Senior note maturity date				Feb. 1, 2043
ETP $3.75 billion Revolving Credit Facility due November 2019 | ETP [Member]
Senior note maturity date				Oct. 27, 2019
5.35% Senior Notes due May 15, 2045 | Sunoco Logistics [Member]
Senior note principal amount				$ 800	800
Senior note interest rate				5.35%
Senior note maturity date				May 15, 2045
5.95% Senior Notes due December 1, 2025 | Sunoco Logistics [Member]
Senior note principal amount				$ 400	400
Senior note interest rate				5.95%
Senior note maturity date				Dec. 1, 2025
ETP $3.75 billion Revolving Credit Facility due November 2019 | ETP [Member]
Revolving credit facility balance outstanding				$ 2,777	1,362
Amount available for future borrowings under the revolving credit facitlity				813
Letters of credit outstanding, amount				160
Commercial Paper				$ 777
Weighted average interest rate on the total amount outstanding				2.20%
Line of Credit Facility, Current Borrowing Capacity				$ 3,750
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETP [Member]
Senior note maturity date				Nov. 1, 2066
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member]
Debt Instrument, Interest Rate Terms				variable rate based upon the three-month LIBOR rate plus 3.0175%
Senior note maturity date				Nov. 1, 2066
Debt Instrument, Interest Rate, Effective Percentage				3.77%
3.90% Senior Notes due July 15, 2026 | Sunoco Logistics [Member]
Senior note principal amount				$ 550	0
Senior note interest rate				3.90%
Senior note maturity date				Jul. 15, 2026
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | Sunoco Logistics [Member]
Revolving credit facility balance outstanding				$ 1,292	562
Commercial Paper				$ 50
Weighted average interest rate on the total amount outstanding				1.76%
Line of Credit Facility, Current Borrowing Capacity				$ 2,500
Line of Credit Facility, Maximum Borrowing Capacity				3,250
Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | Sunoco Logistics [Member]
Revolving credit facility balance outstanding	[1]			630	0
Line of Credit Facility, Current Borrowing Capacity				1,000
Line of Credit Facility, Maximum Borrowing Capacity				1,000
Sunoco Merger [Member]
Senior note principal amount				465				$ 965
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]
Revolving credit facility balance outstanding				$ 1,100	0
Weighted average interest rate on the total amount outstanding				2.13%
Line of Credit Facility, Current Borrowing Capacity				$ 2,500
PennTex $275 million Revolving Credit Facility due December 2019 | PennTex [Member]
Revolving credit facility balance outstanding				168	$ 0
Amount available for future borrowings under the revolving credit facitlity				$ 106
Weighted average interest rate on the total amount outstanding				2.90%
Line of Credit Facility, Current Borrowing Capacity				$ 275
Line of Credit Facility, Maximum Borrowing Capacity				$ 400
Maximum [Member] | PennTex [Member]
Line of Credit Facility, Commitment Fee Percentage				0.50%
Maximum [Member] | Applicable margins for LIBOR rate loans [Member] | PennTex [Member]
Debt Instrument, Basis Spread on Variable Rate				3.25%
Maximum [Member] | Applicable margin for ABR loans [Member] | PennTex [Member]
Debt Instrument, Basis Spread on Variable Rate				2.25%
Minimum [Member] | PennTex [Member]
Line of Credit Facility, Commitment Fee Percentage				0.35%
Minimum [Member] | Applicable margins for LIBOR rate loans [Member] | PennTex [Member]
Debt Instrument, Basis Spread on Variable Rate				2.00%
Minimum [Member] | Applicable margin for ABR loans [Member] | PennTex [Member]
Debt Instrument, Basis Spread on Variable Rate				1.00%
Subsequent Event [Member]
Proceeds from borrowings			$ 1,480
Subsequent Event [Member] | 4.20% Senior Notes due April 2027 [Member]
Senior note principal amount			$ 600
Senior note interest rate			4.20%
Subsequent Event [Member] | 5.30% Senior Notes due April 2047 [Member]
Senior note principal amount			$ 900
Senior note interest rate			5.30%
Subsequent Event [Member] | 5.75% Senior Notes due January 15, 2017 | Sunoco [Member]
Repayments of Long-term Debt			$ 400
[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 Instrume

Debt Obligations (Debt Instruments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Long-term Debt		$ 32,930	$ 28,679
Other		30	32
Less: current maturities		(1,189)	(126)
Long-term debt, less current maturities		31,741	28,553
ETP [Member]
Unamortized premiums, discounts and fair value adjustments, net		(18)	(21)
Deferred Finance Costs, Noncurrent, Net		(132)	(147)
Long-term Debt		$ 22,067	20,633
Debt instrument interest rate		6.50%
Debt instrument maturity date		May 15, 2021
Transwestern [Member]
Unamortized premiums, discounts and fair value adjustments, net		$ 0	(1)
Deferred Finance Costs, Noncurrent, Net		(1)	(2)
Long-term Debt		656	779
Panhandle [Member]
Unamortized premiums, discounts and fair value adjustments, net		50	75
Long-term Debt		1,135	1,160
Sunoco [Member]
Unamortized premiums, discounts and fair value adjustments, net		9	20
Long-term Debt		474	485
Sunoco Logistics [Member]
Unamortized premiums, discounts and fair value adjustments, net		75	85
Deferred Finance Costs, Noncurrent, Net		(34)	(32)
Long-term Debt		7,313	5,590
Bakken Project [Member]
Deferred Finance Costs, Noncurrent, Net		(13)	0
Long-term Debt		1,087	0
6.125% Senior Notes due February 15, 2017 | ETP [Member]
Senior Notes		$ 400	400
Debt instrument interest rate		6.125%
Debt instrument maturity date		Feb. 15, 2017
2.50% Senior Notes due June 15, 2018 | ETP [Member]
Senior Notes		$ 650	650
Debt instrument interest rate		2.50%
Debt instrument maturity date		Jun. 15, 2018
6.70% Senior Notes due July 1, 2018 | ETP [Member]
Senior Notes		$ 600	600
Debt instrument interest rate		6.70%
Debt instrument maturity date		Jul. 1, 2018
9.70% Senior Notes due March 15, 2019 | ETP [Member]
Senior Notes		$ 400	400
Debt instrument interest rate		9.70%
Debt instrument maturity date		Mar. 15, 2019
9.00% Senior Notes due April 15, 2019 | ETP [Member]
Senior Notes		$ 450	450
Debt instrument interest rate		9.00%
Debt instrument maturity date		Apr. 15, 2019
4.15% Senior Notes due October 1, 2020 | ETP [Member]
Senior Notes		$ 1,050	1,050
Debt instrument interest rate		4.15%
Debt instrument maturity date		Oct. 1, 2020
4.65% Senior Notes due June 1, 2021 | ETP [Member]
Senior Notes		$ 800	800
Debt instrument interest rate		4.65%
Debt instrument maturity date		Jun. 1, 2021
5.20% Senior Notes due February 1, 2022 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		5.20%
Debt instrument maturity date		Feb. 1, 2022
3.60% Senior Notes due February 1, 2023 | ETP [Member]
Senior Notes		$ 800	800
Debt instrument interest rate		3.60%
Debt instrument maturity date		Feb. 1, 2023
4.90% Senior Notes due February 1, 2024 | ETP [Member]
Senior Notes		$ 350	350
Debt instrument interest rate		4.90%
Debt instrument maturity date		Feb. 1, 2024
7.60% Senior Notes due February 1, 2024 | ETP [Member]
Senior Notes		$ 277	277
Debt instrument interest rate		7.60%
Debt instrument maturity date		Feb. 1, 2024
7.60% Senior Notes due February 1, 2024 | Panhandle [Member]
Senior Notes		$ 82	82
Debt instrument interest rate		7.60%
Debt instrument maturity date		Feb. 1, 2024
4.05% Senior Notes due March 15, 2025 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		4.05%
Debt instrument maturity date		Mar. 15, 2025
4.75% Senior Notes due January 15, 2026 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		4.75%
Debt instrument maturity date		Jan. 15, 2026
8.25% Senior Notes due November 15, 2029 | ETP [Member]
Senior Notes		$ 267	267
Debt instrument interest rate		8.25%
Debt instrument maturity date		Nov. 15, 2029
8.25% Senior Notes due November 15, 2029 | Panhandle [Member]
Senior Notes		$ 33	33
Debt instrument interest rate		8.25%
Debt instrument maturity date		Nov. 14, 2029
4.90% Senior Notes due March 15, 2035 | ETP [Member]
Senior Notes		$ 500	500
Debt instrument interest rate		4.90%
Debt instrument maturity date		Mar. 15, 2035
6.625% Senior Notes due October 15, 2036 | ETP [Member]
Senior Notes		$ 400	400
Debt instrument interest rate		6.625%
Debt instrument maturity date		Oct. 15, 2036
7.50% Senior Notes due July 1, 2038 | ETP [Member]
Senior Notes		$ 550	550
Debt instrument interest rate		7.50%
Debt instrument maturity date		Jul. 1, 2038
6.05% Senior Notes due June 1, 2041 | ETP [Member]
Senior Notes		$ 700	700
Debt instrument interest rate		6.05%
Debt instrument maturity date		Jun. 1, 2041
6.50% Senior Notes due February 1, 2042 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		6.50%
Debt instrument maturity date		Feb. 1, 2042
5.15% Senior Notes due February 1, 2043 | ETP [Member]
Senior Notes		$ 450	450
Debt instrument interest rate		5.15%
Debt instrument maturity date		Feb. 1, 2043
5.95% Senior Notes due October 1, 2043 | ETP [Member]
Senior Notes		$ 450	450
Debt instrument interest rate		5.95%
Debt instrument maturity date		Oct. 1, 2043
5.15% Senior Notes due March 15, 2045 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		5.15%
Debt instrument maturity date		Mar. 15, 2045
6.125% Senior Notes due December 15, 2045 | ETP [Member]
Senior Notes		$ 1,000	1,000
Debt instrument interest rate		6.125%
Debt instrument maturity date		Dec. 15, 2045
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETP [Member]
Junior Subordinated Notes		$ 546	545
Debt instrument maturity date		Nov. 1, 2066
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member]
Junior Subordinated Notes		$ 54	54
Debt instrument maturity date		Nov. 1, 2066
Debt Instrument, Interest Rate, Effective Percentage		3.77%
ETP $3.75 billion Revolving Credit Facility due November 2019 | ETP [Member]
Revolving credit facilities		$ 2,777	1,362
ETP $3.75 billion Revolving Credit Facility due November 2019 | ETP [Member]
Debt instrument maturity date		Oct. 27, 2019
5.54% Senior Notes due November 17, 2016 | Transwestern [Member]
Senior Notes		$ 0	125
Debt instrument interest rate		5.54%
Debt instrument maturity date		Nov. 17, 2016
5.64% Senior Notes due May 24, 2017 | Transwestern [Member]
Senior Notes		$ 82	82
Debt instrument interest rate		5.64%
Debt instrument maturity date		May 24, 2017
5.36% Senior Notes due December 9, 2020 | Transwestern [Member]
Senior Notes		$ 175	175
Debt instrument interest rate		5.36%
Debt instrument maturity date		Dec. 9, 2020
5.89% Senior Notes due May 24, 2022 | Transwestern [Member]
Senior Notes		$ 150	150
Debt instrument interest rate		5.89%
Debt instrument maturity date		May 24, 2022
5.66% Senior Notes due December 9, 2024 | Transwestern [Member]
Senior Notes		$ 175	175
Debt instrument interest rate		5.66%
Debt instrument maturity date		Dec. 9, 2024
6.16% Senior Notes due May 24, 2037 | Transwestern [Member]
Senior Notes		$ 75	75
Debt instrument interest rate		6.16%
Debt instrument maturity date		May 24, 2037
6.20% Senior Notes due November 1, 2017 | Panhandle [Member]
Senior Notes		$ 300	300
Debt instrument interest rate		6.20%
Debt instrument maturity date		Nov. 1, 2017
7.00% Senior Notes due June 15, 2018 | Panhandle [Member]
Senior Notes		$ 400	400
Debt instrument interest rate		7.00%
Debt instrument maturity date		Jun. 15, 2018
8.125% Senior Notes due June 1, 2019 | Panhandle [Member]
Senior Notes		$ 150	150
Debt instrument interest rate		8.125%
Debt instrument maturity date		Jun. 1, 2019
7.00% Senior Notes due July 15, 2029 | Panhandle [Member]
Senior Notes		$ 66	66
Debt instrument interest rate		7.00%
Debt instrument maturity date		Jul. 15, 2029
5.75% Senior Notes due January 15, 2017 | Sunoco [Member]
Senior Notes		$ 400	400
Debt instrument interest rate		5.75%
Debt instrument maturity date		Jan. 15, 2017
9.00% Debentures due November 1, 2024 | Sunoco [Member]
Subordinated Debt		$ 65	65
Debt instrument interest rate		9.00%
Debt instrument maturity date		Nov. 1, 2024
6.125% Senior Notes due May 15, 2016 | Sunoco Logistics [Member]
Senior Notes		$ 0	175
Debt instrument interest rate		6.125%
Debt instrument maturity date		May 15, 2016
5.50% Senior Notes due February 15, 2020 | Sunoco Logistics [Member]
Senior Notes		$ 250	250
Debt instrument interest rate		5.50%
Debt instrument maturity date		Feb. 15, 2020
4.40% Senior Notes due April 1, 2021 | Sunoco Logistics [Member]
Senior Notes		$ 600	600
Debt instrument interest rate		4.40%
Debt instrument maturity date		Apr. 1, 2021
4.65% Senior Notes due February 15, 2022 | Sunoco Logistics [Member]
Senior Notes		$ 300	300
Debt instrument interest rate		4.65%
Debt instrument maturity date		Feb. 15, 2022
3.45% Senior Notes due January 15, 2023 | Sunoco Logistics [Member]
Senior Notes		$ 350	350
Debt instrument interest rate		3.45%
Debt instrument maturity date		Jan. 15, 2023
4.25% Senior Notes due April 1, 2024 | Sunoco Logistics [Member]
Senior Notes		$ 500	500
Debt instrument interest rate		4.25%
Debt instrument maturity date		Apr. 1, 2024
5.95% Senior Notes due December 1, 2025 | Sunoco Logistics [Member]
Senior Notes		$ 400	400
Debt instrument interest rate		5.95%
Debt instrument maturity date		Dec. 1, 2025
3.90% Senior Notes due July 15, 2026 | Sunoco Logistics [Member]
Senior Notes		$ 550	0
Debt instrument interest rate		3.90%
Debt instrument maturity date		Jul. 15, 2026
6.85% Senior Notes due February 15, 2040 | Sunoco Logistics [Member]
Senior Notes		$ 250	250
Debt instrument interest rate		6.85%
Debt instrument maturity date		Feb. 15, 2040
6.10% Senior Notes due February 15, 2042 | Sunoco Logistics [Member]
Senior Notes		$ 300	300
Debt instrument interest rate		6.10%
Debt instrument maturity date		Feb. 15, 2042
4.95% Senior Notes due January 15, 2043 | Sunoco Logistics [Member]
Senior Notes		$ 350	350
Debt instrument interest rate		4.95%
Debt instrument maturity date		Jan. 15, 2043
5.30% Senior Notes due April 1, 2044 | Sunoco Logistics [Member]
Senior Notes		$ 700	700
Debt instrument interest rate		5.30%
Debt instrument maturity date		Apr. 1, 2044
5.35% Senior Notes due May 15, 2045 | Sunoco Logistics [Member]
Senior Notes		$ 800	800
Debt instrument interest rate		5.35%
Debt instrument maturity date		May 15, 2045
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | Sunoco Logistics [Member]
Revolving credit facilities		$ 1,292	562
5.75% Senior Notes due September 1, 2020 | ETP [Member]
Senior Notes		$ 400	400
Debt instrument interest rate		5.75%
Debt instrument maturity date		Sep. 1, 2020
6.50% Senior Notes due July 15, 2021 | ETP [Member]
Senior Notes		$ 500	500
5.875% Senior Notes due March 1, 2022 | ETP [Member]
Senior Notes		$ 900	900
Debt instrument interest rate		5.875%
Debt instrument maturity date		Mar. 1, 2022
5.00% Senior Notes due October 1, 2022 | ETP [Member]
Senior Notes		$ 700	700
Debt instrument interest rate		5.00%
Debt instrument maturity date		Oct. 1, 2022
5.50% Senior Notes due April 15, 2023 | ETP [Member]
Senior Notes		$ 700	700
Debt instrument interest rate		5.50%
Debt instrument maturity date		Apr. 15, 2023
4.50% Senior Notes due November 1, 2023 | ETP [Member]
Senior Notes		$ 600	600
Debt instrument interest rate		4.50%
Debt instrument maturity date		Nov. 1, 2023
Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | Sunoco Logistics [Member]
Revolving credit facilities	[1]	$ 630	0
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]
Revolving credit facilities		1,100	0
PennTex $275 million Revolving Credit Facility due December 2019 | PennTex [Member]
Revolving credit facilities		$ 168	$ 0
[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 Instrumen

Debt Obligations Debt Instruments (Parenthetical) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
ETP [Member]
Senior note interest rate	6.50%
Debt instrument maturity date	May 15, 2021
Deferred Finance Costs, Noncurrent, Net	$ 132	$ 147
Transwestern [Member]
Deferred Finance Costs, Noncurrent, Net	1	2
Sunoco Logistics [Member]
Deferred Finance Costs, Noncurrent, Net	$ 34	$ 32
4.25% Senior Notes due April 1, 2024 | Sunoco Logistics [Member]
Senior note interest rate	4.25%
Debt instrument maturity date	Apr. 1, 2024
5.95% Senior Notes due December 1, 2025 | Sunoco Logistics [Member]
Senior note interest rate	5.95%
Debt instrument maturity date	Dec. 1, 2025
3.90% Senior Notes due July 15, 2026 | Sunoco Logistics [Member]
Senior note interest rate	3.90%
Debt instrument maturity date	Jul. 15, 2026
6.85% Senior Notes due February 15, 2040 | Sunoco Logistics [Member]
Senior note interest rate	6.85%
Debt instrument maturity date	Feb. 15, 2040
5.30% Senior Notes due April 1, 2044 | Sunoco Logistics [Member]
Senior note interest rate	5.30%
Debt instrument maturity date	Apr. 1, 2044
5.35% Senior Notes due May 15, 2045 | Sunoco Logistics [Member]
Senior note interest rate	5.35%
Debt instrument maturity date	May 15, 2045
6.125% Senior Notes due February 15, 2017 | ETP [Member]
Senior note interest rate	6.125%
Debt instrument maturity date	Feb. 15, 2017
2.50% Senior Notes due June 15, 2018 | ETP [Member]
Senior note interest rate	2.50%
Debt instrument maturity date	Jun. 15, 2018
6.70% Senior Notes due July 1, 2018 | ETP [Member]
Senior note interest rate	6.70%
Debt instrument maturity date	Jul. 1, 2018
9.70% Senior Notes due March 15, 2019 | ETP [Member]
Senior note interest rate	9.70%
Debt instrument maturity date	Mar. 15, 2019
9.00% Senior Notes due April 15, 2019 | ETP [Member]
Senior note interest rate	9.00%
Debt instrument maturity date	Apr. 15, 2019
5.75% Senior Notes due September 1, 2020 | ETP [Member]
Senior note interest rate	5.75%
Debt instrument maturity date	Sep. 1, 2020
4.15% Senior Notes due October 1, 2020 [Member] | ETP [Member]
Senior note interest rate	4.15%
Debt instrument maturity date	Oct. 1, 2020
4.65% Senior Notes due June 1, 2021 | ETP [Member]
Senior note interest rate	4.65%
Debt instrument maturity date	Jun. 1, 2021
5.20% Senior Notes due February 1, 2022 | ETP [Member]
Senior note interest rate	5.20%
Debt instrument maturity date	Feb. 1, 2022
5.875% Senior Notes due March 1, 2022 | ETP [Member]
Senior note interest rate	5.875%
Debt instrument maturity date	Mar. 1, 2022
5.00% Senior Notes due October 1, 2022 | ETP [Member]
Senior note interest rate	5.00%
Debt instrument maturity date	Oct. 1, 2022
3.60% Senior Notes due February 1, 2023 | ETP [Member]
Senior note interest rate	3.60%
Debt instrument maturity date	Feb. 1, 2023
5.50% Senior Notes due April 15, 2023 | ETP [Member]
Senior note interest rate	5.50%
Debt instrument maturity date	Apr. 15, 2023
4.50% Senior Notes due November 1, 2023 | ETP [Member]
Senior note interest rate	4.50%
Debt instrument maturity date	Nov. 1, 2023
4.90% Senior Notes due February 1, 2024 | ETP [Member]
Senior note interest rate	4.90%
Debt instrument maturity date	Feb. 1, 2024
7.60% Senior Notes due February 1, 2024 | ETP [Member]
Senior note interest rate	7.60%
Debt instrument maturity date	Feb. 1, 2024
7.60% Senior Notes due February 1, 2024 | Panhandle [Member]
Senior note interest rate	7.60%
Debt instrument maturity date	Feb. 1, 2024
4.05% Senior Notes due March 15, 2025 | ETP [Member]
Senior note interest rate	4.05%
Debt instrument maturity date	Mar. 15, 2025
4.75% Senior Notes due January 15, 2026 | ETP [Member]
Senior note interest rate	4.75%
Debt instrument maturity date	Jan. 15, 2026
8.25% Senior Notes due November 15, 2029 | ETP [Member]
Senior note interest rate	8.25%
Debt instrument maturity date	Nov. 15, 2029
8.25% Senior Notes due November 15, 2029 | Panhandle [Member]
Senior note interest rate	8.25%
Debt instrument maturity date	Nov. 14, 2029
6.625% Senior Notes due October 15, 2036 | ETP [Member]
Senior note interest rate	6.625%
Debt instrument maturity date	Oct. 15, 2036
4.90% Senior Notes due March 15, 2035 | ETP [Member]
Senior note interest rate	4.90%
Debt instrument maturity date	Mar. 15, 2035
7.50% Senior Notes due July 1, 2038 | ETP [Member]
Senior note interest rate	7.50%
Debt instrument maturity date	Jul. 1, 2038
6.05% Senior Notes due June 1, 2041 | ETP [Member]
Senior note interest rate	6.05%
Debt instrument maturity date	Jun. 1, 2041
6.50% Senior Notes due February 1, 2042 | ETP [Member]
Senior note interest rate	6.50%
Debt instrument maturity date	Feb. 1, 2042
5.15% Senior Notes due February 1, 2043 | ETP [Member]
Senior note interest rate	5.15%
Debt instrument maturity date	Feb. 1, 2043
5.95% Senior Notes due October 1, 2043 | ETP [Member]
Senior note interest rate	5.95%
Debt instrument maturity date	Oct. 1, 2043
5.15% Senior Notes due March 15, 2045 | ETP [Member]
Senior note interest rate	5.15%
Debt instrument maturity date	Mar. 15, 2045
6.125% Senior Notes due December 15, 2045 | ETP [Member]
Senior note interest rate	6.125%
Debt instrument maturity date	Dec. 15, 2045
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETP [Member]
Debt instrument maturity date	Nov. 1, 2066
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member]
Debt instrument maturity date	Nov. 1, 2066
Debt Instrument, Interest Rate, Effective Percentage	3.77%
ETP $3.75 billion Revolving Credit Facility due November 2019 | ETP [Member]
Weighted average interest rate on the total amount outstanding	2.20%
ETP $3.75 billion Revolving Credit Facility due November 2019 | ETP [Member]
Debt instrument maturity date	Oct. 27, 2019
5.54% Senior Notes due November 17, 2016 | Transwestern [Member]
Senior note interest rate	5.54%
Debt instrument maturity date	Nov. 17, 2016
5.64% Senior Notes due May 24, 2017 | Transwestern [Member]
Senior note interest rate	5.64%
Debt instrument maturity date	May 24, 2017
5.36% Senior Notes due December 9, 2020 | Transwestern [Member]
Senior note interest rate	5.36%
Debt instrument maturity date	Dec. 9, 2020
5.89% Senior Notes due May 24, 2022 | Transwestern [Member]
Senior note interest rate	5.89%
Debt instrument maturity date	May 24, 2022
5.66% Senior Notes due December 9, 2024 | Transwestern [Member]
Senior note interest rate	5.66%
Debt instrument maturity date	Dec. 9, 2024
6.16% Senior Notes due May 24, 2037 | Transwestern [Member]
Senior note interest rate	6.16%
Debt instrument maturity date	May 24, 2037
6.20% Senior Notes due November 1, 2017 | Panhandle [Member]
Senior note interest rate	6.20%
Debt instrument maturity date	Nov. 1, 2017
7.00% Senior Notes due June 15, 2018 | Panhandle [Member]
Senior note interest rate	7.00%
Debt instrument maturity date	Jun. 15, 2018
8.125% Senior Notes due June 1, 2019 | Panhandle [Member]
Senior note interest rate	8.125%
Debt instrument maturity date	Jun. 1, 2019
7.00% Senior Notes due July 15, 2029 | Panhandle [Member]
Senior note interest rate	7.00%
Debt instrument maturity date	Jul. 15, 2029
6.125% Senior Notes due May 15, 2016 | Sunoco Logistics [Member]
Senior note interest rate	6.125%
Debt instrument maturity date	May 15, 2016
5.50% Senior Notes due February 15, 2020 | Sunoco Logistics [Member]
Senior note interest rate	5.50%
Debt instrument maturity date	Feb. 15, 2020
4.40% Senior Notes due April 1, 2021 | Sunoco Logistics [Member]
Senior note interest rate	4.40%
Debt instrument maturity date	Apr. 1, 2021
4.65% Senior Notes due February 15, 2022 | Sunoco Logistics [Member]
Senior note interest rate	4.65%
Debt instrument maturity date	Feb. 15, 2022
3.45% Senior Notes due January 15, 2023 | Sunoco Logistics [Member]
Senior note interest rate	3.45%
Debt instrument maturity date	Jan. 15, 2023
6.10% Senior Notes due February 15, 2042 | Sunoco Logistics [Member]
Senior note interest rate	6.10%
Debt instrument maturity date	Feb. 15, 2042
4.95% Senior Notes due January 15, 2043 | Sunoco Logistics [Member]
Senior note interest rate	4.95%
Debt instrument maturity date	Jan. 15, 2043
5.75% Senior Notes due January 15, 2017 | Sunoco [Member]
Senior note interest rate	5.75%
Debt instrument maturity date	Jan. 15, 2017
9.00% Debentures due November 1, 2024 | Sunoco [Member]
Senior note interest rate	9.00%
Debt instrument maturity date	Nov. 1, 2024

Debt Obligations (Future maturi

Debt Obligations (Future maturities of long-term debt) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
2,017	$ 1,812
2,018	1,650
2,019	5,045
2,020	3,167
2,021	1,900
Thereafter	19,420
Long-term Debt	32,930	$ 28,679
Excluding unamortized premiums and fair value adjustments [Member]
Long-term Debt	$ 32,994

Series A Preferred Units (Detai

Series A Preferred Units (Details) shares in Millions	1 Months Ended	9 Months Ended	12 Months Ended
	Jan. 31, 2017USD ($)shares	Sep. 30, 2015shares	Dec. 31, 2016shares	Dec. 31, 2015shares	Dec. 31, 2014shares	Apr. 30, 2015USD ($)$ / commonunit
Preferred Units Redemption Amount						$ 35,000,000
Preferred Units Quarterly Cash Distribution Per Unit | $ / commonunit						0.445
Preferrred Units Issued Stated Price						$ 18.30
Conversion Price of Preferred Units						$ 44.37
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares		0.9
Partners' Capital Account, Units, Redeemed | shares			17.8	51.8	18.7
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	1.9

Equity (Narrative) (Details)

Equity (Narrative) (Details) - USD ($)	1 Months Ended					3 Months Ended													6 Months Ended	12 Months Ended			36 Months Ended
	Feb. 28, 2017	Jan. 31, 2017	Aug. 31, 2016	Oct. 31, 2015	Mar. 31, 2015	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	Oct. 05, 2012	Dec. 31, 2011
Units issued for cash																				$ 1,098,000,000	$ 1,428,000,000	$ 1,382,000,000
Class H Unitholder’s interest in net income																				$ 351,000,000	$ 258,000,000	$ 217,000,000
Partners' Capital Account, Units						529,900,000				505,600,000				355,500,000					529,900,000	529,900,000	505,600,000	355,500,000	529,900,000			333,800,000
Class F Unit Distribution Rate						35.00%													35.00%	35.00%			35.00%
Common Units issued in connection with the Distribution Reinvestment Plan																				6,600,000	7,700,000	2,800,000	17,100,000
Class E Units entitled to aggregate cash distributions						11.10%													11.10%	11.10%			11.10%
Class E unit maximum distribution						$ 1.41													$ 1.41	$ 1.41			$ 1.41
Maximum Class F Distribution per Unit						3.75													$ 3.75	$ 3.75			$ 3.75
Partners' Capital Account, Units, Redeemed																				17,800,000	51,800,000	18,700,000
Common Units issued in connection with the equity distribution program																				26,100,000	21,100,000	21,400,000
Partners' Capital Account, Sale of Units																				$ 1,098,000,000	$ 1,428,000,000	$ 1,382,000,000
Payments to Acquire Businesses, Gross				$ 382,000,000
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						$ 1.0550	1.0550	$ 1.0550	$ 1.0550	$ 1.0550	$ 1.0550	$ 1.0350	$ 1.0150	$ 0.9950	$ 0.9750	$ 0.9550	$ 0.9350	$ 0.9200
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan						4,900,000													4,900,000	4,900,000			4,900,000
Common Units issued in connection with the equity distribution program																				26,100,000
Equity Distribution Agreements, Value of Units Available to be Issued						$ 936,000,000													$ 936,000,000	$ 936,000,000			$ 936,000,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement																				891,000,000
Stock Issued During Period, Value, Dividend Reinvestment Plan																				216,000,000	360,000,000	$ 155,000,000
Sunoco Logistics [Member]
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
Gain from subsidiary issuances of common units																				37,000,000
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units Sold																				$ 2,250,000,000	$ 1,250,000,000
Common Units issued in connection with the equity distribution program																				29,100,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement																				$ 744,000,000
Fees and Commissions																				8,000,000
Partners' Capital Account, Units, Sale of Units					15,500,000														24,200,000		7,700,000
Proceeds from Issuance of Common Stock					$ 629,000,000														$ 644,000,000		$ 362,000,000
Sunoco LP [Member]
Partners' Capital Account, Units, Sale of Units																						9,100,000
Partners' Capital Account, Sale of Units																						$ 405,000,000
Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				40.00%
Accumulated Other Comprehensive Income (Loss)
Partners' Capital Account, Sale of Units																				0	$ 0	$ 0
Bakken Pipeline Transaction [Member]
Class I Distributions													$ 55,000,000							$ 30,000,000
Partners' Capital Account, Units, Redeemed					30,800,000
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 Equity Sale [Member]
Payments to Acquire Businesses, Gross			$ 2,000,000,000
Class I Units
Limited Partners' Capital Account, Units Outstanding						100				100									100	100	100		100
Limited Partners' Capital Account, Units Authorized						100				100									100	100	100		100
Class I Units | Bakken Pipeline Transaction [Member]
Partners' Capital Account, Units					100								100
Class F Units [Member] | Sunoco [Member]
Partners' Capital Account, Units						40,000,000													40,000,000	40,000,000			40,000,000
Class E Units
Limited Partners' Capital Account, Units Outstanding						8,853,832				8,853,832									8,853,832	8,853,832	8,853,832		8,853,832
Limited Partners' Capital Account, Units Authorized						8,853,832				8,853,832									8,853,832	8,853,832	8,853,832		8,853,832
Class G Units
Limited Partners' Capital Account, Units Outstanding						90,706,000				90,706,000									90,706,000	90,706,000	90,706,000		90,706,000
Limited Partners' Capital Account, Units Authorized						90,706,000				90,706,000									90,706,000	90,706,000	90,706,000		90,706,000
Class G Units | ETP Holdco Transaction (see Note 3)
Partners' Capital Account, Units																									90,700,000
Class H Units
Partners' Capital Account, Units					50,200,000								50,200,000
Limited Partners' Capital Account, Units Outstanding						81,001,069				81,001,069									81,001,069	81,001,069	81,001,069		81,001,069
Limited Partners' Capital Account, Units Authorized						81,001,069				81,001,069									81,001,069	81,001,069	81,001,069		81,001,069
Allocation of Profits, Losses and Other by Sunoco, Percent						90.05%													90.05%	90.05%			90.05%
Class H Units | Bakken Pipeline Transaction [Member]
Allocation of Profits, Losses and Other by Sunoco, Percent					90.05%								90.05%
Partners' Capital Account, Units, Redeemed					30,800,000
Class K Units [Member]
Limited Partners' Capital Account, Units Outstanding						101,525,429				0									101,525,429	101,525,429	0		101,525,429
Limited Partners' Capital Account, Units Authorized						101,525,429				0									101,525,429	101,525,429	0		101,525,429
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
Equity Distribution Agreement [Member] | ETP [Member]
Fees and Commissions																				$ 8,000,000
Class E Units | ETP [Member]
Limited Partners' Capital Account, Units Outstanding						8,900,000													8,900,000	8,900,000			8,900,000
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | Sunoco Logistics [Member]
Line of Credit Facility, Current Borrowing Capacity						$ 2,500,000,000													$ 2,500,000,000	$ 2,500,000,000			$ 2,500,000,000
Bakken Pipeline Investments LLC [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired																								49.00%
Sunoco Logistics [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			40.00%
ETP [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			60.00%
Minimum [Member] | PennTex [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit																				$ 0.2750
Subsequent Event [Member]
Partners' Capital Account, Units, Sold in Private Placement		15,800,000
Proceeds from Issuance of Private Placement		$ 568,000,000
Subsequent Event [Member] | Dakota Access and ETCOC [Member] | Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	25.00%
Subsequent Event [Member] | Dakota Access and ETCOC [Member] | Bakken Pipeline Investments LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	75.00%
Subsequent Event [Member] | Bakken Pipeline [Member] | Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	25.00%
Subsequent Event [Member] | Bakken Pipeline [Member] | ETP and Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	38.25%
Subsequent Event [Member] | Bakken Pipeline [Member] | MarEn Bakken Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	36.75%

Equity (Change in Common Units)

Equity (Change in Common Units) (Details) - shares shares in Millions	1 Months Ended		12 Months Ended			36 Months Ended
	Aug. 31, 2014	Feb. 28, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016
Number of Common Units, beginning of period			505.6	355.5
Partners' Capital Account, Units, Redeemed			(17.8)	(51.8)	(18.7)
Partners' Capital Account, Units, Acquisitions			8.9	172.2	15.8
Common Units issued in connection with the Distribution Reinvestment Plan			6.6	7.7	2.8	17.1
Common Units issued in connection with the equity distribution program			26.1	21.1	21.4
Issuance of Common Units under equity incentive plans			0.5	0.9	0.4
Number of Common Units, end of period			529.9	505.6	355.5	529.9
Susser Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	15.8
Lake Charles LNG Transaction [Member]
Partners' Capital Account, Units, Redeemed		(18.7)

Equity (Public Offerings of Com

Equity (Public Offerings of Common Units) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net Proceeds	$ 1,098	$ 1,428	$ 1,382

Equity (Quarterly Distributions

Equity (Quarterly Distributions of Available Cash) (Details) - $ / shares

3 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

ETP [Member]

Distribution Made to Limited Partner [Line Items]

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

$ 1.0550

$ 1.0550

$ 1.0550

$ 1.0550

$ 1.0550

$ 1.0550

$ 1.0350

$ 1.0150

$ 0.9950

$ 0.9750

$ 0.9550

$ 0.9350

$ 0.9200

Sunoco Logistics [Member]

Distribution Made to Limited Partner [Line Items]

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

Equity (Incentive Distribution

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

Equity (SXL Quarterly Distribut

Equity (SXL Quarterly Distributions) (Details) - Sunoco Logistics [Member] - $ / shares

3 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

Distribution Made to Limited Partner [Line Items]

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

Equity (PennTex Quarterly DIstr

Equity (PennTex Quarterly DIstributions) (Details) - PennTex [Member] - $ / shares	3 Months Ended
	Dec. 31, 2016	Sep. 30, 2016
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

Equity (Accumulated other compr

Equity (Accumulated other comprehensive income, net of tax) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	$ 2	$ 0
Foreign currency translation adjustment	(5)	(4)
Actuarial gain (loss) related to pensions and other postretirement benefits	7	8
AOCI attributable to equity method investments	4	0
Total AOCI, net of tax	$ 8	$ 4

Equity (Tax amounts attributabl

Equity (Tax amounts attributable to Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Equity [Abstract]
Other Comprehensive Income (Loss), Available-for-sale Securities, 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

Unit-Based Compensation Plans80

Unit-Based Compensation Plans (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	1.8
Employee [Member]
Share based compensation, vesting term	5 years
Director [Member]
Share based compensation, vesting term	5 years
ETP Cash Restricted Units [Member]
Unvested unit awards outstanding	0.2
Awards remaining unvested compensation expense	$ 3
Awards remaining unvested weighted average period, in years	1 year
ETP Unit-Based Compensation Plans [Member]
Awards granted	$ 35.73	$ 35.21	$ 60.85
Total fair value of awards vested	$ 28	$ 49	$ 26
Unvested unit awards outstanding	6.3	4.8
Awards remaining unvested compensation expense	$ 179
Awards remaining unvested weighted average period, in years	2 years 1 month

Unit-Based Compensation Plans81

Unit-Based Compensation Plans (Activity of the awards granted to employees and non-employee directors) (Details) - ETP Unit-Based Compensation Plans [Member] - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Unvested unit awards outstanding	6.3	4.8
Awards granted	2.5
Awards vested	(0.8)
Unvested awards as of December 31, 2015	$ 47.61
Awards granted	35.73	$ 35.21	$ 60.85
Awards vested	53.22
Awards forfeited	$ 48.39
Awards forfeited	$ (0.2)
Unvested awards as of December 31, 2016	$ 41.53	$ 47.61

Unit-Based Compensation Plans82

Unit-Based Compensation Plans (SXL Award Activity) (Details) - Sunoco Logistics Unit-Based Compensation Plans [Member] - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested unit awards outstanding	3.2	2.5
Unvested awards outstanding	$ 28.57	$ 33.16
Awards granted	1.3
Awards granted	$ 23.21	$ 29.54	$ 41.59
Awards vested	(0.5)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 34.19
Awards forfeited	$ (0.1)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 33.72
Total fair value of awards vested	$ 12	$ 8	$ 30
Awards remaining unvested compensation expense	$ 57
Awards remaining unvested weighted average period, in years	3 years

Income Taxes Narrative (Details

Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Contingency [Line Items]
Deferred Tax Liabilities, Gross	$ 4,802	$ 4,355
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
Unrecognized Tax Benefits, Interest on Income Taxes Expense	$ 1
Income Tax Examination, Penalties and Interest Accrued	$ 6
Operating Loss Carryforwards, Expiration Date	Jan. 1, 2032
Net operating losses and alternative minimum tax credit	$ 380	155
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	596
Deferred Tax Assets, Valuation Allowance	118	121
Pending Tax Refund	530
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	530
State	(35)	$ (51)	$ 86
Pennsylvania Constitution [Member]
Income Tax Contingency [Line Items]
State	46
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	9
ETP Holdco and other corporate subsidiaries [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	580
Corporate Subsidiaries [Member]
Income Tax Contingency [Line Items]
Net operating losses and alternative minimum tax credit	52
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	124
Net of federal tax [Member] | Pennsylvania Constitution [Member]
Income Tax Contingency [Line Items]
State	30
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	$ 6
Minimum [Member] | Corporate Subsidiaries [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards, Expiration Date	Jan. 1, 2017
Maximum [Member] | ETP Holdco and other corporate subsidiaries [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2035
Maximum [Member] | Corporate Subsidiaries [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2036

Income Taxes Compoenents of Fed

Income Taxes Compoenents of Federal and State Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current expense (benefit):
Federal	$ 18	$ (274)	$ 321
State	(35)	(51)	86
Current expense (benefit) - Total	(17)	(325)	407
Deferred expense (benefit):
Federal	(173)	231	(50)
State	4	(29)	1
Deferred expense (benefit) - Total	(169)	202	(49)
Income tax expense (benefit) from continuing operations	$ (186)	$ (123)	$ 358

Income Taxes Statutory Income T

Income Taxes Statutory Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income tax expense at U.S. statutory rate of 35 percent	$ 154	$ 490	$ 558
Partnership earnings not subject to tax	(519)	(515)	(341)
Effective Income Tax Reconciliation, Nondeductible Goodwill Lake Charles	0	0	105
Goodwill impairments	223	0	0
Foreign	(17)	(37)	54
Dividend Received Deduction	(15)	(24)	0
Audit Settlement	0	(7)	0
Premium on debt retirement	0	0	(10)
Foreign	0	0	(8)
Other	(12)	(30)	0
Income tax expense (benefit) from continuing operations	$ (186)	$ (123)	$ 358

Income Taxes Tax Effects of Tem

Income Taxes Tax Effects of Temporary Differences (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	$ 380	$ 155
Pension and other postretirement benefits	30	36
Long term debt	32	61
Other	84	142
Total deferred income tax assets	526	394
Valuation allowance	(118)	(121)
Net deferred income tax assets	408	273
Deferred income tax liabilities:
Properties, plants and equipment	(1,054)	(1,305)
Investment in unconsolidated affiliates	(3,728)	(2,889)
Trademarks	0	(112)
Other	(20)	(49)
Total deferred income tax liabilities	(4,802)	(4,355)
Accumulated deferred income taxes	(4,394)	(4,082)	$ (4,331)
Accumulated deferred income taxes	$ (4,394)	$ (4,082)

Income Taxes Components of Net

Income Taxes Components of Net Deferred Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits, Increase Resulting from Acquisition	$ 0	$ 490
Net deferred income tax liability, beginning of year	(4,082)	(4,331)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)	(460)	0
Tax provision	169	(202)
Other	(21)	(39)
Net deferred income tax liability, end of year	$ (4,394)	$ (4,082)

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
Income Tax Disclosure [Abstract]
Balance at beginning of year	$ 610	$ 440	$ 429
Additions attributable to tax positions taken in the current year	8	0	20
Additions attributable to tax positions taken in prior years	18	178	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 Matters (Narrative) (Details)	1 Months Ended		12 Months Ended
	Oct. 31, 2015USD ($)	Apr. 30, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)		Dec. 31, 2014USD ($)		Feb. 01, 2017USD ($)	Dec. 31, 2012USD ($)	Jan. 31, 2012USD ($)
Lease Expiration Date			Dec. 31, 2034
Rental expense under operating lease			$ 81,000,000	$ 176,000,000	[1]	$ 159,000,000	[1]
Operating Leases, Rent Expense, Sublease Rentals			(1,000,000)	(16,000,000)		(26,000,000)
Operating Leases, Rent Expense, Net			$ 80,000,000	160,000,000		133,000,000
Operating Leases, Rent Expense, Contingent Rentals				26,000,000		$ 24,000,000
Site Contingency, Number of Sites Needing Remediation			50
Accrual for Environmental Loss Contingencies			$ 345,000,000	367,000,000
Payments for Environmental Liabilities			43,000,000	38,000,000
Payments to Acquire Businesses, Gross	$ 382,000,000
Proposed Environmental Penalty			0
Long-term Debt			32,930,000,000	28,679,000,000
AmeriGas [Member]
Business Combination, Contingent Consideration, Liability										$ 1,550,000,000
Debt instrument interest rate								7.00%
Sunoco Logistics [Member]
Proposed Environmental Penalty			100,000						$ 1,400,000
Long-term Debt			7,313,000,000	5,590,000,000
Related To Deductibles [Member]
Loss Contingency Accrual, at Carrying Value			53,000,000	$ 40,000,000
Texas Commission on Environmental Quality [Member]
Accrual for Environmental Loss Contingencies			50,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount			536,000,000
New Mexico Environmental Department [Member]
Accrual for Environmental Loss Contingencies			250,000
Civil penalties			465,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount			595,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount			$ 1,000,000
MTBE Sites [Member]
Site Contingency, Number of Sites Needing Remediation			19
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount			$ 319,000,000
Supplemental Environmental Project [Member]
Proposed Environmental Penalty			21,000
Permian Express 2 [Member] | Sunoco Logistics [Member]
Proposed Environmental Penalty			100,000
Sunoco Logistics Crude Oil Pipeline [Member] | Sunoco Logistics [Member]
Proposed Environmental Penalty			100,000
Wortham, Texas Crude Oil Pipeline [Member] | Sunoco Logistics [Member]
Proposed Environmental Penalty			$ 100,000
Dropdown of Sunoco LLC Interest [Member]
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage		31.58%
Payments to Acquire Businesses, Gross		$ 775,000,000
Equity Issued in Business Combination, Fair Value Disclosure		$ 41,000,000
6.375% Senior Notes due April 2023 [Member] | Sunoco LP [Member]
Debt instrument interest rate			6.375%
Senior Notes			$ 800,000,000
6.25% Senior Notes due 2021 [Member] | Sunoco LP [Member]
Debt instrument interest rate			6.25%
Senior Notes			$ 800,000,000
Term loan due 2019 [Member] | Sunoco LP [Member]
Long-term Debt			$ 2,035,000,000
Subsequent Event [Member] | AmeriGas [Member]
Business Combination, Contingent Consideration, Liability								$ 122,000,000
[1]	(1) Includes contingent rentals totaling $26 million and $24 million for the years ended December 31, 2015 and 2014, respectively.

Regulatory Matters, Commitmen90

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Future minimum lease commitments) (Details) $ in Millions	Dec. 31, 2016USD ($)
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
2,017	$ 38
2,018	30
2,019	28
2,020	28
2,021	35
Thereafter	133
Future minimum lease commitments	292
Less: Sublease rental income	(14)
Net future minimum lease commitments	$ 278

Regulatory Matters, Commitmen91

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Liabilities Related to Environmental Matters) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Environmental Remediation Obligations [Abstract]
Accrued Environmental Loss Contingencies, Current	$ 32	$ 41
Accrued Environmental Loss Contingencies, Noncurrent	313	326
Accrual for Environmental Loss Contingencies	$ 345	$ 367

Derivative assets and liabilt92

Derivative assets and liabilties (Outstanding commodity-related derivatives) (Details)		12 Months Ended
		Dec. 31, 2016MMbtuMWbblbushels	Dec. 31, 2015barrelsMMbtuMWbblbushels
Fixed Swaps Futures [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Notional Volume		(52,652,500)	(14,380,000)
Fixed Swaps Futures [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Short [Member]
Term Of Commodity Derivatives		2,017	2,016
Fixed Swaps Futures [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Short [Member]
Term Of Commodity Derivatives		2,019	2,018
Fixed Swaps Futures [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Notional Volume		(682,500)	(602,500)
Term Of Commodity Derivatives		2,017
Fixed Swaps Futures [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Minimum [Member] | Short [Member]
Term Of Commodity Derivatives			2,016
Fixed Swaps Futures [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Maximum [Member] | Short [Member]
Term Of Commodity Derivatives			2,017
Fixed Swaps Futures [Member] | Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Short [Member]
Notional Volume		(36,370,000)	(37,555,000)
Term Of Commodity Derivatives		2,017	2,016
Forward Physical Contracts [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Long [Member]
Notional Volume			(21,922,484)
Forward Physical Contracts [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Notional Volume		(22,492,489)
Term Of Commodity Derivatives		2,017
Forward Physical Contracts [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Long [Member]
Term Of Commodity Derivatives			2,016
Forward Physical Contracts [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Long [Member]
Term Of Commodity Derivatives			2,017
Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Long [Member]
Notional Volume		(10,750,000)
Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Notional Volume			(6,522,500)
Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Long [Member]
Term Of Commodity Derivatives		2,017	2,016
Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Long [Member]
Term Of Commodity Derivatives		2,018	2,017
Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Notional Volume	[1]	(2,242,500)
Term Of Commodity Derivatives		2,017
Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Notional Volume	[1]		(31,240,000)
Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Minimum [Member] | Long [Member]
Term Of Commodity Derivatives			2,016
Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Maximum [Member] | Long [Member]
Term Of Commodity Derivatives			2,017
Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Short [Member]
Notional Volume		(36,370,000)	(37,555,000)
Term Of Commodity Derivatives		2,017	2,016
Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Long [Member]
Notional Volume			(71,340,000)
Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Notional Volume		(5,662,500)
Term Of Commodity Derivatives		2,017
Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Short [Member]
Term Of Commodity Derivatives			2,016
Swing Swaps IFERC [Member] | Natural Gas [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Short [Member]
Term Of Commodity Derivatives			2,017
Call Option [Member] | Power [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Notional Volume | MW		(186,400)	(1,300,647)
Term Of Commodity Derivatives		2,017	2,016
Forward Swaps [Member] | Natural Gas Liquids [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Notional Volume		(5,786,627)	(8,146,800)
Term Of Commodity Derivatives		2,017
Forward Swaps [Member] | Natural Gas Liquids [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Short [Member]
Term Of Commodity Derivatives			2,016
Forward Swaps [Member] | Natural Gas Liquids [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Short [Member]
Term Of Commodity Derivatives			2,018
Forward Swaps [Member] | Power [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Notional Volume | MW		(391,880)	(357,092)
Forward Swaps [Member] | Power [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Minimum [Member] | Long [Member]
Term Of Commodity Derivatives		2,017	2,016
Forward Swaps [Member] | Power [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Maximum [Member] | Long [Member]
Term Of Commodity Derivatives		2,018	2,017
Future [Member] | Power [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Notional Volume | MW		(109,564)
Future [Member] | Power [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Notional Volume | MW			(109,791)
Term Of Commodity Derivatives			2,016
Future [Member] | Power [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Minimum [Member] | Long [Member]
Term Of Commodity Derivatives		2,017
Future [Member] | Power [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Maximum [Member] | Long [Member]
Term Of Commodity Derivatives		2,018
Future [Member] | WTI Crude Oil [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Notional Volume | bbl		(617,000)	(591,000)
Term Of Commodity Derivatives		2,017
Future [Member] | WTI Crude Oil [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Minimum [Member] | Short [Member]
Term Of Commodity Derivatives			2,016
Future [Member] | WTI Crude Oil [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Maximum [Member] | Short [Member]
Term Of Commodity Derivatives			2,017
Future [Member] | Refined Products [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Notional Volume		(2,240,000)	(939,000)
Term Of Commodity Derivatives		2,017
Future [Member] | Refined Products [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Minimum [Member] | Short [Member]
Term Of Commodity Derivatives			2,016
Future [Member] | Refined Products [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Maximum [Member] | Short [Member]
Term Of Commodity Derivatives			2,017
Future [Member] | Corn [Member] | Mark to Market Derivatives [Member] | Non Trading [Member]
Notional Volume | bushels		0
Future [Member] | Corn [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Long [Member]
Notional Volume | bushels			(1,185,000)
Term Of Commodity Derivatives		2,016
Put Option [Member] | Power [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Notional Volume | MW			(260,534)
Term Of Commodity Derivatives			2,016
Put Option [Member] | Power [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Notional Volume | MW		(50,400)
Term Of Commodity Derivatives		2,017
Hedged Item - Inventory (MMBtu) [Member] | Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Long [Member]
Notional Volume		(36,370,000)	(37,555,000)
Term Of Commodity Derivatives		2,017	2,016
[1]	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Derivative assets and liabilt93

Derivative assets and liabilties (Interest rate swaps outstanding) (Details) - ETP [Member] - Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
July 2016 [Member] | Forward-Starting Swaps [Member]
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
Notional amount outstanding	[2]	$ 0	$ 200
July 2017 [Member] | Forward-Starting Swaps [Member]
Type	[1],[3]	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate
Notional amount outstanding	[3]	$ 500	300
July 2018 [Member] | Forward-Starting Swaps [Member]
Type	[1],[3]	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate
Notional amount outstanding	[3]	$ 200	200
July 2019 [Member] | Forward-Starting Swaps [Member]
Type	[1],[3]	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate
Notional amount outstanding	[3]	$ 200	200
December 2018 [Member]
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%
Notional amount outstanding		$ 1,200	1,200
March 2019 [Member]
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
Notional amount outstanding		$ 300	$ 300
[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 terms of 30 years with a mandatory termination date the same as the effective date.

Derivative assets and liabilt94

Derivative assets and liabilties (Fair Value of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Total derivative assets	$ 362	$ 448
Total derivative liabilities	(666)	(526)
Derivative Asset, Fair Value, Net	20	122
Derivative Liability, Fair Value, Net	324	200
Designated as Hedging Instrument [Member]
Total derivative assets	0	38
Total derivative liabilities	(4)	(3)
Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) [Member]
Total derivative assets	0	38
Total derivative liabilities	(4)	(3)
Not Designated as Hedging Instrument [Member]
Total derivative assets	362	410
Total derivative liabilities	(662)	(523)
Not Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) [Member]
Total derivative assets	338	353
Total derivative liabilities	(416)	(306)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivative assets	24	57
Total derivative liabilities	(52)	(41)
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivative assets		0
Total derivative liabilities	(193)	(171)
Asset Fair Value, Netting Offset [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivative assets	0
Embedded Derivatives in Preferred Units [Member] | Not Designated as Hedging Instrument [Member]
Total derivative assets	0	0
Total derivative liabilities	(1)	(5)
Broker cleared derivative contracts [Member]
Total derivative assets	338	391
Total derivative liabilities	$ (420)	$ (309)

Derivative assets and liabilt95

Derivative assets and liabilties (Netting table) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 362	$ 448
Derivative Liability, Fair Value, Gross Liability	(666)	(526)
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, Net	20	122
Derivative Liability, Fair Value, Net	(324)	(200)
Without offsetting agreements [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(194)	(176)
OTC Contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	24	57
Derivative Liability, Fair Value, Gross Liability	(52)	(41)
Broker cleared derivative contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	338	391
Derivative Liability, Fair Value, Gross Liability	(420)	(309)
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	362	410
Derivative Liability, Fair Value, Gross Liability	$ (662)	$ (523)

Derivative assets and liabilt96

Derivative assets and liabilties (Partnership's derivative assets and liabilities, recognized OCI on derivatives (effective portion)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 14	$ 21	$ (8)
Cost of Sales [Member] | Commodity [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 14	$ 21	$ (8)

Derivative assets and liabilt97

Derivative assets and liabilties (Partnership's derivative assets and liabilities, amount of gain/(loss) reclassified from AOCI into income (effective portion)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 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 on Ineffective Portion	14	21	(8)
Amount of Gain (Loss) Recognized In Income On Derivatives	(216)	6	39
Losses on interest rate derivatives	(12)	(18)	(157)
Embedded Derivatives in Preferred Units [Member] | Other Income (Expenses) [Member]
Amount of Gain (Loss) Recognized In Income On Derivatives	4	12	3
Commodity [Member] | Cost of Sales [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	0	0	(3)
Amount of Gain (Loss) Recognized in Income on Ineffective Portion	14	21	(8)
Trading [Member] | Commodity [Member] | Cost of Sales [Member]
Amount of Gain (Loss) Recognized In Income On Derivatives	(35)	(11)	(6)
Non Trading [Member] | Commodity [Member] | Cost of Sales [Member]
Amount of Gain (Loss) Recognized In Income On Derivatives	$ (173)	$ 23	$ 199

Retirement Benefits (Narratives

Retirement Benefits (Narratives) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	1.8
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Large Cap US Equitiies	100.00%	100.00%
2,017	$ 12
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Large Cap US Equitiies	31.00%
Fixed Income Securities	66.00%
Cash Fund Investments	3.00%
2,017	$ 10
ETP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to the 401(k) savings plan	44	$ 39	$ 50
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Large Cap US Equitiies		56.00%
Fixed Income Securities		33.00%
Cash Fund Investments		11.00%
Sunoco [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent	$ 200
Cash [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage, Cash Maximum	10.00%
Equity [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum	25.00%
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum	35.00%
Fixed Income Investments [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Minimum	65.00%
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities, Range Maximum	75.00%
ETP Unit-Based Compensation Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Awards remaining unvested weighted average period, in years	2 years 1 month
Awards granted	$ 35.73	$ 35.21	$ 60.85
Unvested unit awards outstanding	6.3	4.8

Retirement Benefits Obligations

Retirement Benefits Obligations and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Change in benefit obligation and Plan Assets:
Settlements	$ 0	$ 0
Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Interest cost	3	25
Benefit obligation		20
Fair value of plan assets		15
Amount underfunded		5
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Amounts Recognized in Balance Sheet		(5)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax		2
Other Postretirement Benefit Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Interest cost	4	4
Actuarial (gain) loss and other	2	(6)
Benefits paid, net	21	20
Return on plan assets and other	6	0
Employer contributions	10	8
Benefit obligation	165	180	$ 202
Fair value of plan assets	248	253	265
Amount underfunded	(83)	(73)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	108	97
Current liabilities	(2)	(2)
Non-current liabilities	(23)	(22)
Defined Benefit Plan, Amounts Recognized in Balance Sheet	83	73
Net actuarial gain	(12)	(17)
Prior service cost	14	15
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	2	(2)
Southern Union [Member] | Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Fair value of plan assets	12	15
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Fair value of plan assets	248	253
Funded Plans [Member]
Change in benefit obligation and Plan Assets:
Settlements	0
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Interest cost	1	23
Actuarial (gain) loss and other	(2)	16
Benefits paid, net	1	46
Settlements		(691)
Return on plan assets and other	(2)	16
Employer contributions	0	138
Benefit obligation	18	20	718
Fair value of plan assets	12	15	598
Amount underfunded	6
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Current liabilities	0	0
Non-current liabilities	(6)	(5)
Defined Benefit Plan, Amounts Recognized in Balance Sheet	(6)
Net actuarial gain	0	2
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	0
Unfunded Plans [Member]
Change in benefit obligation and Plan Assets:
Settlements	0	0
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Interest cost	2	2
Actuarial (gain) loss and other	(1)	(2)
Benefits paid, net	7	8
Benefit obligation	51	57	65
Amount underfunded	51	57
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Current liabilities	(7)	(9)
Non-current liabilities	(44)	(48)
Defined Benefit Plan, Amounts Recognized in Balance Sheet	(51)	(57)
Net actuarial gain	0	4
Prior service cost	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] | Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Fair value of plan assets	0	0
Change in Plan Assets [Member] | Unfunded Plans [Member]
Change in benefit obligation and Plan Assets:
Settlements	0	0
Change in Plan Assets [Member] | Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Benefits paid, net	0	0
Return on plan assets and other	0	0
Employer contributions	$ 0	0
Fair value of plan assets		$ 0	$ 0

Retirement Benefits Components

Retirement Benefits Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	$ 3	$ 25
Expected return on plan assets	(1)	(16)
Prior service cost amortization	0	0
Settlements	0	(32)
Net periodic benefit cost	2	41
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	4	4
Expected return on plan assets	(8)	(8)
Prior service cost amortization	1	1
Settlements	0	0
Net periodic benefit cost	(3)	(3)
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	$ 1	$ 23

Retirement Benefits Summary for

Retirement Benefits Summary for Plans with an Accumulated Benefit Obligation in Excess of Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	$ 165	$ 180
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	248	253
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Pension 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 Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [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 Weighted-Av

Retirement Benefits Weighted-Average Assumptions Used in Determining Benefit Obligations (Details)	Dec. 31, 2016	Dec. 31, 2015
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.65%	3.59%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.34%	2.38%

Retirement Benefits Assumed Hea

Retirement Benefits Assumed Health Care Cost Trend Rates (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [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

Retirement Benefits Schedule Of

Retirement Benefits Schedule Of Weighted-Average Assumptions To Determine Defined Benefit Plans And Postretirement Benefit Plans Expense (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.60%	3.65%
Expected long term return on assets, tax exempt accounts	3.50%	7.50%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.06%	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 Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		$ 248	$ 253	$ 265
Large Cap US Equitiies		31.00%
Fixed Income Securities		66.00%
Cash Fund Investments		3.00%
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			$ 15
Large Cap US Equitiies		100.00%	100.00%
Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		$ 23
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		134
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		12
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0
Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		91
Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0
Southern Union [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		248	$ 253
Large Cap US Equitiies			56.00%
Fixed Income Securities			33.00%
Cash Fund Investments			11.00%
Southern Union [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		12	$ 15
Southern Union [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		23	18
Southern Union [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets	[1]	134	133
Southern Union [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets	[2]	12	15
Southern Union [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		91	102
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		157	151
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		12	0
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			18
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			133
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			0
Southern Union [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			0
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		91	102
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	15
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			0
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			0
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			15
Southern Union [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			102
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		$ 0	0
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			0
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			0
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			0
Southern Union [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			$ 0
[1]	(1) Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016.
[2]	(1) Comprised of approximately 100% equities as of December 31, 2016.

Retirement Benefits Expected Fu

Retirement Benefits Expected Future Benefit Payments (Details) $ in Millions	Dec. 31, 2016USD ($)
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,017	$ 26
2,018	25
2,019	23
2,020	22
2,021	19
2022 - 2026	39
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,017	10
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,017	12
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,017	1
2,018	1
2,019	1
2,020	1
2,021	1
2022 - 2026	6
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [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) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Related Party Transaction, Amounts of Transaction	$ 75
Management Fees Revenue	$ 95

Related Party Transactions Rela

Related Party Transactions Related Party - Affiliated Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Affiliated revenues	$ 377	$ 417	$ 965

Related Party Transactions R109

Related Party Transactions Related Party - Affiliate AR and Affiliate AP (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Long-term notes payable – related company	$ (250)	$ (233)
Accounts Receivable, Related Parties, Current	209	268
Accounts Payable, Related Parties, Current	43	25
Net Related Party Receivable (Payable)	(163)	(233)
ETE
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	22	110
Accounts Payable, Related Parties, Current	0	1
PES
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	6	10
FGT
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	15	13
Accounts Payable, Related Parties, Current	1	1
Lake Charles LNG
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	4	36
Accounts Payable, Related Parties, Current	3	3
Trans-Pecos Pipeline, LLC [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	1	29
Comanche Trail Pipeline, LLC [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	0	22
Other
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	65	45
Accounts Payable, Related Parties, Current	19	15
Sunoco LP [Member]
Related Party Transaction [Line Items]
Notes Receivable, Related Parties, Noncurrent	87
Long-term notes payable – related company		(233)
Accounts Receivable, Related Parties, Current	96	3
Accounts Payable, Related Parties, Current	20	5
Phillips 66 Company [Member]
Related Party Transaction [Line Items]
Long-term notes payable – related company	$ (250)	$ 0

Reportable Segments (Narrative)

Reportable Segments (Narrative) (Details) shares in Millions	Dec. 31, 2016shares
Segment Reporting [Abstract]
Investments in and Advances to Affiliates, Balance, Shares	43.5
Equity Method Investment, Ownership Percentage	44.30%

Reportable Segments (Segment Ad

Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Adjusted EBITDA			$ 5,605	$ 5,714	$ 5,710
Depreciation, depletion and amortization			(1,986)	(1,929)	(1,669)
Interest expense, net			(1,317)	(1,291)	(1,165)
Gains on acquisitions			(83)	0	0
Gain on sale of AmeriGas common units			0	0	177
Impairment losses			813	339	370
Impairment losses			(670)	(205)
Losses on interest rate derivatives			(12)	(18)	(157)
Non-cash unit-based compensation expense			(80)	(79)	(68)
Unrealized gains (losses) on commodity risk management activities			(131)	(65)	112
Inventory valuation adjustments	$ 27	$ (120)	170	(104)	(473)
Losses on extinguishments of debt			0	(43)	(25)
Adjusted EBITDA related to discontinued operations			0	0	(27)
Adjusted EBITDA related to unconsolidated affiliates			(946)	(937)	(748)
Equity in earnings from unconsolidated affiliates			59	469	332
Impairment of investment in an unconsolidated affiliate			308	0	0
Other, net			114	20	(36)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE			438	1,398	1,593
Intrastate Transportation And Storage [Member]
Segment Adjusted EBITDA			613	543	559
Depreciation, depletion and amortization			(144)	(129)	(125)
Impairment losses			0	0
Equity in earnings from unconsolidated affiliates			35	32	27
Interstate Transportation and Storage [Member]
Segment Adjusted EBITDA			1,117	1,155	1,212
Depreciation, depletion and amortization			(207)	(210)	(203)
Impairment losses			638	99
Equity in earnings from unconsolidated affiliates			193	197	196
Midstream [Member]
Segment Adjusted EBITDA			1,133	1,237	1,318
Depreciation, depletion and amortization			(844)	(720)	(569)
Impairment losses			32	0
Equity in earnings from unconsolidated affiliates			19	(19)	10
Liquids Transportation And Services [Member]
Segment Adjusted EBITDA			968	744	591
Depreciation, depletion and amortization			(156)	(126)	(113)
Impairment losses			0	106
Equity in earnings from unconsolidated affiliates			3	(2)	(3)
Investment in Sunoco Logistics [Member]
Segment Adjusted EBITDA			1,233	1,153	971
Depreciation, depletion and amortization			(446)	(382)	(296)
Impairment losses			0	0
Equity in earnings from unconsolidated affiliates			34	21	23
Other Segments [Member]
Segment Adjusted EBITDA			541	882	1,059
Depreciation, depletion and amortization			(189)	(362)	(363)
Impairment losses			0	0
Equity in earnings from unconsolidated affiliates			$ (225)	$ 240	$ 79

Reportable Segments (Financial

Reportable Segments (Financial Information by Segment) (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
Advances to and investments in unconsolidated affiliates	$ 4,280				$ 5,003				$ 4,280	$ 5,003	$ 3,760
Property, Plant and Equipment, Additions									5,810	8,167	5,494
Total assets	70,191				65,173				70,191	65,173	62,518
Equity in earnings from unconsolidated affiliates									59	469	332
Depreciation, depletion and amortization									1,986	1,929	1,669
Cost of products sold (see Note 3)									15,394	27,029	48,414
Revenues	6,526	$ 5,531	$ 5,289	$ 4,481	5,825	$ 6,601	$ 11,540	$ 10,326	21,827	34,292	55,475
Intrastate Transportation And Storage [Member]
Advances to and investments in unconsolidated affiliates	387				406				387	406	423
Property, Plant and Equipment, Additions									76	105	169
Total assets	5,164				4,882				5,164	4,882	4,983
Equity in earnings from unconsolidated affiliates									35	32	27
Depreciation, depletion and amortization									144	129	125
Cost of products sold (see Note 3)									1,897	1,554	2,169
Revenues									2,613	2,250	2,857
Intrastate Transportation And Storage [Member] | External Customers [Member]
Revenues									2,155	1,912	2,645
Intrastate Transportation And Storage [Member] | Intersegment [Member]
Revenues									458	338	212
Interstate Transportation and Storage [Member]
Advances to and investments in unconsolidated affiliates	2,149				2,516				2,149	2,516	2,649
Property, Plant and Equipment, Additions									280	860	411
Total assets	10,833				11,345				10,833	11,345	10,779
Equity in earnings from unconsolidated affiliates									193	197	196
Depreciation, depletion and amortization									207	210	203
Revenues									969	1,025	1,072
Interstate Transportation and Storage [Member] | External Customers [Member]
Revenues									946	1,008	1,057
Interstate Transportation and Storage [Member] | Intersegment [Member]
Revenues									23	17	15
Midstream [Member]
Advances to and investments in unconsolidated affiliates	111				117				111	117	138
Property, Plant and Equipment, Additions									1,255	2,172	1,298
Total assets	18,011				17,111				18,011	17,111	15,562
Equity in earnings from unconsolidated affiliates									19	(19)	10
Depreciation, depletion and amortization									844	720	569
Cost of products sold (see Note 3)									3,381	3,264	4,893
Revenues									5,179	5,056	6,823
Midstream [Member] | External Customers [Member]
Revenues									2,342	2,607	4,770
Midstream [Member] | Intersegment [Member]
Revenues									2,837	2,449	2,053
Liquids Transportation And Services [Member]
Advances to and investments in unconsolidated affiliates	29				32				29	32	31
Property, Plant and Equipment, Additions									2,316	2,109	427
Total assets	11,296				7,235				11,296	7,235	4,568
Equity in earnings from unconsolidated affiliates									3	(2)	(3)
Depreciation, depletion and amortization									156	126	113
Cost of products sold (see Note 3)									3,673	2,597	3,166
Revenues									4,797	3,496	3,911
Liquids Transportation And Services [Member] | External Customers [Member]
Revenues									4,498	3,247	3,730
Liquids Transportation And Services [Member] | Intersegment [Member]
Revenues									299	249	181
Investment in Sunoco Logistics [Member]
Advances to and investments in unconsolidated affiliates	224				247				224	247	226
Property, Plant and Equipment, Additions									1,739	2,126	2,510
Total assets	18,819				15,423				18,819	15,423	13,619
Equity in earnings from unconsolidated affiliates									34	21	23
Depreciation, depletion and amortization									446	382	296
Cost of products sold (see Note 3)									7,658	9,307	17,135
Revenues									9,151	10,486	18,088
Investment in Sunoco Logistics [Member] | External Customers [Member]
Revenues									9,015	10,302	17,920
Investment in Sunoco Logistics [Member] | Intersegment [Member]
Revenues									136	184	168
Other Segments [Member]
Advances to and investments in unconsolidated affiliates	1,380				1,685				1,380	1,685	293
Property, Plant and Equipment, Additions									144	795	679
Total assets	$ 6,068				$ 9,177				6,068	9,177	13,007
Equity in earnings from unconsolidated affiliates									(225)	240	79
Depreciation, depletion and amortization									189	362	363
Cost of products sold (see Note 3)									2,942	14,029	24,129
Revenues									3,271	15,774	25,818
Other Segments [Member] | External Customers [Member]
Revenues									2,871	15,216	25,353
Other Segments [Member] | Intersegment [Member]
Revenues									400	558	465
Intersegment Eliminations [Member]
Cost of products sold (see Note 3)									(4,157)	(3,722)	(3,078)
Revenues									$ (4,153)	$ (3,795)	$ (3,094)

Quarterly Financial Data Qarter

Quarterly Financial Data Qarterly Financial Data Table(Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 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 Data [Abstract]
Revenues	$ 6,526	$ 5,531	$ 5,289	$ 4,481	$ 5,825	$ 6,601	$ 11,540	$ 10,326	$ 21,827	$ 34,292	$ 55,475
Operating income (loss)	(165)	638	715	614	187	576	888	608	1,802	2,259	2,443
Net income (loss)	(362)	138	472	376	21	393	839	268	624	1,521	1,299
Common Unitholders’ interest in net income (loss)	$ (762)	$ (241)	$ 60	$ (67)	$ (327)	$ 59	$ 298	$ (48)	$ (1,010)	$ (18)	$ 606
Basic net income (loss) per Common Unit	$ (1.47)	$ (0.49)	$ 0.10	$ (0.15)	$ (0.68)	$ 0.11	$ 0.67	$ (0.17)	$ (2.06)	$ (0.09)	$ 1.77
Diluted net income (loss) per Common Unit	$ (1.47)	$ (0.49)	$ 0.10	$ (0.15)	$ (0.68)	$ 0.10	$ 0.67	$ (0.17)	$ (2.06)	$ (0.10)	$ 1.77

Quarterly Financial Data Quarte

Quarterly Financial Data Quarterly Narrative (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Inventory Valuation Reserves	$ (27)	$ 120	$ (170)	$ 104	$ 473
Impairment losses			813	339	$ 370
Impairment losses			670	$ 205
MEP [Member]
Impairment losses			$ 308