Energy Transfer 10-Q 5 Aug 16 2016 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 29, 2016
Entity Information [Abstract]
Entity Registrant Name	Energy Transfer Partners, L.P.
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		523,519,262
Document Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 386	$ 527
Accounts receivable, net	2,542	2,118
Accounts receivable from related companies	354	268
Inventories	1,425	1,213
Derivative assets	35	40
Other current assets	587	532
Total current assets	5,329	4,698
Property, plant and equipment	53,421	50,869
Accumulated depreciation and depletion	(6,434)	(5,782)
Property, plant and equipment, net	46,987	45,087
Advances to and investments in unconsolidated affiliates	5,018	5,003
Non-current derivative assets	18	0
Other non-current assets, net	518	536
Intangible assets, net	4,032	4,421
Goodwill	4,139	5,428
Total assets	66,041	65,173
Current liabilities:
Accounts payable	2,493	1,859
Accounts payable to related companies	21	25
Derivative liabilities	23	63
Accrued and other current liabilities	1,815	2,048
Current maturities of long-term debt	1,007	126
Total current liabilities	5,359	4,121
Long-term debt, less current maturities	27,950	28,553
Long-term notes payable – related companies	182	233
Non-current derivative liabilities	367	137
Deferred income taxes	4,471	4,082
Other non-current liabilities	961	968
Commitments and contingencies
Series A Preferred Units	33	33
Redeemable noncontrolling interests	15	15
Equity:
General Partner	234	306
Limited Partners:
Common Unitholders	16,024	17,043
Class H Unitholder	3,474	3,469
Class I Unitholder	2	14
Accumulated other comprehensive income (loss)	(6)	4
Total partners’ capital	19,728	20,836
Noncontrolling interest	6,975	6,195
Total equity	26,703	27,031
Total liabilities and equity	$ 66,041	$ 65,173

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
REVENUES:
Natural gas sales	$ 695	$ 899	$ 1,533	$ 1,933
NGL sales	1,150	988	2,090	1,969
Crude sales	1,713	2,680	2,923	4,888
Gathering, transportation and other fees	1,045	980	2,005	1,973
Refined product sales (see Note 2)	234	4,434	479	8,090
Other (see Note 2)	452	1,559	740	3,013
Total revenues	5,289	11,540	9,770	21,866
COSTS AND EXPENSES:
Cost of products sold (see Note 2)	3,630	9,354	6,598	17,850
Operating expenses (see Note 2)	374	635	722	1,245
Depreciation, depletion and amortization	496	501	966	980
Selling, general and administrative (see Note 2)	74	162	155	295
Total costs and expenses	4,574	10,652	8,441	20,370
OPERATING INCOME	715	888	1,329	1,496
OTHER INCOME (EXPENSE):
Interest expense, net	(317)	(336)	(636)	(646)
Equity in earnings of unconsolidated affiliates	119	117	195	174
Losses on extinguishments of debt	0	(33)	0	(33)
Gains (losses) on interest rate derivatives	(81)	127	(151)	50
Other, net	27	17	44	24
INCOME BEFORE INCOME TAX BENEFIT	463	780	781	1,065
Income tax benefit	(9)	(59)	(67)	(42)
NET INCOME	472	839	848	1,107
Less: Net income attributable to noncontrolling interest	102	212	167	206
Less: Net loss attributable to predecessor	0	(27)	0	(34)
NET INCOME ATTRIBUTABLE TO PARTNERS	370	654	681	935
General Partner’s interest in net income	223	260	520	502
Class H Unitholder’s interest in net income	85	64	164	118
Class I Unitholder’s interest in net income	2	32	4	65
Common Unitholders’ interest in net income (loss)	$ 60	$ 298	$ (7)	$ 250
NET INCOME (LOSS) PER COMMON UNIT:
Basic	$ 0.10	$ 0.67	$ (0.05)	$ 0.63
Diluted	$ 0.10	$ 0.67	$ (0.05)	$ 0.63

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Net income	$ 472	$ 839	$ 848	$ 1,107
Other comprehensive income (loss), net of tax:
Change in value of derivative instruments accounted for as cash flow hedges	0	0	0	1
Change in value of available-for-sale securities	3	(1)	5	0
Actuarial gain (loss) relating to pension and other postretirement benefit plans	6	0	(3)	45
Foreign currency translation adjustments	0	0	(1)	(2)
Change in other comprehensive income from unconsolidated affiliates	(5)	0	(11)	(2)
Total other comprehensive income (loss)	4	(1)	(10)	42
Comprehensive income	476	838	838	1,149
Less: Comprehensive income attributable to noncontrolling interest	102	212	167	206
Less: Comprehensive loss attributable to predecessor	0	(27)	0	(34)
Comprehensive income attributable to partners	$ 374	$ 653	$ 671	$ 977

Consolidated Statement Of Equit

Consolidated Statement Of Equity - 6 months ended Jun. 30, 2016 - USD ($) $ in Millions	Total	General Partner	Common Units	Class H Units	Class I Units	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
Balance, December 31, 2015 at Dec. 31, 2015	$ 27,031	$ 306	$ 17,043	$ 3,469	$ 14	$ 4	$ 6,195
Distributions to partners	1,813	592	1,046	159	16	0	0
Distributions to noncontrolling interest	(209)	0	0	0	0	0	(209)
Units issued for cash	408	0	408	0	0	0	0
Subsidiary units issued for cash	667	0	14	0	0	0	653
Capital contributions from noncontrolling interest	161	0	0	0	0	0	161
Sunoco, Inc. retail business to Sunoco LP transaction | Sunoco LP Exchange [Member]	(405)	0	(405)	0	0	0	0
Other comprehensive loss, net of tax	(10)	0	0	0	0	(10)	0
Other, net	25	0	17	0	0	0	8
Net income (loss)	848	520	(7)	164	4	0	167
Balance, June 30, 2016 at Jun. 30, 2016	$ 26,703	$ 234	$ 16,024	$ 3,474	$ 2	$ (6)	$ 6,975

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
OPERATING ACTIVITIES
Net income	$ 848	$ 1,107
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	966	980
Deferred income taxes	(79)	79
Amortization included in interest expense	(12)	(21)
Inventory valuation adjustments	(106)	(150)
Unit-based compensation expense	38	43
Losses on extinguishments of debt	0	(33)
Distributions on unvested awards	(13)	(7)
Equity in earnings of unconsolidated affiliates	(195)	(174)
Distributions from unconsolidated affiliates	199	162
Other non-cash	124	(19)
Net change in operating assets and liabilities, net of effects of acquisition	(96)	(938)
Net cash provided by operating activities	1,426	1,133
INVESTING ACTIVITIES
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction	2,200	0
Proceeds from Bakken Pipeline Transaction	0	980
Proceeds from sale of noncontrolling interest	0	64
Cash paid for acquisition of a noncontrolling interest	0	(129)
Cash paid for all other acquisitions	0	(475)
Capital expenditures, excluding allowance for equity funds used during construction	(3,479)	(4,143)
Contributions in aid of construction costs	25	12
Contributions to unconsolidated affiliates	(31)	(43)
Distributions from unconsolidated affiliates in excess of cumulative earnings	56	64
Proceeds from the sale of assets	7	15
Change in restricted cash	(2)	8
Other	(1)	(9)
Net cash used in investing activities	(1,225)	(3,656)
FINANCING ACTIVITIES
Proceeds from borrowings	7,811	12,494
Repayments of long-term debt	(7,514)	(9,386)
Proceeds from Related Party Debt	147	0
Units issued for cash	408	724
Subsidiary units issued for cash	667	1,013
Predecessor units issued for cash	0	34
Capital contributions from noncontrolling interest	161	398
Distributions to partners	(1,813)	(1,384)
Predecessor distributions to partners	0	(202)
Distributions to noncontrolling interest	(209)	(165)
Debt issuance costs	0	(50)
Other	0	(1)
Net cash provided by (used in) financing activities	(342)	3,475
Increase (decrease) in cash and cash equivalents	(141)	952
Cash and cash equivalents, beginning of period	527	663
Cash and cash equivalents, end of period	$ 386	$ 1,615

Operations And Organization

Operations And Organization	6 Months Ended
	Jun. 30, 2016
Operations And Organization [Abstract]
Operations And Organization	ORGANIZATION AND BASIS OF PRESENTATION Organization Energy Transfer Partners, L.P., a publicly traded Delaware master limited partnership, and its subsidiaries (collectively, the “Partnership,” “we,” “us,” “our” or “ETP”) are 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 consolidated financial statements of the Partnership presented herein include our operating subsidiaries described below. Our activities are primarily conducted through our operating subsidiaries (collectively, the “Operating Companies”) as follows: • ETC OLP, a Texas limited partnership primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is 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. • ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of: • Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales. • ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline. • ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas. • CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline. • ETC MEP, a Delaware limited liability company that directly owns a 50% interest in MEP. • ETC Compression, LLC, a Delaware limited liability company engaged in natural gas compression services and related equipment sales. • ETP Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco, Inc. Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. Sunoco, Inc. owned and operated retail marketing assets, which were contributed to Sunoco LP in March 2016, as discussed in Note 2. Subsequent to this transaction, Sunoco Inc.’s assets primarily consist of its ownership in Retail Holdings, which owns noncontrolling interests in Sunoco LP and PES. • Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary crude oil, NGLs, and refined products pipeline, terminalling, and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, NGLs and refined products. • Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP LLC, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETE transferred to ETP 21 million ETP common units. These operations were reported within the retail marketing segment. In connection with this transaction, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. Additionally, in March 2016 and as discussed in Note 2 , ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business effective January 1, 2016. Our financial statements reflect the following reportable business segments: • intrastate transportation and storage; • interstate transportation and storage; • midstream; • liquids transportation and services; • investment in Sunoco Logistics; • retail marketing; and • all other. Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 . In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. Certain prior period amounts have been reclassified to conform to the current year presentation. These reclassifications had no impact on net income or total equity. Merger with Regency. 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”). 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). Use of Estimates The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates. Recent 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. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies. In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidations analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. The Partnership adopted this standard on January 1, 2016, and the adoption did not impact the Partnership’s financial position or results of operations. 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, if any, that adopting this new standard will have on the consolidated financial statements and related disclosures. In March 2016, the FASB issued 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. In addition, the amendments in this update eliminate the guidance in Topic 718 that was indefinitely deferred shortly after the issuance of FASB Statement No. 123 (revised 2004), Share-Based Payment . ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that it will have on the consolidated financial statements and related disclosures.

Contribution Transaction

Contribution Transaction	6 Months Ended
	Jun. 30, 2016
CONTRIBUTION TRANSACTION [Abstract]
Contribution Transaction	CONTRIBUTION TRANSACTION 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. Impact of Contribution Transactions Following is a summary of amounts reflected 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 three and six months ended June 30, 2016 : Three Months Ended June 30, 2015 Six Months Ended June 30, 2015 Revenues $ 5,537 $ 10,342 Cost of products sold 5,003 9,370 Operating expenses 281 552 Selling, general and administrative expenses 58 93

Cash And Cash Equivalents

Cash And Cash Equivalents	6 Months Ended
	Jun. 30, 2016
Cash and Cash Equivalents [Abstract]
Cash And Cash Equivalents	CASH AND CASH EQUIVALENTS 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 acquisition, included in cash flows from operating activities is comprised as follows: Six Months Ended 2016 2015 Accounts receivable $ (471 ) $ 82 Accounts receivable from related companies (129 ) (53 ) Inventories (157 ) (252 ) Other current assets (53 ) (110 ) Other non-current assets, net 8 99 Accounts payable 509 (333 ) Accounts payable to related companies 21 (262 ) Accrued and other current liabilities (22 ) (169 ) Other non-current liabilities 20 30 Derivative assets and liabilities, net 178 30 Net change in operating assets and liabilities, net of effects of acquisition $ (96 ) $ (938 ) Non-cash investing and financing activities are as follows: Six Months Ended 2016 2015 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 861 $ 693 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 issuances 14 102 NON-CASH FINANCING ACTIVITIES: 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 Redemption of common units in connection with the Bakken Pipeline Transaction — 999

Inventories

Inventories	6 Months Ended
	Jun. 30, 2016
Inventory, Gross [Abstract]
Inventories	INVENTORIES Inventories consisted of the following: June 30, 2016 December 31, 2015 Natural gas and NGLs $ 552 $ 415 Crude oil 564 424 Refined products 106 104 Other 203 270 Total inventories $ 1,425 $ 1,213 We utilize commodity derivatives to manage price volatility associated with our natural gas inventories stored in our Bammel storage facility. 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.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2016
Fair Value Measurements [Abstract]
Fair Value Measurements	FAIR VALUE MEASURES Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of June 30, 2016 was $29.25 billion and $28.96 billion , respectively. As of December 31, 2015 , the aggregate fair value and carrying amount of our consolidated 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 the 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 six months ended June 30, 2016 , no transfers were made between any levels within the fair value hierarchy. 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 June 30, 2016 and December 31, 2015 based on inputs used to derive their fair values: Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ 29 $ — $ 29 $ — Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 18 18 — — Swing Swaps IFERC 6 — 6 — Fixed Swaps/Futures 41 41 — — Forward Physical Swaps 4 — 4 — Power: Forwards 30 — 30 — Options – Calls 3 3 — — Natural Gas Liquids – Forwards/Swaps 76 76 — — Refined Products – Futures 1 1 — — Crude – Futures 5 5 — — Total commodity derivatives 184 144 40 — Total assets $ 213 $ 144 $ 69 $ — Liabilities: Interest rate derivatives $ (358 ) $ — $ (358 ) $ — Embedded derivatives in the Preferred Units (9 ) — — (9 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (17 ) (17 ) — — Swing Swaps IFERC (6 ) (1 ) (5 ) — Fixed Swaps/Futures (64 ) (64 ) — — Forward Physical Swaps (2 ) — (2 ) — Power: Forwards (28 ) — (28 ) — Futures (1 ) (1 ) — — Natural Gas Liquids – Forwards/Swaps (88 ) (88 ) — — Refined Products – Futures (9 ) (9 ) — — Crude – Futures (7 ) (7 ) — — Total commodity derivatives (222 ) (187 ) (35 ) — Total liabilities $ (589 ) $ (187 ) $ (393 ) $ (9 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 16 $ 16 $ — $ — Swing Swaps IFERC 10 2 8 — Fixed Swaps/Futures 274 274 — — Forward Physical 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 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 ) 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 six months ended June 30, 2016 . Balance, December 31, 2015 $ (5 ) Net unrealized gains included in other income (expense) (4 ) Balance, June 30, 2016 $ (9 )

Net Income Per Limited Partner

Net Income Per Limited Partner Unit	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Net Income (Loss) Per Limited Partner Unit [Text Block]	NET INCOME (LOSS) PER LIMITED PARTNER UNIT 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 the General Partner, the holder of the IDRs pursuant to the 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. Loss attributable to predecessor represents amounts allocated to the former Regency partners and have no impact on net income (loss) per unit for the periods prior to the Regency Merger. A reconciliation of net income and weighted average units used in computing basic and diluted net income (loss) per unit is as follows: Three Months Ended Six Months Ended 2016 2015 2016 2015 Net income $ 472 $ 839 $ 848 $ 1,107 Less: Income attributable to noncontrolling interest 102 212 167 206 Less: Loss attributable to predecessor — (27 ) — (34 ) Net income, net of noncontrolling interest and predecessor income 370 654 681 935 General Partner’s interest in net income 223 260 520 502 Class H Unitholder’s interest in net income 85 64 164 118 Class I Unitholder’s interest in net income 2 32 4 65 Common Unitholders’ interest in net income (loss) 60 298 (7 ) 250 Additional earnings allocated to General Partner (3 ) (2 ) (6 ) (4 ) Distributions on employee unit awards, net of allocation to General Partner (5 ) (3 ) (10 ) (7 ) Net income (loss) available to Common Unitholders $ 52 $ 293 $ (23 ) $ 239 Weighted average Common Units – basic (1) 501.6 434.8 495.9 379.6 Basic net income (loss) per Common Unit $ 0.10 $ 0.67 $ (0.05 ) $ 0.63 Net income (loss) available to Common Unitholders $ 52 $ 293 $ (23 ) $ 239 Income attributable to Preferred Units (4 ) — (3 ) — Diluted net income (loss) available to Common Unitholders $ 48 $ 293 $ (26 ) $ 239 Weighted average Common Units – basic (1) 501.6 434.8 495.9 379.6 Dilutive effect of unvested employee unit awards 0.7 1.5 — 1.5 Dilutive effect of Preferred Units 0.4 — 0.4 — Weighted average Common Units – diluted (1) 502.7 436.3 496.3 381.1 Diluted net income (loss) per Common Unit $ 0.10 $ 0.67 $ (0.05 ) $ 0.63 (1) Excludes Common Units owned by the Partnership’s consolidated subsidiaries.

Debt Obligations

Debt Obligations	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Debt Obligations	DEBT OBLIGATIONS Credit Facilities ETP Credit Facility The ETP Credit Facility allows for borrowings of up to $3.75 billion and expires in November 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. As of June 30, 2016 , the ETP Credit Facility had $1.13 billion of outstanding borrowings. 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. As of June 30, 2016 , the Sunoco Logistics Credit Facility had $1.26 billion of outstanding borrowings. ETP Senior Notes Subsequent to the Regency Merger in 2015, ETP assumed $3.80 billion total aggregate principal amount of Regency’s senior notes, which remained outstanding as of June 30, 2016 . These notes were previously guaranteed by certain consolidated subsidiaries that had previously been consolidated by Regency. The subsidiary guarantees on all of these outstanding notes have been released. Sunoco Logistics Senior Notes Sunoco Logistics had $175 million of 6.125% senior notes which matured and were repaid in May 2016, using borrowings under the $2.50 billion Sunoco Logistics Credit Facility. 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. Bakken Financing 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 facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects. Compliance with Our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of June 30, 2016 .

Equity

Equity	6 Months Ended
	Jun. 30, 2016
Partners' Capital Notes [Abstract]
Equity	EQUITY ETP The changes in outstanding common units during the six months ended June 30, 2016 were as follows: Number of Units Number of common units at December 31, 2015 505.6 Common units issued in connection with equity distribution agreements 11.2 Common units issued in connection with the distribution reinvestment plan 3.1 Number of common units at June 30, 2016 519.9 During the six months ended June 30, 2016 , the Partnership received proceeds of $324 million , net of $3 million commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes. As of June 30, 2016 , none of the Partnership’s common units were available to be issued under an equity distribution agreement. In July 2016, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.50 billion . During the six months ended June 30, 2016 , distributions of $84 million were reinvested under the distribution reinvestment plan. As of June 30, 2016 , a total of 8.4 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment plan. Sunoco Logistics During the six months ended June 30, 2016 , Sunoco Logistics received proceeds of $667 million , net of $7 million commissions and fees, from the issuance of Sunoco Logistics common units pursuant to equity distribution agreements, which were used for general partnership purposes. As a result of Sunoco Logistics’ issuances of common units during the six months ended June 30, 2016 , the Partnership recognized increases in partners’ capital of $14 million . Bakken Equity Sale In August 2016, ETP and Sunoco Logistics announced they have signed an agreement to sell 36.75% of the Bakken Pipeline project to MarEn Bakken Company LLC, an entity jointly owned by Enbridge Energy Partners, L.P. and Marathon Petroleum Corporation, for $2.00 billion in cash. The sale is expected to close in the third quarter of 2016, subject to certain closing conditions. ETP and Sunoco Logistics will receive $1.20 billion and $800 million in cash at closing, respectively, and will own a combined 38.25% of the Bakken Pipeline project. Quarterly Distributions of Available Cash Following are distributions declared and/or paid by the Partnership subsequent to December 31, 2015 : Quarter Ended Record Date Payment Date Rate 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 In July 2016, ETE agreed to relinquish incentive distributions over seven quarters, beginning with $75 million for the quarter ended June 30, 2016. ETE has also previously agreed to relinquish additional incentive distributions. In the aggregate, including relinquishment agreed to in July 2016, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units. Total Year 2016 (remainder) $ 249 2017 593 2018 105 2019 95 Sunoco Logistics Quarterly Distributions of Available Cash Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2015 : Quarter Ended Record Date Payment Date Rate 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 Accumulated Other Comprehensive Income (Loss) The following table presents the components of AOCI, net of tax: June 30, 2016 December 31, 2015 Available-for-sale securities $ 5 $ — Foreign currency translation adjustment (5 ) (4 ) Actuarial gain related to pensions and other postretirement benefits 5 8 Investments in unconsolidated affiliates, net (11 ) — Total AOCI, net of tax $ (6 ) $ 4

Income Taxes (Notes)

Income Taxes (Notes)	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES For the three and six months ended June 30, 2016 and 2015 , the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries. Also, for the three months ended June 30, 2015 , the Partnership income tax expense was favorably impacted by $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015.

Regulatory Matters, Commitments

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	6 Months Ended
	Jun. 30, 2016
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES Contingent Residual Support Agreement – AmeriGas In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchasers. In June 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETP under the contingent residual support agreement. As of June 30, 2016, ETP continued to provide contingent, residual support of approximately $1 billion of borrowings. ETP Retail Holdings Guarantee of Sunoco LP Notes Retail Holdings has provided a 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. 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 our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations. We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058 . 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: Three Months Ended Six Months Ended 2016 2015 2016 2015 Rental expense (1) $ 21 $ 54 $ 39 $ 106 Less: Sublease rental income — (4 ) — (12 ) Rental expense, net $ 21 $ 50 $ 39 $ 94 (1) Includes contingent rentals totaling $6 million and $10 million for the three and six months ended June 30, 2015 , respectively. Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. 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. Mont Belvieu Incident On June 26, 2016, a subsurface release of hydrocarbons and water, and a subsequent fire, occurred at Lone Star’s South Terminal. All employees and contractors were accounted for, and there were no injuries. The cause of the fire and evaluation of possible damages is currently under investigation. MTBE Litigation Sunoco, Inc., along with other refiners, manufacturers and sellers of gasoline, is a defendant 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 June 30, 2016 , Sunoco, Inc. is a defendant in five cases, including cases initiated by the States of New Jersey, Vermont, Pennsylvania, 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. Sunoco informed Judge Goodman it is open to participating in global settlement discussions in a global mediation forum. The remaining portion of the New Jersey case remains in the MDL. It is reasonably possible that a loss may be realized; 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’ Answering Brief is currently due on July 29, 2016. 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 approximately $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. 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 June 30, 2016 and December 31, 2015 , accruals of approximately $56 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 June 30, 2016 or December 31, 2015 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Attorney General of the Commonwealth of Massachusetts v. New England Gas Company. On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries. The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling approximately $19 million , that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50% , level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The hearing officer has deferred consideration of Southern Union’s motion to dismiss. The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses. 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. 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 its Mont Belvieu Gas Plant. The Partnership has accrued $300,000 related to the claim. As of April 2016, the Agreed Order is in the approval process with the Texas Commission on Environmental Quality and includes a $21,000 penalty and 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. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. 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. • Legacy sites related to Sunoco, Inc., that are subject to environmental assessments include 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 June 30, 2016 , Sunoco, Inc. had been named as a PRP at approximately 49 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. June 30, 2016 December 31, 2015 Current $ 35 $ 41 Non-current 289 326 Total environmental liabilities $ 324 $ 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 three months ended June 30, 2016 and 2015 , Sunoco, Inc. recorded $8 million and $11 million , respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30, 2016 and 2015 , Sunoco, Inc. recorded $14 million and $18 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 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 management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures. In January 2012, Sunoco Logistics experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which Sunoco Logistics is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. Sunoco Logistics also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. Sunoco Logistics has also received a "No Further Action" approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, Sunoco Logistics received a proposed penalty from the EPA and U.S. Department of Justice associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position. Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

Derivative Assets And Liabiliti

Derivative Assets And Liabilities	6 Months Ended
	Jun. 30, 2016
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Price Risk Management 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 futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing segment. 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: June 30, 2016 December 31, 2015 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures 5,825,000 2016-2017 (602,500 ) 2016-2017 Basis Swaps IFERC/NYMEX (1) 7,920,000 2016-2017 (31,240,000 ) 2016-2017 Power (Megawatt): Forwards 272,164 2016-2017 357,092 2016-2017 Futures (320,257 ) 2016-2017 (109,791 ) 2016 Options – Puts (424,000 ) 2016 260,534 2016 Options – Calls 696,000 2016 1,300,647 2016 Crude (Bbls): Futures (222,000 ) 2016-2017 (591,000 ) 2016-2017 (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (522,500 ) 2016-2017 (6,522,500 ) 2016-2017 Swing Swaps IFERC 34,465,000 2016-2017 71,340,000 2016-2017 Fixed Swaps/Futures (3,835,000 ) 2016-2018 (14,380,000 ) 2016-2018 Forward Physical Contracts 3,838,458 2016-2017 21,922,484 2016-2017 Natural Gas Liquid (Bbls) – Forwards/Swaps (10,443,400 ) 2016 (8,146,800 ) 2016-2018 Refined Products (Bbls) – Futures (1,557,000 ) 2016-2017 (993,000 ) 2016-2017 Corn (Bushels) – Futures — — 1,185,000 2016 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (42,167,500 ) 2016-2017 (37,555,000 ) 2016 Fixed Swaps/Futures (42,167,500 ) 2016-2017 (37,555,000 ) 2016 Hedged Item – Inventory 42,167,500 2016-2017 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 June 30, 2016 December 31, 2015 July 2016 (2)(4) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate $ — $ 200 July 2017 (3)(4) 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 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 July 2019 (3) Forward-starting to pay a fixed rate of 3.25% and receive a floating rate 200 200 (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. (4) ETP previously had outstanding forward starting interest rate swaps, which were scheduled to expire in July 2016, with a total notional value of $200 million . In June 2016, ETP extended the expiration of those swaps to July 2017. 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 June 30, 2016 December 31, 2015 June 30, 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) 138 353 (173 ) (306 ) Commodity derivatives 46 57 (45 ) (41 ) Interest rate derivatives 29 — (358 ) (171 ) Embedded derivatives in ETP Preferred Units — — (9 ) (5 ) 213 410 (585 ) (523 ) Total derivatives $ 213 $ 448 $ (589 ) $ (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 June 30, 2016 December 31, 2015 June 30, 2016 December 31, 2015 Derivatives without offsetting agreements Derivative assets (liabilities) $ 29 $ — $ (367 ) $ (176 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 46 57 (45 ) (41 ) Broker cleared derivative contracts Other current assets 138 391 (177 ) (309 ) Total gross derivatives 213 448 (589 ) (526 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (22 ) (17 ) 22 17 Payments on margin deposit Other current assets (138 ) (309 ) 138 309 Total net derivatives $ 53 $ 122 $ (429 ) $ (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: Change in Value Recognized in OCI on Derivatives (Effective Portion) Three Months Ended Six Months Ended 2016 2015 2016 2015 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ — $ — $ 1 Total $ — $ — $ — $ 1 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 Three Months Ended Six Months Ended 2016 2015 2016 2015 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 21 $ 11 $ 17 $ 8 Total $ 21 $ 11 $ 17 $ 8 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives Three Months Ended Six Months Ended 2016 2015 2016 2015 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (7 ) $ (6 ) $ (16 ) $ (8 ) Commodity derivatives – Non-trading Cost of products sold (48 ) (40 ) (43 ) (48 ) Interest rate derivatives Gains (losses) on interest rate derivatives (81 ) 127 (151 ) 50 Embedded derivatives Other, net (4 ) 2 (4 ) 4 Total $ (140 ) $ 83 $ (214 ) $ (2 )

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2016
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS ETE has agreements with subsidiaries to provide or receive various management and 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. 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: Three Months Ended Six Months Ended 2016 2015 2016 2015 Affiliated revenues $ 133 $ 130 $ 207 $ 206 The following table summarizes the related company balances on our consolidated balance sheets: June 30, 2016 December 31, 2015 Accounts receivable from related companies: ETE $ 58 $ 110 Sunoco LP 185 3 PES 9 10 FGT 9 13 Lake Charles LNG 30 36 Trans-Pecos Pipeline, LLC — 29 Comanche Trail Pipeline, LLC 9 22 Other 54 45 Total accounts receivable from related companies: $ 354 $ 268 Accounts payable to related companies: Sunoco LP $ 10 $ 5 FGT 1 1 Lake Charles LNG 2 3 Other 8 16 Total accounts payable to related companies: $ 21 $ 25 The following table summarizes the related company balances on our consolidated balance sheets: June 30, 2016 December 31, 2015 Long-term notes payable – related companies: Sunoco LP $ 75 $ 233 Phillips 66 107 — Long-term notes payable – related companies: $ 182 $ 233

Reportable Segments

Reportable Segments	6 Months Ended
	Jun. 30, 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; • retail marketing; and • all other. 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 retail marketing 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, 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: Three Months Ended Six Months Ended 2016 2015 2016 2015 Revenues: Intrastate transportation and storage: Revenues from external customers $ 428 $ 486 $ 874 $ 1,027 Intersegment revenues 113 83 225 128 541 569 1,099 1,155 Interstate transportation and storage: Revenues from external customers 229 239 483 510 Intersegment revenues 5 4 10 9 234 243 493 519 Midstream: Revenues from external customers 690 767 1,217 1,516 Intersegment revenues 640 473 1,205 875 1,330 1,240 2,422 2,391 Liquids transportation and services: Revenues from external customers 1,099 783 1,928 1,595 Intersegment revenues 11 45 101 68 1,110 828 2,029 1,663 Investment in Sunoco Logistics: Revenues from external customers 2,250 3,120 3,979 5,646 Intersegment revenues 18 82 66 128 2,268 3,202 4,045 5,774 Retail marketing: Revenues from external customers — 5,557 — 10,339 Intersegment revenues — (20 ) — 3 — 5,537 — 10,342 All other: Revenues from external customers 593 588 1,289 1,233 Intersegment revenues 118 134 276 231 711 722 1,565 1,464 Eliminations (905 ) (801 ) (1,883 ) (1,442 ) Total revenues $ 5,289 $ 11,540 $ 9,770 $ 21,866 Three Months Ended Six Months Ended 2016 2015 2016 2015 Segment Adjusted EBITDA: Intrastate transportation and storage $ 149 $ 117 $ 328 $ 294 Interstate transportation and storage 278 285 570 586 Midstream 298 352 561 662 Liquids transportation and services 220 154 447 323 Investment in Sunoco Logistics 245 326 594 547 Retail marketing 68 140 125 269 All other 112 114 157 173 Total 1,370 1,488 2,782 2,854 Depreciation, depletion and amortization (496 ) (501 ) (966 ) (980 ) Interest expense, net (317 ) (336 ) (636 ) (646 ) Gains (losses) on interest rate derivatives (81 ) 127 (151 ) 50 Non-cash unit-based compensation expense (19 ) (23 ) (38 ) (43 ) Unrealized losses on commodity risk management activities (18 ) (42 ) (81 ) (119 ) Inventory valuation adjustments 132 184 106 150 Losses on extinguishments of debt — (33 ) — (33 ) Adjusted EBITDA related to unconsolidated affiliates (252 ) (215 ) (471 ) (361 ) Equity in earnings of unconsolidated affiliates 119 117 195 174 Other, net 25 14 41 19 Income before income tax benefit $ 463 $ 780 $ 781 $ 1,065 June 30, 2016 December 31, 2015 Assets: Intrastate transportation and storage $ 5,134 $ 4,882 Interstate transportation and storage 11,551 11,345 Midstream 17,604 17,111 Liquids transportation and services 8,977 7,235 Investment in Sunoco Logistics 16,780 15,423 Retail marketing 1,387 3,218 All other 4,608 5,959 Total assets $ 66,041 $ 65,173

Operations And Organization Acc

Operations And Organization Accounting Policy (Policies)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
Combination of Entities under Common Control, Policy [Policy Text Block]	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).
New Accounting Pronouncements, Policy [Policy Text Block]	Recent 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. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies. In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidations analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. The Partnership adopted this standard on January 1, 2016, and the adoption did not impact the Partnership’s financial position or results of operations. 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, if any, that adopting this new standard will have on the consolidated financial statements and related disclosures. In March 2016, the FASB issued 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. In addition, the amendments in this update eliminate the guidance in Topic 718 that was indefinitely deferred shortly after the issuance of FASB Statement No. 123 (revised 2004), Share-Based Payment . ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that it will have on the consolidated financial statements and related disclosures.

Contribution Transaction Impact

Contribution Transaction Impact of Contribution Transaction (Tables)	6 Months Ended
	Jun. 30, 2015
Sunoco, LLC and legacy Sunoco, Inc. retail business [Member]
Schedule of Statement of Operations Supplemental Disclosures [Table Text Block]	Impact of Contribution Transactions Following is a summary of amounts reflected 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 three and six months ended June 30, 2016 : Three Months Ended June 30, 2015 Six Months Ended June 30, 2015 Revenues $ 5,537 $ 10,342 Cost of products sold 5,003 9,370 Operating expenses 281 552 Selling, general and administrative expenses 58 93

Cash And Cash Equivalents (Tabl

Cash And Cash Equivalents (Tables)	6 Months Ended
	Jun. 30, 2016
Cash and Cash Equivalents [Abstract]
Net Cash Provided By Operating Activities	The net change in operating assets and liabilities, net of effects of acquisition, included in cash flows from operating activities is comprised as follows: Six Months Ended 2016 2015 Accounts receivable $ (471 ) $ 82 Accounts receivable from related companies (129 ) (53 ) Inventories (157 ) (252 ) Other current assets (53 ) (110 ) Other non-current assets, net 8 99 Accounts payable 509 (333 ) Accounts payable to related companies 21 (262 ) Accrued and other current liabilities (22 ) (169 ) Other non-current liabilities 20 30 Derivative assets and liabilities, net 178 30 Net change in operating assets and liabilities, net of effects of acquisition $ (96 ) $ (938 )
Non-Cash Investing And Financing Activities	Non-cash investing and financing activities are as follows: Six Months Ended 2016 2015 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 861 $ 693 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 issuances 14 102 NON-CASH FINANCING ACTIVITIES: 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 Redemption of common units in connection with the Bakken Pipeline Transaction — 999

Inventories (Tables)

Inventories (Tables)	6 Months Ended
	Jun. 30, 2016
Inventory, Gross [Abstract]
Schedule Of Inventories	Inventories consisted of the following: June 30, 2016 December 31, 2015 Natural gas and NGLs $ 552 $ 415 Crude oil 564 424 Refined products 106 104 Other 203 270 Total inventories $ 1,425 $ 1,213

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Measurements [Abstract]
Fair Value Of Assets And Liabilities Measured And Recorded On Recurring Basis	The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2016 and December 31, 2015 based on inputs used to derive their fair values: Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Interest rate derivatives $ 29 $ — $ 29 $ — Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 18 18 — — Swing Swaps IFERC 6 — 6 — Fixed Swaps/Futures 41 41 — — Forward Physical Swaps 4 — 4 — Power: Forwards 30 — 30 — Options – Calls 3 3 — — Natural Gas Liquids – Forwards/Swaps 76 76 — — Refined Products – Futures 1 1 — — Crude – Futures 5 5 — — Total commodity derivatives 184 144 40 — Total assets $ 213 $ 144 $ 69 $ — Liabilities: Interest rate derivatives $ (358 ) $ — $ (358 ) $ — Embedded derivatives in the Preferred Units (9 ) — — (9 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (17 ) (17 ) — — Swing Swaps IFERC (6 ) (1 ) (5 ) — Fixed Swaps/Futures (64 ) (64 ) — — Forward Physical Swaps (2 ) — (2 ) — Power: Forwards (28 ) — (28 ) — Futures (1 ) (1 ) — — Natural Gas Liquids – Forwards/Swaps (88 ) (88 ) — — Refined Products – Futures (9 ) (9 ) — — Crude – Futures (7 ) (7 ) — — Total commodity derivatives (222 ) (187 ) (35 ) — Total liabilities $ (589 ) $ (187 ) $ (393 ) $ (9 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 16 $ 16 $ — $ — Swing Swaps IFERC 10 2 8 — Fixed Swaps/Futures 274 274 — — Forward Physical 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 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 )
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 six months ended June 30, 2016 . Balance, December 31, 2015 $ (5 ) Net unrealized gains included in other income (expense) (4 ) Balance, June 30, 2016 $ (9 )

Net Income Per Limited Partne25

Net Income Per Limited Partner Unit (Tables)	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	A reconciliation of net income and weighted average units used in computing basic and diluted net income (loss) per unit is as follows: Three Months Ended Six Months Ended 2016 2015 2016 2015 Net income $ 472 $ 839 $ 848 $ 1,107 Less: Income attributable to noncontrolling interest 102 212 167 206 Less: Loss attributable to predecessor — (27 ) — (34 ) Net income, net of noncontrolling interest and predecessor income 370 654 681 935 General Partner’s interest in net income 223 260 520 502 Class H Unitholder’s interest in net income 85 64 164 118 Class I Unitholder’s interest in net income 2 32 4 65 Common Unitholders’ interest in net income (loss) 60 298 (7 ) 250 Additional earnings allocated to General Partner (3 ) (2 ) (6 ) (4 ) Distributions on employee unit awards, net of allocation to General Partner (5 ) (3 ) (10 ) (7 ) Net income (loss) available to Common Unitholders $ 52 $ 293 $ (23 ) $ 239 Weighted average Common Units – basic (1) 501.6 434.8 495.9 379.6 Basic net income (loss) per Common Unit $ 0.10 $ 0.67 $ (0.05 ) $ 0.63 Net income (loss) available to Common Unitholders $ 52 $ 293 $ (23 ) $ 239 Income attributable to Preferred Units (4 ) — (3 ) — Diluted net income (loss) available to Common Unitholders $ 48 $ 293 $ (26 ) $ 239 Weighted average Common Units – basic (1) 501.6 434.8 495.9 379.6 Dilutive effect of unvested employee unit awards 0.7 1.5 — 1.5 Dilutive effect of Preferred Units 0.4 — 0.4 — Weighted average Common Units – diluted (1) 502.7 436.3 496.3 381.1 Diluted net income (loss) per Common Unit $ 0.10 $ 0.67 $ (0.05 ) $ 0.63 (1) Excludes Common Units owned by the Partnership’s consolidated subsidiaries.

Equity (Tables)

Equity (Tables)	6 Months Ended
	Jun. 30, 2016
Change In Common Units	The changes in outstanding common units during the six months ended June 30, 2016 were as follows: Number of Units Number of common units at December 31, 2015 505.6 Common units issued in connection with equity distribution agreements 11.2 Common units issued in connection with the distribution reinvestment plan 3.1 Number of common units at June 30, 2016 519.9
Schedule of Net IDR Subsidies [Table Text Block]	Total Year 2016 (remainder) $ 249 2017 593 2018 105 2019 95
Accumulated Other Comprehensive Income	The following table presents the components of AOCI, net of tax: June 30, 2016 December 31, 2015 Available-for-sale securities $ 5 $ — Foreign currency translation adjustment (5 ) (4 ) Actuarial gain related to pensions and other postretirement benefits 5 8 Investments in unconsolidated affiliates, net (11 ) — Total AOCI, net of tax $ (6 ) $ 4
ETP [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Following are distributions declared and/or paid by the Partnership subsequent to December 31, 2015 : Quarter Ended Record Date Payment Date Rate 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
Sunoco Logistics [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2015 : Quarter Ended Record Date Payment Date Rate 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

Regulatory Matters, Commitmen27

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)	6 Months Ended
	Jun. 30, 2016
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Schedule of Rent Expense [Table Text Block]	We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058 . 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: Three Months Ended Six Months Ended 2016 2015 2016 2015 Rental expense (1) $ 21 $ 54 $ 39 $ 106 Less: Sublease rental income — (4 ) — (12 ) Rental expense, net $ 21 $ 50 $ 39 $ 94 (1) Includes contingent rentals totaling $6 million and $10 million for the three and six months ended June 30, 2015
Environmental Exit Costs by Cost [Table Text Block]	June 30, 2016 December 31, 2015 Current $ 35 $ 41 Non-current 289 326 Total environmental liabilities $ 324 $ 367

Derivative Assets And Liabili28

Derivative Assets And Liabilities (Tables)	6 Months Ended
	Jun. 30, 2016
Derivative [Line Items]
Outstanding Commodity-Related Derivatives	The following table details our outstanding commodity-related derivatives: June 30, 2016 December 31, 2015 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (MMBtu): Fixed Swaps/Futures 5,825,000 2016-2017 (602,500 ) 2016-2017 Basis Swaps IFERC/NYMEX (1) 7,920,000 2016-2017 (31,240,000 ) 2016-2017 Power (Megawatt): Forwards 272,164 2016-2017 357,092 2016-2017 Futures (320,257 ) 2016-2017 (109,791 ) 2016 Options – Puts (424,000 ) 2016 260,534 2016 Options – Calls 696,000 2016 1,300,647 2016 Crude (Bbls): Futures (222,000 ) 2016-2017 (591,000 ) 2016-2017 (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (522,500 ) 2016-2017 (6,522,500 ) 2016-2017 Swing Swaps IFERC 34,465,000 2016-2017 71,340,000 2016-2017 Fixed Swaps/Futures (3,835,000 ) 2016-2018 (14,380,000 ) 2016-2018 Forward Physical Contracts 3,838,458 2016-2017 21,922,484 2016-2017 Natural Gas Liquid (Bbls) – Forwards/Swaps (10,443,400 ) 2016 (8,146,800 ) 2016-2018 Refined Products (Bbls) – Futures (1,557,000 ) 2016-2017 (993,000 ) 2016-2017 Corn (Bushels) – Futures — — 1,185,000 2016 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (MMBtu): Basis Swaps IFERC/NYMEX (42,167,500 ) 2016-2017 (37,555,000 ) 2016 Fixed Swaps/Futures (42,167,500 ) 2016-2017 (37,555,000 ) 2016 Hedged Item – Inventory 42,167,500 2016-2017 37,555,000 2016 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Interest Rate Swaps Outstanding	The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes: Term Type (1) Notional Amount Outstanding June 30, 2016 December 31, 2015 July 2016 (2)(4) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate $ — $ 200 July 2017 (3)(4) 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 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 July 2019 (3) Forward-starting to pay a fixed rate of 3.25% and receive a floating rate 200 200 (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. (4) ETP previously had outstanding forward starting interest rate swaps, which were scheduled to expire in July 2016, with a total notional value of $200 million . In June 2016, ETP extended the expiration of those swaps to July 2017.
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 June 30, 2016 December 31, 2015 June 30, 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) 138 353 (173 ) (306 ) Commodity derivatives 46 57 (45 ) (41 ) Interest rate derivatives 29 — (358 ) (171 ) Embedded derivatives in ETP Preferred Units — — (9 ) (5 ) 213 410 (585 ) (523 ) Total derivatives $ 213 $ 448 $ (589 ) $ (526 )
Derivatives, Offsetting Fair Value Amounts [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 June 30, 2016 December 31, 2015 June 30, 2016 December 31, 2015 Derivatives without offsetting agreements Derivative assets (liabilities) $ 29 $ — $ (367 ) $ (176 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 46 57 (45 ) (41 ) Broker cleared derivative contracts Other current assets 138 391 (177 ) (309 ) Total gross derivatives 213 448 (589 ) (526 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (22 ) (17 ) 22 17 Payments on margin deposit Other current assets (138 ) (309 ) 138 309 Total net derivatives $ 53 $ 122 $ (429 ) $ (200 )
Partnership's Derivative Assets And Liabilities	The following tables summarize the amounts recognized with respect to our derivative financial instruments: Change in Value Recognized in OCI on Derivatives (Effective Portion) Three Months Ended Six Months Ended 2016 2015 2016 2015 Derivatives in cash flow hedging relationships: Commodity derivatives $ — $ — $ — $ 1 Total $ — $ — $ — $ 1
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 Three Months Ended Six Months Ended 2016 2015 2016 2015 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ 21 $ 11 $ 17 $ 8 Total $ 21 $ 11 $ 17 $ 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 Three Months Ended Six Months Ended 2016 2015 2016 2015 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Cost of products sold $ (7 ) $ (6 ) $ (16 ) $ (8 ) Commodity derivatives – Non-trading Cost of products sold (48 ) (40 ) (43 ) (48 ) Interest rate derivatives Gains (losses) on interest rate derivatives (81 ) 127 (151 ) 50 Embedded derivatives Other, net (4 ) 2 (4 ) 4 Total $ (140 ) $ 83 $ (214 ) $ (2 )

Related Party Transactions (Tab

Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2016
Related Party Transactions [Abstract]
Related Party Transactions For Period Presented [Table Text Block]	The following table summarizes the affiliate revenues on our consolidated statements of operations: Three Months Ended Six Months Ended 2016 2015 2016 2015 Affiliated revenues $ 133 $ 130 $ 207 $ 206
Related Party Transactions [table text block]	June 30, 2016 December 31, 2015 Accounts receivable from related companies: ETE $ 58 $ 110 Sunoco LP 185 3 PES 9 10 FGT 9 13 Lake Charles LNG 30 36 Trans-Pecos Pipeline, LLC — 29 Comanche Trail Pipeline, LLC 9 22 Other 54 45 Total accounts receivable from related companies: $ 354 $ 268 Accounts payable to related companies: Sunoco LP $ 10 $ 5 FGT 1 1 Lake Charles LNG 2 3 Other 8 16 Total accounts payable to related companies: $ 21 $ 25 The following table summarizes the related company balances on our consolidated balance sheets: June 30, 2016 December 31, 2015 Long-term notes payable – related companies: Sunoco LP $ 75 $ 233 Phillips 66 107 — Long-term notes payable – related companies: $ 182 $ 233

Reportable Segments (Tables)

Reportable Segments (Tables)	6 Months Ended
	Jun. 30, 2016
Sales Revenue, Segment [Member]
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	The following tables present financial information by segment: Three Months Ended Six Months Ended 2016 2015 2016 2015 Revenues: Intrastate transportation and storage: Revenues from external customers $ 428 $ 486 $ 874 $ 1,027 Intersegment revenues 113 83 225 128 541 569 1,099 1,155 Interstate transportation and storage: Revenues from external customers 229 239 483 510 Intersegment revenues 5 4 10 9 234 243 493 519 Midstream: Revenues from external customers 690 767 1,217 1,516 Intersegment revenues 640 473 1,205 875 1,330 1,240 2,422 2,391 Liquids transportation and services: Revenues from external customers 1,099 783 1,928 1,595 Intersegment revenues 11 45 101 68 1,110 828 2,029 1,663 Investment in Sunoco Logistics: Revenues from external customers 2,250 3,120 3,979 5,646 Intersegment revenues 18 82 66 128 2,268 3,202 4,045 5,774 Retail marketing: Revenues from external customers — 5,557 — 10,339 Intersegment revenues — (20 ) — 3 — 5,537 — 10,342 All other: Revenues from external customers 593 588 1,289 1,233 Intersegment revenues 118 134 276 231 711 722 1,565 1,464 Eliminations (905 ) (801 ) (1,883 ) (1,442 ) Total revenues $ 5,289 $ 11,540 $ 9,770 $ 21,866
Operating Segments [Member]
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Three Months Ended Six Months Ended 2016 2015 2016 2015 Segment Adjusted EBITDA: Intrastate transportation and storage $ 149 $ 117 $ 328 $ 294 Interstate transportation and storage 278 285 570 586 Midstream 298 352 561 662 Liquids transportation and services 220 154 447 323 Investment in Sunoco Logistics 245 326 594 547 Retail marketing 68 140 125 269 All other 112 114 157 173 Total 1,370 1,488 2,782 2,854 Depreciation, depletion and amortization (496 ) (501 ) (966 ) (980 ) Interest expense, net (317 ) (336 ) (636 ) (646 ) Gains (losses) on interest rate derivatives (81 ) 127 (151 ) 50 Non-cash unit-based compensation expense (19 ) (23 ) (38 ) (43 ) Unrealized losses on commodity risk management activities (18 ) (42 ) (81 ) (119 ) Inventory valuation adjustments 132 184 106 150 Losses on extinguishments of debt — (33 ) — (33 ) Adjusted EBITDA related to unconsolidated affiliates (252 ) (215 ) (471 ) (361 ) Equity in earnings of unconsolidated affiliates 119 117 195 174 Other, net 25 14 41 19 Income before income tax benefit $ 463 $ 780 $ 781 $ 1,065
Assets Segments [Member]
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	June 30, 2016 December 31, 2015 Assets: Intrastate transportation and storage $ 5,134 $ 4,882 Interstate transportation and storage 11,551 11,345 Midstream 17,604 17,111 Liquids transportation and services 8,977 7,235 Investment in Sunoco Logistics 16,780 15,423 Retail marketing 1,387 3,218 All other 4,608 5,959 Total assets $ 66,041 $ 65,173

Operations And Organization Ope

Operations And Organization Operations And Organization (Details) - shares shares in Millions	1 Months Ended		6 Months Ended
	Mar. 31, 2016	Jul. 31, 2015	Jun. 30, 2016
Citrus [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%
FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%
MEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%
Fayetteville Express Pipeline, LLC [Member] | FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Citrus [Member] | FGT
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Sunoco LP Exchange [Member]
Stock Repurchased During Period, Shares		21
Sunoco LP Exchange [Member] | Sunoco GP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Dropdown of Sunoco LLC Interest [Member] | Sunoco, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	68.42%
Dropdown of Sunoco LLC Interest [Member] | Legacy Sunoco, Inc. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%

Contribution Transaction Narrat

Contribution Transaction Narrative (Details) - USD ($) shares in Millions, $ in Millions	1 Months Ended
	Mar. 31, 2016	Jun. 30, 2016	Dec. 31, 2015
Goodwill		$ 4,139	$ 5,428
Intangible assets, net		4,032	$ 4,421
Sunoco, LLC [Member] | Dropdown of Sunoco LLC Interest [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	68.42%
Legacy Sunoco, Inc. [Member] | Dropdown of Sunoco LLC Interest [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
Sunoco LP | Dropdown of Sunoco LLC Interest [Member]
Business Combination, Consideration Transferred	$ 2,230
Payments to Acquire Businesses, Gross	$ 2,200
Sale of Stock, Number of Shares Issued in Transaction	5.7
Sunoco, Inc. [Member] | Dropdown of Sunoco LLC Interest [Member]
Goodwill		1,290
Intangible assets, net		$ 294

Contribution Transaction Impa33

Contribution Transaction Impact of Contribution Transaction (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues	$ 5,289	$ 11,540	$ 9,770	$ 21,866
Cost of Goods Sold	3,630	9,354	6,598	17,850
Operating Costs and Expenses	374	635	722	1,245
Selling, General and Administrative Expense	$ 74	162	$ 155	295
Sunoco, LLC and legacy Sunoco, Inc. retail business [Member]
Revenues		5,537		10,342
Cost of Goods Sold		5,003		9,370
Operating Costs and Expenses		281		552
Selling, General and Administrative Expense		$ 58		$ 93

Cash And Cash Equivalents Net C

Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash and Cash Equivalents [Abstract]
Accounts receivable	$ (471)	$ 82
Accounts receivable from related companies	(129)	(53)
Inventories	(157)	(252)
Other current assets	(53)	(110)
Other non-current assets, net	8	99
Accounts payable	509	(333)
Accounts payable to related companies	21	(262)
Accrued and other current liabilities	(22)	(169)
Other non-current liabilities	20	30
Derivative assets and liabilities, net	178	30
Net change in operating assets and liabilities, net of effects of acquisition	$ (96)	$ (938)

Cash And Cash Equivalents Non-C

Cash And Cash Equivalents Non-Cash Investing and Financing Activities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 861	$ 693
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP	194	0
Net gains from subsidiary common unit issuances	14	102
NON-CASH FINANCING ACTIVITIES:
Issuance of Class H Units in connection with the Bakken Pipeline Transaction	0	1,946
Regency Merger [Member]
Partners' Capital Account, Acquisitions	0	9,250
Bakken Pipeline Transaction [Member]
NON-CASH FINANCING ACTIVITIES:
Redemption of common units in connection with the Bakken Pipeline Transaction	$ 0	$ 999

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Inventory, Gross [Abstract]
Natural gas and NGLs	$ 552	$ 415
Crude oil	564	424
Refined products	106	104
Other	203	270
Total inventories	$ 1,425	$ 1,213

Fair Value Measurements Narrati

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Fair Value Measurements [Abstract]
Transfers between levels in fair value hierarchy	$ 0
Aggregate fair value of long-term debt	29,250	$ 25,710
Long-term Debt	$ 28,957	$ 28,679

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Heigharchy (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Derivative Liability, Fair Value, Gross Liability	$ (589)	$ (526)
Fair Value, Measurements, Recurring [Member]
Interest rate derivatives, Assets	29
Price Risk Derivative Assets, at Fair Value	184	448
Assets, Fair Value Disclosure, Recurring	213	448
Interest rate derivatives, Liabilities	(358)	(171)
Embedded Derivative, Fair Value of Embedded Derivative Liability	(9)	(5)
Price Risk Derivative Liabilities, at Fair Value	(222)	(350)
Liabilities, Fair Value Disclosure, Recurring	(589)	(526)
Fair Value, Measurements, Recurring [Member] | Level 1
Interest rate derivatives, Assets	0
Price Risk Derivative Assets, at Fair Value	144	414
Assets, Fair Value Disclosure, Recurring	144	414
Interest rate derivatives, Liabilities	0	0
Embedded Derivative, Fair Value of Embedded Derivative Liability	0	0
Price Risk Derivative Liabilities, at Fair Value	(187)	(318)
Liabilities, Fair Value Disclosure, Recurring	(187)	(318)
Fair Value, Measurements, Recurring [Member] | Level 2
Interest rate derivatives, Assets	29
Price Risk Derivative Assets, at Fair Value	40	34
Assets, Fair Value Disclosure, Recurring	69	34
Interest rate derivatives, Liabilities	(358)	(171)
Embedded Derivative, Fair Value of Embedded Derivative Liability	0	0
Price Risk Derivative Liabilities, at Fair Value	(35)	(32)
Liabilities, Fair Value Disclosure, Recurring	(393)	(203)
Fair Value, Measurements, Recurring [Member] | Level 3
Interest rate derivatives, Assets	0
Price Risk Derivative Assets, at Fair Value	0	0
Assets, Fair Value Disclosure, Recurring	0	0
Interest rate derivatives, Liabilities	0	0
Embedded Derivative, Fair Value of Embedded Derivative Liability		(5)
Derivative Liability, Fair Value, Gross Liability	(9)
Price Risk Derivative Liabilities, at Fair Value	0	0
Liabilities, Fair Value Disclosure, Recurring	(9)	(5)
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	18	16
Price Risk Derivative Liabilities, at Fair Value	(17)	(16)
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	18	16
Price Risk Derivative Liabilities, at Fair Value	(17)	(16)
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	6	10
Price Risk Derivative Liabilities, at Fair Value	(6)	(12)
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	0	2
Price Risk Derivative Liabilities, at Fair Value	(1)	(2)
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	6	8
Price Risk Derivative Liabilities, at Fair Value	(5)	(10)
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	41	274
Price Risk Derivative Liabilities, at Fair Value	(64)	(203)
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	41	274
Price Risk Derivative Liabilities, at Fair Value	(64)	(203)
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	4	4
Price Risk Derivative Liabilities, at Fair Value	(2)
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	4	4
Price Risk Derivative Liabilities, at Fair Value	(2)
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	30	22
Price Risk Derivative Liabilities, at Fair Value	(28)	(22)
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	30	22
Price Risk Derivative Liabilities, at Fair Value	(28)	(22)
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	3	1
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	3	1
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		3
Price Risk Derivative Liabilities, at Fair Value	(1)	(2)
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value		3
Price Risk Derivative Liabilities, at Fair Value	(1)	(2)
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] | Options - Puts [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(1)
Commodity Derivatives - Power [Member] | Options - Puts [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(1)
Commodity Derivatives - Power [Member] | Options - Puts [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Power [Member] | Options - Puts [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	76	99
Price Risk Derivative Liabilities, at Fair Value	(88)	(89)
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	76	99
Price Risk Derivative Liabilities, at Fair Value	(88)	(89)
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	9
Price Risk Derivative Liabilities, at Fair Value	(9)
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	1	9
Price Risk Derivative Liabilities, at Fair Value	(9)
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	5	9
Price Risk Derivative Liabilities, at Fair Value	(7)	(5)
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	5	9
Price Risk Derivative Liabilities, at Fair Value	(7)	(5)
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	$ 0	$ 0

Fair Value Measurements Level 3

Fair Value Measurements Level 3 Rollforward (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (140)	$ 83	$ (214)	$ (2)
Fair Value, Measurements, Recurring [Member]
Liabilities, Fair Value Disclosure, Recurring	(589)		(589)		$ (526)
Fair Value, Measurements, Recurring [Member] | Level 3
Liabilities, Fair Value Disclosure, Recurring	(9)		(9)		$ (5)
Other Income (Expenses) [Member] | Embedded Derivatives in Preferred Units [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (4)	$ 2	$ (4)	$ 4

Net Income Per Limited Partne40

Net Income Per Limited Partner Unit Reconciliation of Basic and Diluted EPU (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share [Abstract]
Net income	$ 472	$ 839	$ 848	$ 1,107
Less: Income attributable to noncontrolling interest	102	212	167	206
Less: Net loss attributable to predecessor	0	(27)	0	(34)
Net income, net of noncontrolling interest and predecessor income	370	654	681	935
General Partner’s interest in net income	223	260	520	502
Class H Unitholder’s interest in net income	85	64	164	118
Class I Unitholder’s interest in net income	2	32	4	65
Common Unitholders’ interest in net income (loss)	60	298	(7)	250
Additional earnings allocated to General Partner	(3)	(2)	(6)	(4)
Distributions on employee unit awards, net of allocation to General Partner	(5)	(3)	(10)	(7)
Net income (loss) available to Common Unitholders	52	293	(23)	239
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	(4)	0	(3)	0
Net Income (Loss) Available to Common Stockholders, Diluted	$ 48	$ 293	$ (26)	$ 239
Weighted average Common Units – basic (1)	501.6	434.8	495.9	379.6
Basic net income (loss) per Common Unit	$ 0.10	$ 0.67	$ (0.05)	$ 0.63
Dilutive effect of unvested employee unit awards	0.7	1.5	0	1.5
Incremental Common Shares Attributable to Dilutive Effect of Conversion of Preferred Stock	0.4	0	0.4	0
Weighted average Common Units – diluted (1)	502.7	436.3	496.3	381.1
Diluted net income (loss) per Common Unit	$ 0.10	$ 0.67	$ (0.05)	$ 0.63

Debt Obligations Narrative (Det

Debt Obligations Narrative (Details) - USD ($) $ in Millions	Aug. 01, 2016	Jun. 30, 2016
ETP [Member] | ETP Revolving Credit Facility, due November 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity		$ 3,750
Long-term Line of Credit		1,130
Sunoco Logistics [Member] | Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member]
Line of Credit Facility, Current Borrowing Capacity		2,500
Long-term Line of Credit		1,260
Line of Credit Facility, Maximum Borrowing Capacity		3,250
Assumed from Regency [Member]
Senior Notes		3,800
6.125% Senior Notes, due May 15, 2016 [Member] | Sunoco Logistics [Member]
Senior Notes		$ 175
Debt Instrument, Interest Rate, Stated Percentage		6.125%
3.90% Senior Notes Due July 15, 2026 [Member] | Sunoco Logistics [Member]
Senior Notes		$ 550
Debt Instrument, Interest Rate, Stated Percentage		3.90%
Subsequent Event [Member] | Bakken Pipeline [Member]
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,500

Equity Narrative (Details)

Equity Narrative (Details) - USD ($) shares in Millions, $ in Millions	1 Months Ended	3 Months Ended	6 Months Ended			12 Months Ended
	Aug. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jul. 31, 2016
Proceeds from Sale of Equity Method Investments				$ 2,200	$ 0
Relinquishment of Incentive Distributions		$ 75
Common units issued in connection with the distribution reinvestment plan				3.1
Net gains from subsidiary common unit issuances				$ 14	102
Proceeds from Issuance of Common Limited Partners Units				408	$ 724
ETP [Member]
Stock Issued During Period, Value, Dividend Reinvestment Plan				$ 84
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan		8.4		8.4
Equity Distribution Agreement [Member] | Sunoco Logistics [Member]
Fees and Commissions				$ 7
Proceeds from Issuance of Common Limited Partners Units				667
Equity Distribution Agreement [Member] | ETP [Member]
Proceeds from Issuance of Common Stock				324
Fees and Commissions				3
Equity Distribution Agreements, Value of Units Available to be Issued		$ 0		$ 0
Bakken Pipeline Transaction [Member] | ETP and Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				36.75%
Subsequent Event [Member]
Relinquishment of Incentive Distributions			$ 249			$ 95	$ 105	$ 593
Subsequent Event [Member] | Equity Distribution Agreement [Member] | ETP [Member]
Equity Distribution Agreements, Value of Units Available to be Issued									$ 1,500
Subsequent Event [Member] | Bakken Pipeline Transaction [Member]
Business Combination, Consideration Transferred	$ 2,000
Subsequent Event [Member] | Bakken Pipeline Transaction [Member] | Sunoco Logistics [Member]
Proceeds from Sale of Equity Method Investments	$ 800
Subsequent Event [Member] | Bakken Pipeline Transaction [Member] | ETP and Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	38.25%
Subsequent Event [Member] | Bakken Pipeline Transaction [Member] | ETP [Member]
Proceeds from Sale of Equity Method Investments	$ 1,200

Equity Common Unit Activity (De

Equity Common Unit Activity (Details) shares in Millions	6 Months Ended
	Jun. 30, 2016shares
Number of common units at December 31, 2015	505.6
Common units issued in connection with equity distribution agreements	11.2
Common units issued in connection with the distribution reinvestment plan	3.1
Number of common units at June 30, 2016	519.9

Equity Quarterly Distributions

Equity Quarterly Distributions Of Available Cash (Details) - $ / shares	3 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
ETP [Member]
Distribution Made to Member or Limited Partner [Line Items]
Record Date	Aug. 8, 2016	May 6, 2016	Feb. 8, 2016
Payment Date	Aug. 15, 2016	May 16, 2016	Feb. 16, 2016
Rate	$ 1.0550	$ 1.0550	$ 1.0550
Sunoco Logistics [Member]
Distribution Made to Member or Limited Partner [Line Items]
Record Date	Aug. 8, 2016	May 9, 2016	Feb. 8, 2016
Payment Date	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016
Rate	$ 0.5000	$ 0.4890	$ 0.4790

Equity Net IDR Schedule (Detail

Equity Net IDR Schedule (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Relinquishment of Incentive Distributions	$ 75
Subsequent Event [Member]
Relinquishment of Incentive Distributions		$ 249	$ 95	$ 105	$ 593

Equity AOCI (Details)

Equity AOCI (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 5	$ 0
Foreign currency translation adjustment	(5)	(4)
Actuarial gain related to pensions and other postretirement benefits	5	8
Investments in unconsolidated affiliates, net	(11)	0
Total AOCI, net of tax	$ (6)	$ 4

Income Taxes Narrative (Details

Income Taxes Narrative (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Mar. 31, 2016	Jun. 30, 2015
Investments, Owned, Federal Income Tax Note [Line Items]
Income Tax Benefit		$ (11)
Dropdown of Sunoco LLC Interest [Member] | Sunoco, LLC [Member]
Investments, Owned, Federal Income Tax Note [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	68.42%
Dropdown of Sunoco LLC Interest [Member] | Legacy Sunoco, Inc. [Member]
Investments, Owned, Federal Income Tax Note [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%

Regulatory Matters, Commitmen48

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2012USD ($)	Jun. 30, 2016USD ($)sites	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)sites	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Maximum lease expiration year				Dec. 31, 2058
Operating Leases, Rent Expense, Contingent Rentals			$ 6,000,000		$ 10,000,000
Loss contingency accrual, at carrying value		$ 56,000,000		$ 56,000,000		$ 40,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed		0		0
Environmental Costs Recognized, Recovery Credited to Expense				19,000,000
Accrual for Environmental Loss Contingencies		$ 324,000,000		$ 324,000,000		$ 367,000,000
Sites where remediation operations are responsibility of third parties | sites		19		19
Proposed Environmental Penalty		$ 200,000		$ 200,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount		595,000,000		595,000,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount		319,000,000		319,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount		1,000,000		1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount		536,000,000		536,000,000
New Mexico Environmental Department [Member]
Accrual for Environmental Loss Contingencies		250,000		250,000
Texas Commission on Environmental Quality [Member]
Accrual for Environmental Loss Contingencies		300,000		300,000
TCEQ [Member]
Proposed Environmental Penalty		21,000		21,000
Supplemental Environmental Project [Member]
Proposed Environmental Penalty		21,000		21,000
AmeriGas [Member]
Contingent Residual Support Agreement, Amount	$ 1,550,000,000	1,000,000,000
Sunoco LP | 6.375% Senior Notes due April 2023 [Member]
Senior Notes		$ 800,000,000		$ 800,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.375%		6.375%
Sunoco LP | 6.25% Senior Notes due 2021 [Member]
Senior Notes		$ 800,000,000		$ 800,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.25%		6.25%
Sunoco LP | Term loan due 2019 [Member]
Senior Notes		$ 2,035,000,000		$ 2,035,000,000
Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number		5		5
Payments for Environmental Liabilities		$ 8,000,000	$ 11,000,000	$ 14,000,000	$ 18,000,000
Sunoco, Inc. [Member] | Multidistrict Legislation [Member]
Loss Contingency, Pending Claims, Number		4		4
Southern Union [Member]
Loss Contingency, Estimated Recovery from Third Party				150,000
Percentage Of Recovery				50.00%
Sunoco [Member]
Sites where remediation operations are responsibility of third parties		49		49

Regulatory Matters, Commitmen49

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Operating Leases, Rental Expense (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Rental expense(1)	[1]	$ 21	$ 54	$ 39	$ 106
Less: Sublease rental income		0	(4)	0	(12)
Rental expense, net		$ 21	$ 50	$ 39	$ 94
[1]	(1) Includes contingent rentals totaling $6 million and $10 million for the three and six months ended June 30, 2015

Regulatory Matters, Commitmen50

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Environmental Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Environmental Exit Cost [Line Items]
Current	$ 35	$ 41
Non-current	289	326
Total environmental liabilities	$ 324	$ 367

Derivative Assets And Liabili51

Derivative Assets And Liabilities Narrative (Details) - USD ($) $ in Millions		Jun. 30, 2016	Dec. 31, 2015
July 2016 [Member]
Derivative, Notional Amount	[1],[2]	$ 0	$ 200
[1]	ETP previously had outstanding forward starting interest rate swaps, which were scheduled to expire in July 2016, with a total notional value of $200 million. In June 2016, ETP extended the expiration of those swaps to July 2017.
[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.

Derivative Assets And Liabili52

Derivative Assets And Liabilities Outstanding Commodity Derivatives (Details)		6 Months Ended	12 Months Ended
		Jun. 30, 2016MMbtubarrelsMegawattbblbushels	Dec. 31, 2015MMbtubarrelsMegawattbblbushels
Corn [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2,016
Corn [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume | bushels		0	1,185,000
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member]
Term Of Commodity Derivatives			2,016
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member]
Notional Volume | MMbtu		42,167,500	37,555,000
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | MMbtu			602,500
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume | MMbtu		5,825,000
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member]
Term Of Commodity Derivatives			2,016
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member]
Notional Volume | MMbtu		42,167,500	37,555,000
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | MMbtu	[1]		31,240,000
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume | MMbtu	[1]	7,920,000
Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member]
Term Of Commodity Derivatives			2,016
Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Long [Member]
Notional Volume | MMbtu		42,167,500	37,555,000
Natural Gas [Member] | Minimum [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016	2,016
Natural Gas [Member] | Minimum [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member]
Term Of Commodity Derivatives		2,016
Natural Gas [Member] | Minimum [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016	2,016
Natural Gas [Member] | Minimum [Member] | Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016	2,016
Natural Gas [Member] | Minimum [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016	2,016
Natural Gas [Member] | Minimum [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member]
Term Of Commodity Derivatives		2,016
Natural Gas [Member] | Minimum [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016	2,016
Natural Gas [Member] | Minimum [Member] | Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Long [Member]
Term Of Commodity Derivatives		2,016
Natural Gas [Member] | Minimum [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016	2,016
Natural Gas [Member] | Maximum [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,018	2,018
Natural Gas [Member] | Maximum [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member]
Term Of Commodity Derivatives		2,017
Natural Gas [Member] | Maximum [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Natural Gas [Member] | Maximum [Member] | Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Natural Gas [Member] | Maximum [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Natural Gas [Member] | Maximum [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member]
Term Of Commodity Derivatives		2,017
Natural Gas [Member] | Maximum [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Natural Gas [Member] | Maximum [Member] | Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Long [Member]
Term Of Commodity Derivatives		2,017
Natural Gas [Member] | Maximum [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Natural Gas Liquids and Crude [Member] | Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016
Natural Gas Liquids and Crude [Member] | Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | bbl		10,443,400	8,146,800
Natural Gas Liquids and Crude [Member] | Minimum [Member] | Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2,016
Natural Gas Liquids and Crude [Member] | Maximum [Member] | Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2,018
Power [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		3,835,000	14,380,000
Power [Member] | Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		3,838,458	21,922,484
Power [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		522,500	6,522,500
Power [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016	2,016
Power [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		424,000
Power [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume			260,534
Power [Member] | Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016	2,016
Power [Member] | Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		696,000	1,300,647
Power [Member] | Forwards Swaps [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		272,164	357,092
Power [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		34,465,000	71,340,000
Power [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2,016
Power [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		320,257	109,791
Power [Member] | Minimum [Member] | Forwards Swaps [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016	2,016
Power [Member] | Minimum [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016
Power [Member] | Maximum [Member] | Forwards Swaps [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Power [Member] | Maximum [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017
Crude Oil [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		222,000	591,000
Crude Oil [Member] | Minimum [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016	2,016
Crude Oil [Member] | Maximum [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Refined Products [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | barrels		1,557,000	993,000
Refined Products [Member] | Minimum [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,016	2,016
Refined Products [Member] | Maximum [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
[1]	(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 Liabili53

Derivative Assets And Liabilities Outstanding Interest Rate Derivatives (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
July 2016 [Member]
Notional Amount	[1],[2]	$ 0	$ 200
Type	[1],[2],[3]	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
July 2017 [Member]
Notional Amount	[1],[4]	$ 500	300
Type	[1],[3],[4]	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate
July 2018 [Member]
Notional Amount	[4]	$ 200	200
Type	[3],[4]	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate
July 2019 [Member]
Notional Amount	[4]	$ 200	200
Type	[3],[4]	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate
December 2018 [Member]
Notional Amount		$ 1,200	1,200
Type	[3]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%
March 2019 [Member]
Notional Amount		$ 300	$ 300
Type	[3]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
[1]	ETP previously had outstanding forward starting interest rate swaps, which were scheduled to expire in July 2016, with a total notional value of $200 million. In June 2016, ETP extended the expiration of those swaps to July 2017.
[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]	Floating rates are based on 3-month LIBOR.
[4]	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 Liabili54

Derivative Assets And Liabilities Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Total derivatives assets	$ 213	$ 448
Total derivatives liabilities	(589)	(526)
Designated as Hedging Instrument [Member]
Total derivatives assets	0	38
Total derivatives liabilities	(4)	(3)
Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits)
Total derivatives assets	0	38
Total derivatives liabilities	(4)	(3)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	213	410
Total derivatives liabilities	(585)	(523)
Not Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits)
Total derivatives assets	138	353
Total derivatives liabilities	(173)	(306)
Not Designated as Hedging Instrument [Member] | Commodity derivatives
Total derivatives assets	46	57
Total derivatives liabilities	(45)	(41)
Not Designated as Hedging Instrument [Member] | Interest rate derivatives
Total derivatives assets	29	0
Total derivatives liabilities	(358)	(171)
Embedded Derivatives in Preferred Units [Member] | Not Designated as Hedging Instrument [Member]
Total derivatives assets	0	0
Total derivatives liabilities	$ (9)	$ (5)

Derivative Assets And Liabili55

Derivative Assets And Liabilities Fair Value of Derivatives, Netting Basis (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 213	$ 448
Derivative Liability, Fair Value, Gross Liability	(589)	(526)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(22)	(17)
Derivative Liability, Fair Value, Amount Offset Against Collateral	22	17
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(138)	(309)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	138	309
Derivative Asset, Fair Value, Net	53	122
Derivative Liability, Fair Value, Net	(429)	(200)
Without offsetting agreements [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	29	0
Derivative Liability, Fair Value, Gross Liability	(367)	(176)
OTC Contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	46	57
Derivative Liability, Fair Value, Gross Liability	(45)	(41)
Broker cleared derivative contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	138	391
Derivative Liability, Fair Value, Gross Liability	$ (177)	$ (309)

Derivative Assets And Liabili56

Derivative Assets And Liabilities Partnership's Derivative Assets And Liabilities, Recognized OCI On Derivatives (Effective Portion) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 0	$ 0	$ 0	$ 1
Derivatives In Cash Flow Hedging Relationships - Commodity Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 0	$ 0	$ 0	$ 1

Derivative Assets And Liabili57

Derivative Assets And Liabilities Partnership's Derivative Assets And Liabilities, Amount Of Gain/(Loss) Reclassified From AOCI Into Income (Effective Portion) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	$ 21	$ 11	$ 17	$ 8
Amount of Gain/(Loss) Recognized in Income on Derivatives	(140)	83	(214)	(2)
Gains (losses) on interest rate derivatives	(81)	127	(151)	50
Commodity Derivatives - Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(7)	(6)	(16)	(8)
Commodity derivatives
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	21	11	17	8
Amount of Gain/(Loss) Recognized in Income on Derivatives	(48)	(40)	(43)	(48)
Other Income (Expenses) [Member] | Embedded Derivatives in Preferred Units [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (4)	$ 2	$ (4)	$ 4

Related Party Transactions Affi

Related Party Transactions Affiliated Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Related Party Transactions [Abstract]
Affiliated revenues	$ 133	$ 130	$ 207	$ 206

Related Party Transactions Rela

Related Party Transactions Related Party A/R and A/P (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Total accounts receivable from related companies:	$ 354	$ 268
Total accounts payable to related companies:	21	25
Long-term notes payable – related companies	182	233
ETE
Total accounts receivable from related companies:	58	110
Sunoco LP
Total accounts receivable from related companies:	185	3
Total accounts payable to related companies:	10	5
Long-term notes payable – related companies	75	233
PES
Total accounts receivable from related companies:	9	10
FGT
Total accounts receivable from related companies:	9	13
Total accounts payable to related companies:	1	1
Lake Charles LNG
Total accounts receivable from related companies:	30	36
Total accounts payable to related companies:	2	3
Trans-Pecos Pipeline, LLC
Total accounts receivable from related companies:	0	29
Comanche Trail Pipeline, LLC
Total accounts receivable from related companies:	9	22
Other
Total accounts receivable from related companies:	54	45
Total accounts payable to related companies:	8	16
Phillips 66 Partners LP [Member]
Long-term notes payable – related companies	$ 107	$ 0

Reportable Segments Segment Rev

Reportable Segments Segment Revenues (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Revenues	$ 5,289	$ 11,540	$ 9,770	$ 21,866
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Revenues	541	569	1,099	1,155
Intrastate transportation and storage | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	428	486	874	1,027
Intrastate transportation and storage | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	113	83	225	128
Interstate transportation and storage
Segment Reporting Information [Line Items]
Revenues	234	243	493	519
Interstate transportation and storage | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	229	239	483	510
Interstate transportation and storage | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	5	4	10	9
Midstream
Segment Reporting Information [Line Items]
Revenues	1,330	1,240	2,422	2,391
Midstream | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	690	767	1,217	1,516
Midstream | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	640	473	1,205	875
Liquids transportation and services
Segment Reporting Information [Line Items]
Revenues	1,110	828	2,029	1,663
Liquids transportation and services | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	1,099	783	1,928	1,595
Liquids transportation and services | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	11	45	101	68
Investment in Sunoco Logistics
Segment Reporting Information [Line Items]
Revenues	2,268	3,202	4,045	5,774
Investment in Sunoco Logistics | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	2,250	3,120	3,979	5,646
Investment in Sunoco Logistics | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	18	82	66	128
Retail marketing
Segment Reporting Information [Line Items]
Revenues	0	5,537	0	10,342
Retail marketing | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	0	5,557	0	10,339
Retail marketing | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	0	(20)	0	3
All other
Segment Reporting Information [Line Items]
Revenues	711	722	1,565	1,464
All other | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	593	588	1,289	1,233
All other | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	118	134	276	231
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (905)	$ (801)	$ (1,883)	$ (1,442)

Reportable Segments Segment Adj

Reportable Segments Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 1,370	$ 1,488	$ 2,782	$ 2,854
Depreciation, depletion and amortization	(496)	(501)	(966)	(980)
Interest expense, net	(317)	(336)	(636)	(646)
Gains (losses) on interest rate derivatives	(81)	127	(151)	50
Non-cash unit-based compensation expense	(19)	(23)	(38)	(43)
Unrealized losses on commodity risk management activities	(18)	(42)	(81)	(119)
Inventory valuation adjustments	132	184	106	150
Losses on extinguishments of debt	0	(33)	0	(33)
Adjusted EBITDA related to unconsolidated affiliates	(252)	(215)	(471)	(361)
Equity in earnings of unconsolidated affiliates	119	117	195	174
Other, net	25	14	41	19
INCOME BEFORE INCOME TAX BENEFIT	463	780	781	1,065
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	149	117	328	294
Interstate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	278	285	570	586
Midstream
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	298	352	561	662
Liquids transportation and services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	220	154	447	323
Investment in Sunoco Logistics
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	245	326	594	547
Retail marketing
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	68	140	125	269
All other
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 112	$ 114	$ 157	$ 173

Reportable Segments Segment Ass

Reportable Segments Segment Assets (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Assets	$ 66,041	$ 65,173
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Assets	5,134	4,882
Interstate transportation and storage
Segment Reporting Information [Line Items]
Assets	11,551	11,345
Midstream
Segment Reporting Information [Line Items]
Assets	17,604	17,111
Liquids transportation and services
Segment Reporting Information [Line Items]
Assets	8,977	7,235
Investment in Sunoco Logistics
Segment Reporting Information [Line Items]
Assets	16,780	15,423
Retail marketing
Segment Reporting Information [Line Items]
Assets	1,387	3,218
All other
Segment Reporting Information [Line Items]
Assets	$ 4,608	$ 5,959