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Document And Entity Information - shares	6 Months Ended
Document And Entity Information - shares	Jun. 30, 2017	Jul. 28, 2017
Entity Information [Abstract]
Entity Registrant Name	Energy Transfer Partners, L.P.
Entity Central Index Key	0001161154
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		1,099,625,923
Document Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2

Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 272	$ 360
Accounts receivable, net	2,914	3,002
Accounts receivable from related companies	364	209
Inventories	1,520	1,712
Income Taxes Receivable, Current	148	128
Derivative assets	8	20
Other current assets	160	298
Total current assets	5,386	5,729
Property, plant and equipment	62,790	58,220
Accumulated depreciation and depletion	(8,254)	(7,303)
Property, plant and equipment, net	54,536	50,917
Advances to and investments in unconsolidated affiliates	4,228	4,280
Other non-current assets, net	707	672
Intangible assets, net	5,443	4,696
Goodwill	3,919	3,897
Total assets	74,219	70,191
Current liabilities:
Accounts payable	2,900	2,900
Accounts payable to related companies	200	43
Derivative liabilities	7	166
Accrued and other current liabilities	2,517	1,905
Current maturities of long-term debt	1,365	1,189
Total current liabilities	6,989	6,203
Long-term debt, less current maturities	32,029	31,741
Long-term notes payable – related company	0	250
Non-current derivative liabilities	201	76
Deferred income taxes	4,498	4,394
Other non-current liabilities	1,066	952
Commitments and contingencies
Preferred Units	0	33
Redeemable noncontrolling interests	21	15
Equity:
General Partner	220	206
Limited Partners:
Common Unitholders	25,389	14,946
Class H Unitholder	0	3,480
Class I Unitholder	0	2
Accumulated other comprehensive income	7	8
Total partners’ capital	25,616	18,642
Noncontrolling interest	3,799	7,885
Total equity	29,415	26,527
Total liabilities and equity	$ 74,219	$ 70,191

Consolidated Statements Of Operations - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
REVENUES:
Natural gas sales	$ 1,022	$ 695	$ 2,034	$ 1,533
NGL sales	1,485	1,150	3,032	2,090
Crude sales	2,131	1,713	4,478	2,923
Gathering, transportation and other fees	1,067	1,045	2,091	2,005
Refined product sales	304	234	775	479
Other	567	452	1,061	740
Total revenues	6,576	5,289	13,471	9,770
COSTS AND EXPENSES:
Cost of products sold	4,742	3,630	9,934	6,598
Operating expenses	425	374	804	722
Depreciation, depletion and amortization	557	496	1,117	966
Selling, general and administrative	120	74	230	155
Total costs and expenses	5,844	4,574	12,085	8,441
OPERATING INCOME	732	715	1,386	1,329
OTHER INCOME (EXPENSE):
Interest expense, net	(346)	(317)	(685)	(636)
Equity in earnings (losses) of unconsolidated affiliates	(61)	119	12	195
Losses on interest rate derivatives	(25)	(81)	(20)	(151)
Other, net	71	27	97	44
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	371	463	790	781
Income tax expense (benefit)	79	(9)	134	(67)
NET INCOME	292	472	656	848
Less: Net income attributable to noncontrolling interest	93	102	133	167
Less: Comprehensive income attributable to noncontrolling interest	93	102	133	167
NET INCOME ATTRIBUTABLE TO PARTNERS	199	370	523	681
General Partner’s interest in net income	251	223	457	520
Class H Unitholder’s interest in net income	0	85	98	164
Class I Unitholder’s interest in net income	0	2	0	4
Common Unitholders’ interest in net income (loss)	$ (52)	$ 60	$ (32)	$ (7)
NET INCOME (LOSS) PER COMMON UNIT:
Basic	$ (0.04)	$ 0.07	$ (0.04)	$ (0.03)
Diluted	$ (0.04)	$ 0.06	$ (0.04)	$ (0.03)

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 292	$ 472	$ 656	$ 848
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	1	3	3	5
Actuarial gain (loss) relating to pension and other postretirement benefit plans	(1)	6	(3)	(3)
Foreign currency translation adjustments	0	0	0	(1)
Change in other comprehensive income from unconsolidated affiliates	(1)	(5)	(1)	(11)
Total other comprehensive income (loss)	(1)	4	(1)	(10)
Comprehensive income	291	476	655	838
Less: Comprehensive income attributable to noncontrolling interest	93	102	133	167
Comprehensive income attributable to partners	$ 198	$ 374	$ 522	$ 671

Consolidated Statement Of Equity - 6 months ended Jun. 30, 2017 - USD ($) $ in Millions	Total	General Partner	Common Units	Class H Units	Class I Units	Accumulated Other Comprehensive Income	Noncontrolling Interest
Balance, December 31, 2016 at Dec. 31, 2016	$ 26,527	$ 206	$ 14,946	$ 3,480	$ 2	$ 8	$ 7,885
Distributions to partners	1,702	443	1,162	95	2	0	0
Distributions to noncontrolling interest	(186)	0	0	0	0	0	(186)
Units issued for cash	990	0	990	0	0	0	0
Partners' Capital Account, Acquisitions	0	0	9,459	(3,483)	0	0	(5,976)
Capital contributions from noncontrolling interest	1,444	0	0	0	0	0	1,444
Sale of Bakken Pipeline interest	2,000	0	1,260	0	0	0	740
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	(280)	0	(48)	0	0	0	(232)
Other Comprehensive Income (Loss), Net of Tax	(1)	0	0	0	0	(1)	0
Other, net	(33)	0	(24)	0	0	0	(9)
Net income	656	457	(32)	98	0	0	133
Balance, June 30, 2017 at Jun. 30, 2017	$ 29,415	$ 220	$ 25,389	$ 0	$ 0	$ 7	$ 3,799

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
OPERATING ACTIVITIES
Net income	$ 656	$ 848
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,117	966
Deferred income taxes	121	(79)
Amortization included in interest expense	(2)	(12)
Inventory valuation adjustments	56	(106)
Unit-based compensation expense	38	38
Distributions on unvested awards	(15)	(13)
Equity in earnings of unconsolidated affiliates	(12)	(195)
Distributions from unconsolidated affiliates	197	199
Other non-cash	(96)	(124)
Net change in operating assets and liabilities, net of effects of acquisition	(410)	(96)
Net cash provided by operating activities	1,650	1,426
INVESTING ACTIVITIES
Cash received from Bakken Pipeline Transaction	2,000	0
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction	0	2,200
Cash paid for acquisition of a noncontrolling interest	280	0
Cash paid for all other acquisitions	261	0
Capital expenditures, excluding allowance for equity funds used during construction	(2,842)	(3,479)
Contributions in aid of construction costs	10	25
Contributions to unconsolidated affiliates	(225)	(31)
Distributions from unconsolidated affiliates in excess of cumulative earnings	94	56
Proceeds from the sale of assets	25	7
Change in restricted cash	0	(2)
Other	(7)	(1)
Net cash used in investing activities	(1,486)	(1,225)
FINANCING ACTIVITIES
Proceeds from borrowings	11,466	7,811
Repayments of long-term debt	(10,953)	(7,514)
Proceeds from (Repayments of) Related Party Debt	(255)	147
Units issued for cash	990	408
Subsidiary units issued for cash	0	667
Capital contributions from noncontrolling interest	456	161
Distributions to partners	(1,702)	(1,813)
Distributions to noncontrolling interest	(186)	(209)
Payments for Repurchase of Preferred Stock and Preference Stock	53	0
Debt issuance costs	20	0
Proceeds from (Payments for) Other Financing Activities	5	0
Net cash used in financing activities	(252)	(342)
Decrease in cash and cash equivalents	(88)	(141)
Cash and cash equivalents, beginning of period	360	527
Cash and cash equivalents, end of period	$ 272	$ 386

Operations And Organization

6 Months Ended

Jun. 30, 2017

Operations And Organization [Abstract]

Operations And Organization

ORGANIZATION AND BASIS OF PRESENTATION

Organization

Energy Transfer Partners, L.P. (“ETP”, formerly named “Sunoco Logistics Partners L.P.”, as discussed below) is a consolidated subsidiary of ETE.

In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P. Under the terms of the transaction, the unitholders received 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. Based on the number of Energy Transfer Partners, L.P. common units outstanding at the closing of the merger, Sunoco Logistics issued approximately 832 million Sunoco Logistics common units to Energy Transfer Partners, L.P. unitholders. In connection with the merger, the Energy Transfer Partners, L.P. Class H units were cancelled. The outstanding Energy Transfer Partners, L.P. Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of Energy Transfer Partners, L.P. units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by Energy Transfer Partners, L.P. at the effective time of the merger were cancelled.

At the time of the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of maintaining clarity, the following references are used herein:


•	References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger;


•	References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and


•	References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.

The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes).

The Sunoco Logistics Merger was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assets and liabilities in the consolidated financial statements, and no gain or loss was recognized. For the periods prior to the Sunoco Logistics Merger, the Sunoco Logistics limited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements.

The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.

The consolidated financial statements of the Partnership presented herein include our operating subsidiaries (collectively, the “Operating Companies”), through which our activities are primarily conducted, as follows:

•

ETC OLP, Regency and PennTex, which are primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP and Regency own and operate, through their wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico, West Virginia, Denver and Ohio.


•	ET Interstate, with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:


•	Transwestern, 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, which directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.


•	ETC Tiger, engaged in interstate transportation of natural gas.


•	CrossCountry, which indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline.


•	ETC MEP, which directly owns a 50% interest in MEP.


•	ET Rover, which owns a 65% interest in Rover pipeline.


•	ETC Compression, LLC, engaged in natural gas compression services and related equipment sales.

•

ETP Holdco, which 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. 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. Subsequent to the Sunoco Logistics Merger, ETLP holds an equity method investment in ETP through ETP Holdco’s ownership of ETP Class E, Class G, and Class K units, which investment is eliminated in the consolidated financial statements.


•	Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.

Subsequent to the Sunoco Logistics Merger, our financial statements reflect the following reportable business segments:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services; and

•all other.

Prior periods have been retrospectively adjusted to reflect the impact of the Sunoco Logistics Merger on our reportable business segments.

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 of Energy Transfer Partners, L.P. for the year ended December 31, 2016, included in Exhibit 99.3 to the Partnership’s Current Report on Form 8-K filed on May 8, 2017. 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.

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. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catchup transition method). The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method.

We are in the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standards. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts may be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We continue to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us.

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-09, Stock Compensation (Topic 718) (“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements and related disclosures.

In October 2016, the FASB issued Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that adoption of this standard will have on the consolidated financial statements and related disclosures.

On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-17, Consolidation (Topic 810): Interests Held Through Related Parties That Are Under Common Control (“ASU 2016-17”), which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (“VIE”) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under the amendments, a single decision maker is required to include indirect interests on a proportionate basis consistent with indirect interests held through other related parties. The adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership expects that the adoption of this standard will change its approach for measuring goodwill impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. The Partnership plans to apply this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

Acquisitions and Contribution Transactions	6 Months Ended
Acquisitions and Contribution Transactions	Jun. 30, 2016
Acquisitions [Abstract]
Business Combination Disclosure [Text Block]	ACQUISITIONS AND CONTRIBUTION TRANSACTIONS Permian Express Partners In February 2017, Sunoco Logistics formed Permian Express Partners LLC (“PEP”), a strategic joint venture with ExxonMobil Corporation (“ExxonMobil”). Sunoco Logistics contributed its Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment. The Partnership’s ownership percentage in PEP was approximately 85% at June 30, 2017. In July 2017, the Partnership contributed an approximate 15% ownership interest in Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”) to PEP, which resulted in an increase in its ownership interest in PEP to approximately 88%. The Partnership maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

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+ Details

Cash And Cash Equivalents

6 Months Ended

Jun. 30, 2017

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 acquisitions) included in cash flows from operating activities is comprised as follows:



	Six Months Ended June 30,
	2017			2016
Accounts receivable	$	88		$	(471	)
Accounts receivable from related companies	(115		)	(129		)
Inventories	137			(157		)
Other current assets	77			(53		)
Other non-current assets, net	(39		)	8
Accounts payable	(286		)	509
Accounts payable to related companies	131			21
Accrued and other current liabilities	(389		)	(22		)
Other non-current liabilities	7			20
Derivative assets and liabilities, net	(21		)	178
Net change in operating assets and liabilities, net of effects of acquisitions	$	(410	)	$	(96	)

Non-cash investing and financing activities are as follows:



	Six Months Ended June 30,
	2017		2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,363	$	861
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
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988	$	—

Inventories

6 Months Ended

Jun. 30, 2017

Inventory, Gross [Abstract]

Inventories

INVENTORIES

Inventories consisted of the following:



	June 30, 2017		December 31, 2016
Natural gas and NGLs	$	546	$	699
Crude oil	681		683
Refined products	76		113
Spare parts and other	217		217
Total inventories	$	1,520	$	1,712

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.

Fair Value Measurements

6 Months Ended

Jun. 30, 2017

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, 2017 was $34.68 billion and $33.39 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations was $33.85 billion and $32.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the six months ended June 30, 2017, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2017 and December 31, 2016 based on inputs used to derive their fair values:



				Fair Value Measurements at June 30, 2017
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	9		$	9		$	—
Swing Swaps IFERC	3			1			2
Fixed Swaps/Futures	38			38			—
Forward Physical Swaps	4			—			4
Power:
Forwards	13			—			13
Futures	1			1			—
Natural Gas Liquids – Forwards/Swaps	77			77			—
Crude – Futures	9			9			—
Total commodity derivatives	154			135			19
Total assets	$	154		$	135		$	19
Liabilities:
Interest rate derivatives	$	(201	)	$	—		$	(201	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(9		)	(9		)	—
Swing Swaps IFERC	(2		)	—			(2		)
Fixed Swaps/Futures	(25		)	(25		)	—
Forward Physical Swaps	(1		)	—			(1		)
Power:
Forwards	(12		)	—			(12		)
Futures	(1		)	(1		)	—
Natural Gas Liquids – Forwards/Swaps	(70		)	(70		)	—
Refined Products – Futures	(3		)	(3		)	—
Crude – Futures	(5		)	(5		)	—
Total commodity derivatives	(128		)	(113		)	(15		)
Total liabilities	$	(329	)	$	(113	)	$	(216	)



				Fair Value Measurements at December 31, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	14		$	14		$	—		$	—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	96			96			—			—
Forward Physical Swaps	1			—			1			—
Power:
Forwards	4			—			4			—
Futures	1			1			—			—
Options – Calls	1			1			—			—
Natural Gas Liquids – Forwards/Swaps	233			233			—			—
Refined Products – Futures	1			1			—			—
Crude – Futures	9			9			—			—
Total commodity derivatives	362			355			7			—
Total assets	$	362		$	355		$	7		$	—
Liabilities:
Interest rate derivatives	$	(193	)	$	—		$	(193	)	$	—
Embedded derivatives in Preferred Units	(1		)	—			—			(1		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(11		)	(11		)	—			—
Swing Swaps IFERC	(3		)	—			(3		)	—
Fixed Swaps/Futures	(149		)	(149		)	—			—
Power:
Forwards	(5		)	—			(5		)	—
Futures	(1		)	(1		)	—			—
Natural Gas Liquids – Forwards/Swaps	(273		)	(273		)	—			—
Refined Products – Futures	(17		)	(17		)	—			—
Crude – Futures	(13		)	(13		)	—			—
Total commodity derivatives	(472		)	(464		)	(8		)	—
Total liabilities	$	(666	)	$	(464	)	$	(201	)	$	(1	)

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Net Income Per Limited Partner Unit

6 Months Ended

Jun. 30, 2017

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.

A reconciliation of net income (loss) and weighted average units used in computing basic and diluted net income (loss) per unit is as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Net income	$	292		$	472		$	656		$	848
Less: Income attributable to noncontrolling interest	93			102			133			167
Net income, net of noncontrolling interest	199			370			523			681
General Partner’s interest in net income	251			223			457			520
Class H Unitholder’s interest in net income	—			85			98			164
Class I Unitholder’s interest in net income	—			2			—			4
Common Unitholders’ interest in net income (loss)	(52		)	60			(32		)	(7		)
Additional (earnings) losses allocated to General Partner	15			(3		)	12			(6		)
Distributions on employee unit awards, net of allocation to General Partner	(6		)	(5		)	(13		)	(10		)
Net income (loss) available to Common Unitholders	$	(43	)	$	52		$	(33	)	$	(23	)
Weighted average Common Units – basic ⁽¹⁾	1,021.7			752.4			922.5			743.9
Basic net income (loss) per Common Unit	$	(0.04	)	$	0.07		$	(0.04	)	$	(0.03	)

Net income (loss) available to Common Unitholders	$	(43	)	$	52		$	(33	)	$	(23	)
Income attributable to Preferred Units	—			(4		)	—			(3		)
Diluted net income (loss) available to Common Unitholders	$	(43	)	$	48		$	(33	)	$	(26	)
Weighted average Common Units – basic ⁽¹⁾	1,021.7			752.4			922.5			743.9
Dilutive effect of unvested employee unit awards	—			1.0			—			—
Dilutive effect of Preferred Units	—			0.5			—			0.5
Weighted average Common Units – diluted ⁽¹⁾	1,021.7			753.9			922.5			744.4
Diluted net income (loss) per Common Unit	$	(0.04	)	$	0.06		$	(0.04	)	$	(0.03	)

⁽¹⁾Excludes Common Units owned by the Partnership’s consolidated subsidiaries.

For certain periods reflected above, distributions paid for the period exceeded net income attributable to partners. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.

Debt Obligations	6 Months Ended
Debt Obligations	Jun. 30, 2017
Debt Disclosure [Abstract]
Debt Obligations	DEBT OBLIGATIONS Credit Facilities and Commercial Paper ETLP Credit Facility The ETLP Credit Facility allows for borrowings of up to $3.75 billion and matures in November 2019. The indebtedness under the ETLP 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. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the $3.75 billion ETLP Credit Facility. As of June 30, 2017, the ETLP Credit Facility had $1.54 billion of outstanding borrowings, all of which was commercial paper. Sunoco Logistics Credit Facilities ETP maintains the Sunoco Logistics $2.50 billion unsecured revolving credit facility (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, 2017, the Sunoco Logistics Credit Facility had $1.67 billion of outstanding borrowings, which included $241 million of commercial paper. In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017. Bakken Credit Facility In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility provides substantially all of the remaining capital necessary to complete the projects. As of June 30, 2017, $2.50 billion was outstanding under this credit facility. PennTex Revolving Credit Facility PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). As of June 30, 2017, the PennTex Revolving Credit Facility had $148 million of outstanding borrowings. In August 2017, the PennTex Revolving Credit Facility was repaid and terminated. Compliance with Our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of June 30, 2017.

Series A Preferred Units (Notes)	6 Months Ended
Series A Preferred Units (Notes)	Jun. 30, 2017
Series A Preferred Units [Abstract]
Preferred Units [Text Block]	PREFERRED UNITS In January 2017, Energy Transfer Partners, L.P. repurchased all of its 1.9 million outstanding Preferred Units for cash in the aggregate amount of $53 million.

Equity

6 Months Ended

Jun. 30, 2017

Partners' Capital Notes [Abstract]

Equity

EQUITY

The changes in outstanding common units during the six months ended June 30, 2017 were as follows:



		Number of Units
Number of common units at December 31, 2016 ⁽¹⁾		794.8
Common units issued in connection with equity distribution agreements		15.6
Common units issued in connection with the distribution reinvestment plan		2.8
Common units issued to ETE in a private placement transaction		23.7
Common unit increase from Sunoco Logistics Merger ⁽²⁾		255.4
Issuance of common units under equity incentive plans		0.3
Number of common units at June 30, 2017		1,092.6


⁽¹⁾	The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.


⁽²⁾	Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion. During the six months ended June 30, 2017, the Partnership received proceeds of $358 million, net of $4 million of commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. During the six months ended June 30, 2017, distributions of $71 million were reinvested under the distribution reinvestment plan. In July 2017, the Partnership initiated a new distribution reinvestment plan.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which the Partnership indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P. for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, the Partnership owns a 38.25% interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline”), and MarEn Bakken Company owns 36.75% and Phillips 66 owns 25.00% in the Bakken Pipeline.

PennTex Tender Offer and Limited Call Right Exercise

In June 2017, Energy Transfer Partners, L.P. purchased all of the outstanding PennTex common units not previously owned by Energy Transfer Partners, L.P. for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.

Quarterly Distributions of Available Cash

Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the Partnership's limited partnership agreement, which was Sunoco Logistics' limited partnership agreement prior to the Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as "available cash" in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership's business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.

If cash distributions exceed $0.0833 per unit in a quarter, the general partner receives increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as "incentive distributions." The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

The following table shows the target distribution levels and distribution “splits” between the general partner and the holders of the Partnership’s common units:



		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	IDRs	Partners ⁽¹⁾
Minimum Quarterly Distribution	$0.0750	—%	100%
First Target Distribution	up to $0.0833	—%	100%
Second Target Distribution	above $0.0833 up to $0.0958	13%	87%
Third Target Distribution	above $0.0958 up to $0.2638	35%	65%
Thereafter	above $0.2638	48%	52%

⁽¹⁾ Includes general partner and limited partner interests, based on the proportionate ownership of each.

For the quarter ended December 31, 2016, Energy Transfer Partners, L.P. and Sunoco Logistics paid distributions on February 14, 2017 of $0.7033 and $0.52, respectively, per common unit.

Following are distributions declared and/or paid by the Partnership subsequent to the Sunoco Logistics Merger:



Quarter Ended	Record Date	Payment Date	Rate
March 31, 2017	May 10, 2017	May 15, 2017	$	0.5350
June 30, 2017	August 7, 2017	August 14, 2017	0.5500

ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods.



	Total Year
2017 (remainder)	$	336
2018	153
2019	128
Each year beyond 2019	33

Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:



	June 30, 2017			December 31, 2016
Available-for-sale securities	$	5		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial gain related to pensions and other postretirement benefits	4			7
Investments in unconsolidated affiliates, net	3			4
Total AOCI, net of tax	$	7		$	8

- Definition

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

+ References

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+ Details

Income Taxes (Notes)	6 Months Ended
Income Taxes (Notes)	Jun. 30, 2017
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES For the three and six months ended June 30, 2017, the Partnership’s income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately $77 million during the periods presented. For the three and six months ended June 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries.

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

6 Months Ended

Jun. 30, 2017

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, ETLP (formerly Energy Transfer Partners, L.P.) 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 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETLP under the contingent residual support agreement. In February 2017, AmeriGas repurchased a portion of its 7.00% senior notes. The remaining outstanding 7.00% senior notes were repurchased in May 2017, and ETLP no longer guarantees any AmeriGas notes.

Guarantee of Sunoco LP Notes

In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC.

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 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Rental expense	$	19	$	21	$	39	$	39

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.

Dakota Access Pipeline

During the summer of 2016, individuals affiliated with or sympathetic to the Standing Rock Sioux Tribe (the “SRST”) began to protest the development of the pipeline project. Protesters trespassed on to the construction site, tampered with equipment, and disrupted construction activity at the site. In response to the protests, Dakota Access filed a lawsuit in federal court in North Dakota to restrain protestors from disrupting construction and also requested a temporary restraining order (“TRO”) against the Chairman of the SRST and the protestors. The U.S. District Court granted and later dissolved a TRO enjoining protest activity. The protestors moved to dismiss the lawsuit and the Court granted their motion in May 2017.

On July 25, 2016, the U.S. Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the SRST filed a lawsuit in the U.S. District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access intervened in the case. The SRST soon added a request for an emergency TRO to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot.

After the September 9 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.

The SRST appealed the denial of the preliminary injunction to the U.S. Court of Appeals for the D.C. Circuit and filed an emergency motion in the U.S. District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statutes governing the use of government property.

In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and TRO to block operation of the pipeline. These motions raised, for the first time, claims based on the religious rights of the tribe. The district court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.

The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four tribes.

On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determination under certain of these statutes. The USACE has advised the Court that it expects to have completed this additional work by the end of 2017. The Court ordered briefing that will conclude at the end of August 2017 to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process and the Court is expected to rule on this issue during September 2017. The USACE and Dakota Access have each filed a brief with the Court to oppose any shutdown of operations of the pipeline during this review process. The Court has stayed consideration of any other claims until it fully resolves the remaining issues relating to its remand order.

While we believe that the pending lawsuits are unlikely to block operation of the pipeline, we cannot assure this outcome. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.

Mont Belvieu Incident

On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal (CMB) and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses.

MTBE Litigation

Sunoco, Inc. and/or Sunoco, Inc. (R&M), along with other refiners, manufacturers and sellers of gasoline, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, typically governmental authorities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As of June 30, 2017, Sunoco, Inc. is a defendant in six cases, including cases initiated by the States of New Jersey, Vermont, Pennsylvania, Rhode Island, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico, Vermont, and Pennsylvania plaintiffs assert natural resource damage claims.

Fact discovery has concluded with respect to an initial set of 9 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 9 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. The remaining portion of the New Jersey case remains in the multidistrict litigation. In early 2017, Sunoco, Inc. and Sunoco, Inc. (R&M) and two other co-defendants reached a settlement in principle with the State of New Jersey, subject to the parties agreeing on the terms and conditions of a Settlement and Release agreement, among other things. It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any said adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

Following the January 26, 2015 announcement of the Regency merger, purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint 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. On March 29, 2016, the Delaware Court of Chancery granted defendants’ motion to dismiss the lawsuit. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court issued an order reversing the judgment of the Court of Chancery that dismissed Counts I and II of Dieckman’s Complaint. On February 21, 2017, Regency and the other defendants filed their respective Motions to Dismiss the Chancery Court matter. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. Briefing on both of these motions is ongoing.

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 filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP intends to file a petition for review with the Texas Supreme Court.

Sunoco Logistics Merger Litigation

Five purported Energy Transfer Partners, L.P. common unitholders (“Plaintiffs”) separately filed seven putative unitholder class action lawsuits challenging the merger and the disclosures made in connection with the merger. The lawsuits are styled (a) Shure v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00044-UNA, in the United States District Court for the District of Delaware (the “Shure Lawsuit”); (b) Verlin v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00045-UNA, in the United States District Court for the District of Delaware (the “Verlin Lawsuit”); (c) Duany v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00058-UNA, in the United States District Court for the District of Delaware (the “Duany Lawsuit”); (d) Epstein v. Energy Transfer Partners, L.P. et. al., Case No, 1:17-cv-00069, in the United States District Court for the District of Delaware (the “Epstein Lawsuit”) and (e) Sgnilek v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00141, in the United States District Court for the District of Delaware (the “Sgnilek Lawsuit” and collectively with the Shure Lawsuit, Verlin Lawsuit, Duany Lawsuit, and Epstein Lawsuit, the “Lawsuits”).

Plaintiffs allege causes of action challenging the merger and the preliminary joint proxy statement/prospectus filed in connection with the merger. Plaintiffs allege that (i) defendants have violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and (ii) the members of the ETP Board have violated Section 20(a) of the Exchange Act. Plaintiffs in the Shure Lawsuit and Verlin Lawsuit also allege that Sunoco Logistics has violated Section 20(a) of the Exchange Act. Plaintiffs also assert, in general, that the terms of the merger (including, among other terms, the merger consideration) are unfair to ETP common unitholders and resulted from an unfair and conflicted process. Based on these allegations, the Sgnilek Lawsuit alleges that (a) the ETP Board, ETP GP, ETP LLC, ETP, and ETE have breached the covenant of good faith and/or fiduciary duties, and (b) Sunoco Logistics and Sunoco Partners LLC have aided and abetted those alleged breaches.

Based on these allegations, Plaintiffs seek to enjoin defendants from proceeding with or consummating the merger unless and until defendants disclose the allegedly omitted information summarized above. The Sgnilek Lawsuit also seeks to enjoin defendants from proceeding with or consummating the merger unless and until the ETP Board adopts and implements processes to obtain the best possible terms for ETP common unitholders. To the extent that the merger is consummated before injunctive relief is granted, Plaintiffs seek to have the merger rescinded. Plaintiffs also seek damages and reimbursement of attorneys’ fees.

On May 31, 2017, a Joint Stipulation and Order was filed (1) setting deadlines for Plaintiffs’ Amended Complaint and Defendants’ Answer; (2) dismissing Sunoco Logistics and Sunoco Partners LLC from the lawsuits; and (3) consolidating the remaining five lawsuits under the Shure Lawsuit.

Defendants believe the Lawsuits are without merit and intend to defend vigorously against the Lawsuits and any other actions challenging the merger.

Litigation filed by BP Products

On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the Federal Energy Regulatory Commission (“FERC”), BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million.

SPLP filed an answer on June 1, 2015, denying the allegations in the complaint. SPLP asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). By order dated July 31, 2015, FERC set the matter for hearing.

On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued her Initial Decision and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC trial staff challenged various aspects of the initial decision related to remedies and the statute of limitations issue.

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, 2017 and December 31, 2016, accruals of approximately $71 million and $77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.

In December 2016, Sunoco Logistics received multiple NOVs from the Delaware County Regional Water Quality Control Authority (“DELCORA”) in connection with a discharge at its Marcus Hook Industrial Complex (“MHIC”) in July 2016. Sunoco Logistics also entered in a Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (“PADEP”) related to its tank inspection plan at MHIC. These actions propose penalties in excess of $0.1 million, and ETP is currently in discussions with the PADEP and DELCORA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, the Partnership does not expect there to be a material impact to its results of operations, cash flows, or financial position.

The Ohio Environmental Protection Agency (“Ohio EPA”) has alleged that various environmental violations have occurred during construction of ETP subsidiary Rover Pipeline LLC’s (“Rover”) pipeline project. The alleged violations include inadvertent returns of drilling muds and fluids at horizontal directional drilling (“HDD”) locations in Ohio that affected waters of the State, storm water control violations, improper disposal of spent drilling mud containing diesel fuel residuals, and open burning. The alleged violations occurred from April to July, 2017. The Ohio EPA has proposed penalties of more than $900,000 in connection with the alleged violations and is seeking certain corrective actions. ETP is working with Ohio EPA to resolve the matter. 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.

In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessment of what led to the release at the Tuscarawas River site and what Rover can do to prevent reoccurrence once the HDD suspension is lifted. Rover has notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. The timing or outcome of this matter cannot be reasonably determined at this time; however, Rover anticipates resuming HDD activities before their suspension results in a material delay of pipeline construction.

On July 17, 2017, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Cease and Desist order requiring Rover to cease any land development activity in Doddridge and Tyler Counties. Under the order, Rover has 20 days to submit a corrective action plan and schedule for agency review. The order follows several notices of violation WVDEP issued to Rover alleging stormwater non-compliance. Rover is complying with the order, has already addressed many of the stormwater control issues, and anticipates having the corrective action plan and schedule in place before the order results in a material delay of pipeline construction.

On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania. On August 1st the EHB lifted the order as to two drill locations. On August 3, 2017, the EHB lifted the order as to 14 additional locations. The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”). The EHB Judge encouraged the parties to pursue a settlement with respect to the remaining HDD locations and facilitated a settlement meeting. On August 7, 2017 a final settlement was reached. A stipulated order has been submitted to the EHB Judge with respect to the settlement. The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project. The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation. Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits. Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company.

In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with Sunoco Pipeline regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania that affected waters of the State. Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval. The company is working to fulfill the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.

No amounts have been recorded in our June 30, 2017 or December 31, 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Environmental Matters

Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:


•	Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.


•	Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.


•	Currently operating Sunoco, Inc. retail sites previously contributed to Sunoco LP in January 2016.


•	Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.

•

Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of June 30, 2017, 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, 2017		December 31, 2016
Current	$	38	$	26
Non-current	276		283
Total environmental liabilities	$	314	$	309

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, 2017 and 2016, Sunoco, Inc. recorded $8 million and $8 million, respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30, 2017 and 2016, Sunoco, Inc. recorded $10 million and $14 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 a Notice of Violation (“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 to the EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

Our operations are also subject to the requirements of 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 our 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 Liabilities

6 Months Ended

Jun. 30, 2017

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 NGL and refined products 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.

We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. These contracts are not designated as hedges for accounting purposes.

We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment's operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The following table details our outstanding commodity-related derivatives:



	June 30, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	465,000		2017	(682,500	)	2017
Basis Swaps IFERC/NYMEX⁽¹⁾	33,112,500		2017	2,242,500		2017
Options – Puts	11,500,000		2018	—		—
Power (Megawatt):
Forwards	497,530		2017-2018	391,880		2017-2018
Futures	(212,880	)	2017-2018	109,564		2017-2018
Options – Puts	(364,000	)	2017	(50,400	)	2017
Options – Calls	607,200		2017	186,400		2017
Crude (Bbls) – Futures	(1,569,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(3,630,000	)	2017-2018	10,750,000		2017-2018
Swing Swaps IFERC	39,900,000		2017	(5,662,500	)	2017
Fixed Swaps/Futures	(39,250,000	)	2017-2019	(52,652,500	)	2017-2019
Forward Physical Contracts	(9,302,540	)	2017	(22,492,489	)	2017
Natural Gas Liquid (Bbls) – Forwards/Swaps	(4,501,400	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) – Futures	(803,000	)	2017	(2,240,000	)	2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(32,440,000	)	2017	(36,370,000	)	2017
Fixed Swaps/Futures	(32,440,000	)	2017	(36,370,000	)	2017
Hedged Item – Inventory	32,440,000		2017	36,370,000		2017


⁽¹⁾	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Interest Rate Risk

We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:



Term	Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	June 30, 2017		December 31, 2016
July 2017⁽²⁾	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300


⁽¹⁾	Floating rates are based on 3-month LIBOR.


⁽²⁾	Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary

The following table provides a summary of our derivative assets and liabilities:



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	June 30, 2017		December 31, 2016		June 30, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	8	$	—	$	(1	)	$	(4	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	127		338		(109		)	(416		)
Commodity derivatives	19		24		(18		)	(52		)
Interest rate derivatives	—		—		(201		)	(193		)
Embedded derivatives in Preferred Units	—		—		—			(1		)
	146		362		(328		)	(662		)
Total derivatives	$	154	$	362	$	(329	)	$	(666	)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:



		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	June 30, 2017			December 31, 2016			June 30, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(201	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	19			24			(18		)	(52		)
Broker cleared derivative contracts	Other current assets	135			338			(110		)	(420		)
Total gross derivatives		154			362			(329		)	(666		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(11		)	(4		)	11			4
Payments on margin deposit	Other current assets	(110		)	(338		)	110			338
Total net derivatives		$	33		$	20		$	(208	)	$	(324	)

We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

The following tables summarize the amounts recognized with respect to our derivative financial instruments:



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,				Six Months Ended June 30,
		2017		2016		2017		2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	6	$	21	$	2	$	17
Total		$	6	$	21	$	2	$	17



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2017			2016			2017			2016
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	15		$	(7	)	$	26		$	(16	)
Commodity derivatives – Non-trading	Cost of products sold	7			(48		)	(3		)	(43		)
Interest rate derivatives	Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Embedded derivatives	Other, net	—			(4		)	1			(4		)
Total		$	(3	)	$	(140	)	$	4		$	(214	)

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 30
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6441202&loc=d3e80720-113993

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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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+ Details

Related Party Transactions

6 Months Ended

Jun. 30, 2017

Related Party Transactions

RELATED PARTY TRANSACTIONS

In June 2017, the Partnership acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 9.

We previously had agreements with ETE to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by us on behalf of ETE and its subsidiaries. These agreements expired in 2016.

The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.

The following table summarizes the affiliate revenues on our consolidated statements of operations:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Affiliated revenues	$	133	$	133	$	251	$	207

The following table summarizes the related company balances on our consolidated balance sheets:



	June 30, 2017		December 31, 2016
Accounts receivable from related companies:
ETE	$	—	$	22
Sunoco LP	179		96
PES	8		6
FGT	9		15
Lake Charles LNG	1		4
Trans-Pecos Pipeline, LLC	4		1
Comanche Trail Pipeline, LLC	1		—
Traverse Rover LLC	100		—
Other	62		65
Total accounts receivable from related companies:	$	364	$	209

Accounts payable to related companies:
Sunoco LP	$	177	$	20
FGT	—		1
Lake Charles LNG	2		3
Other	21		19
Total accounts payable to related companies:	$	200	$	43



	June 30, 2017		December 31, 2016
Long-term notes receivable (payable) – related companies:
Sunoco LP	$	87	$	87
Phillips 66	—		(250		)
Net long-term notes receivable (payable) – related companies	$	87	$	(163	)

Reportable Segments

6 Months Ended

Jun. 30, 2017

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS

Subsequent to the Sunoco Logistics Merger, our financial statements reflect the following reportable segments, which conduct their business in the United States, as follows:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services; and

•all other.

The amounts included in the NGL and refined products transportation and services segment and the crude oil transportation and services segment have been retrospectively adjusted in these consolidated financial statements as a result of the Sunoco Logistics Merger.

The Partnership previously presented its retail marketing business as a separate reportable segment. Due to the transfer of the general partner interest of Sunoco LP from Energy Transfer Partners, L.P. to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from Energy Transfer Partners, L.P. to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP. As of June 30, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.7% of Sunoco LP’s total outstanding common units. This equity method investment in Sunoco LP has now been aggregated into the all other segment. Consequently, the retail marketing business that was previously consolidated has also been aggregated in the all other segment for all periods presented.

Intersegment and intrasegment transactions are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are primarily reflected in crude sales. Revenues from our all other segment are primarily reflected in other.

We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.

The following tables present financial information by segment:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	699		$	428		$	1,467		$	874
Intersegment revenues	54			113			102			225
	753			541			1,569			1,099
Interstate transportation and storage:
Revenues from external customers	201			229			432			483
Intersegment revenues	6			5			10			10
	207			234			442			493
Midstream:
Revenues from external customers	633			690			1,198			1,217
Intersegment revenues	982			640			2,054			1,205
	1,615			1,330			3,252			2,422
NGL and refined products transportation and services:
Revenues from external customers	1,767			1,445			3,885			2,617
Intersegment revenues	1			42			160			203
	1,768			1,487			4,045			2,820
Crude oil transportation and services:
Revenues from external customers	2,460			1,904			5,035			3,290
Intersegment revenues	126			85			240			164
	2,586			1,989			5,275			3,454
All other:
Revenues from external customers	816			593			1,454			1,289
Intersegment revenues	54			118			186			276
	870			711			1,640			1,565
Eliminations	(1,223		)	(1,003		)	(2,752		)	(2,083		)
Total revenues	$	6,576		$	5,289		$	13,471		$	9,770



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	148		$	149		$	317		$	328
Interstate transportation and storage	262			278			527			570
Midstream	412			298			732			561
NGL and refined products transportation and services	391			341			773			689
Crude oil transportation and services	279			124			434			352
All other	107			180			230			282
Total	1,599			1,370			3,013			2,782
Depreciation, depletion and amortization	(557		)	(496		)	(1,117		)	(966		)
Interest expense, net	(346		)	(317		)	(685		)	(636		)
Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Non-cash unit-based compensation expense	(15		)	(19		)	(38		)	(38		)
Unrealized gains (losses) on commodity risk management activities	34			(18		)	98			(81		)
Inventory valuation adjustments	(58		)	132			(56		)	106
Adjusted EBITDA related to unconsolidated affiliates	(247		)	(252		)	(486		)	(471		)
Equity in earnings (losses) of unconsolidated affiliates	(61		)	119			12			195
Other, net	47			25			69			41
Income before income tax expense (benefit)	$	371		$	463		$	790		$	781



	June 30, 2017		December 31, 2016
Assets:
Intrastate transportation and storage	$	7,129	$	5,164
Interstate transportation and storage	12,153		10,833
Midstream	17,240		17,873
NGL and refined products transportation and services	16,407		14,128
Crude oil transportation and services	16,137		15,941
All other	5,153		6,252
Total assets	$	74,219	$	70,191

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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+ Details

Guarantor Financial Information (Notes)

6 Months Ended

Jun. 30, 2017

Guarantor Financial Information [Abstract]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

CONSOLIDATING GUARANTOR FINANCIAL INFORMATION

Prior to the Sunoco Logistics Merger, Sunoco Logistics Partners Operations L.P., a subsidiary of Sunoco Logistics was the issuer of multiple series of senior notes that were guaranteed by Sunoco Logistics. Subsequent to the Sunoco Logistics Merger, these notes continue to be guaranteed by the parent company.

These guarantees are full and unconditional. For the purposes of this footnote, Energy Transfer Partners, L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.”

The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting. To present the supplemental condensed consolidating financial information on a comparable basis, the prior period financial information has been recast as if the Sunoco Logistics Merger occurred on January 1, 2016.

The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows:



	June 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	23		$	249	$	—		$	272
All other current assets	—			—			5,114		—			5,114
Property, plant and equipment, net	—			—			54,536		—			54,536
Investments in unconsolidated affiliates	24,154			11,502			4,228		(35,656		)	4,228
All other assets	—			4			10,065		—			10,069
Total assets	$	24,154		$	11,529		$	74,192	$	(35,656	)	$	74,219

Current liabilities	$	(1,491	)	$	(3,421	)	$	11,901	$	—		$	6,989
Non-current liabilities	—			7,062			30,753		—			37,815
Noncontrolling interest	—			—			3,799		—			3,799
Total partners' capital	25,645			7,888			27,739		(35,656		)	25,616
Total liabilities and equity	$	24,154		$	11,529		$	74,192	$	(35,656	)	$	74,219



	December 31, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	41		$	319	$	—		$	360
All other current assets	—			2			5,367		—			5,369
Property, plant and equipment, net	—			—			50,917		—			50,917
Investments in unconsolidated affiliates	23,350			10,664			4,280		(34,014		)	4,280
All other assets	—			5			9,260		—			9,265
Total assets	$	23,350		$	10,712		$	70,143	$	(34,014	)	$	70,191

Current liabilities	$	(1,761	)	$	(3,800	)	$	11,764	$	—		$	6,203
Non-current liabilities	299			7,313			30,148		(299		)	37,461
Noncontrolling interest	—			—			1,297		—			1,297
Total partners' capital	24,812			7,199			26,934		(33,715		)	25,230
Total liabilities and equity	$	23,350		$	10,712		$	70,143	$	(34,014	)	$	70,191



	Three Months Ended June 30, 2017
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	6,576		$	—		$	6,576
Operating costs, expenses, and other	—		1			5,843			—			5,844
Operating income (loss)	—		(1		)	733			—			732
Interest expense, net	—		(39		)	(307		)	—			(346		)
Equity in earnings (losses) of unconsolidated affiliates	199		137			(61		)	(336		)	(61		)
Losses on interest rate derivatives	—		—			(25		)	—			(25		)
Other, net	—		3			69			(1		)	71
Income before income tax expense	199		100			409			(337		)	371
Income tax expense	—		—			79			—			79
Net income	199		100			330			(337		)	292
Less: Net income attributable to noncontrolling interest	—		—			93			—			93
Net income attributable to partners	$	199	$	100		$	237		$	(337	)	$	199

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	199		100			329			(337		)	291
Comprehensive income attributable to noncontrolling interest	—		—			93			—			93
Comprehensive income attributable to partners	$	199	$	100		$	236		$	(337	)	$	198



	Three Months Ended June 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	5,289		$	—		$	5,289
Operating costs, expenses, and other	—		1			4,573			—			4,574
Operating income (loss)	—		(1		)	716			—			715
Interest expense, net	—		(39		)	(278		)	—			(317		)
Equity in earnings of unconsolidated affiliates	451		242			119			(693		)	119
Losses on interest rate derivatives	—		—			(81		)	—			(81		)
Other, net	—		—			27			—			27
Income before income tax benefit	451		202			503			(693		)	463
Income tax benefit	—		—			(9		)	—			(9		)
Net income	451		202			512			(693		)	472
Less: Net income attributable to noncontrolling interest	—		—			18			—			—
Net income attributable to partners	$	451	$	202		$	494		$	(693	)	$	472

Other comprehensive income	$	—	$	—		$	4		$	—		$	4
Comprehensive income	451		202			516			(693		)	476
Comprehensive income attributable to noncontrolling interest	—		—			18			—			18
Comprehensive income attributable to partners	$	451	$	202		$	498		$	(693	)	$	458



	Six Months Ended June 30, 2017
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	13,471		$	—		$	13,471
Operating costs, expenses, and other	—		1			12,084			—			12,085
Operating income (loss)	—		(1		)	1,387			—			1,386
Interest expense, net	—		(81		)	(604		)	—			(685		)
Equity in earnings of unconsolidated affiliates	1,010		765			12			(1,775		)	12
Losses on interest rate derivatives	—		—			(20		)	—			(20		)
Other, net	—		3			95			(1		)	97
Income before income tax expense	1,010		686			870			(1,776		)	790
Income tax expense	—		—			134			—			134
Net income	1,010		686			736			(1,776		)	656
Less: Net income attributable to noncontrolling interest	—		—			133			—			133
Net income attributable to partners	$	1,010	$	686		$	603		$	(1,776	)	$	523

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	1,010		686			735			(1,776		)	655
Comprehensive income attributable to noncontrolling interest	—		—			133			—			133
Comprehensive income attributable to partners	$	1,010	$	686		$	602		$	(1,776	)	$	522



	Six Months Ended June 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	9,770		$	—		$	9,770
Operating costs, expenses, and other	—		1			8,440			—			8,441
Operating income (loss)	—		(1		)	1,330			—			1,329
Interest expense, net	—		(77		)	(559		)	—			(636		)
Equity in earnings of unconsolidated affiliates	811		425			195			(1,236		)	195
Losses on interest rate derivatives	—		—			(151		)	—			(151		)
Other, net	—		—			44			—			44
Income before income tax benefit	811		347			859			(1,236		)	781
Income tax benefit	—		—			(67		)	—			(67		)
Net income	811		347			926			(1,236		)	848
Less: Net income attributable to noncontrolling interest	—		—			36			—			36
Net income attributable to partners	$	811	$	347		$	890		$	(1,236	)	$	812

Other comprehensive loss	$	—	$	—		$	(10	)	$	—		$	(10	)
Comprehensive income	811		347			916			(1,236		)	838
Comprehensive income attributable to noncontrolling interest	—		—			36			—			36
Comprehensive income attributable to partners	$	811	$	347		$	880		$	(1,236	)	$	802



	Six Months Ended June 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	1,010		$	652		$	1,764		$	(1,776	)	$	1,650
Cash flows used in investing activities	(716		)	(421		)	(2,125		)	1,776			(1,486		)
Cash flows provided by (used in) financing activities	(294		)	(249		)	291			—			(252		)
Change in cash	—			(18		)	(70		)	—			(88		)
Cash at beginning of period	—			41			319			—			360
Cash at end of period	$	—		$	23		$	249		$	—		$	272



	Six Months Ended June 30, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	811		$	320		$	1,531		$	(1,236	)	$	1,426
Cash flows used in investing activities	(1,029		)	(847		)	(585		)	1,236			(1,225		)
Cash flows provided by (used in) financing activities	218			526			(1,086		)	—			(342		)
Change in cash	—			(1		)	(140		)	—			(141		)
Cash at beginning of period	—			37			490			—			527
Cash at end of period	$	—		$	36		$	350		$	—		$	386

- Definition

The entire disclosure for condensed financial information, including the financial position, cash flows, and the results of operations of the registrant (parent company) as of the same dates or for the same periods for which audited consolidated financial statements are being presented. Alternatively, the details of this disclosure can be reported by the specific parent company taxonomy elements, indicating the appropriate date and period contexts in an instance document.

+ References + Details

Operations And Organization Accounting Policy (Policies)	6 Months Ended
	Jun. 30, 2017
Accounting Policies [Abstract]
Use of Estimates, Policy [Policy Text Block]	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.
New Accounting Pronouncements, Policy [Policy Text Block]	In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catchup transition method). The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method. We are in the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standards. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts may be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We continue to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-09, Stock Compensation (Topic 718) (“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements and related disclosures. In October 2016, the FASB issued Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that adoption of this standard will have on the consolidated financial statements and related disclosures. On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-17, Consolidation (Topic 810): Interests Held Through Related Parties That Are Under Common Control (“ASU 2016-17”), which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (“VIE”) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under the amendments, a single decision maker is required to include indirect interests on a proportionate basis consistent with indirect interests held through other related parties. The adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures. In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership expects that the adoption of this standard will change its approach for measuring goodwill impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. The Partnership plans to apply this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

Cash And Cash Equivalents (Tables)

6 Months Ended

Jun. 30, 2017

Cash and Cash Equivalents [Abstract]

Net Cash Provided By Operating Activities

The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows:



	Six Months Ended June 30,
	2017			2016
Accounts receivable	$	88		$	(471	)
Accounts receivable from related companies	(115		)	(129		)
Inventories	137			(157		)
Other current assets	77			(53		)
Other non-current assets, net	(39		)	8
Accounts payable	(286		)	509
Accounts payable to related companies	131			21
Accrued and other current liabilities	(389		)	(22		)
Other non-current liabilities	7			20
Derivative assets and liabilities, net	(21		)	178
Net change in operating assets and liabilities, net of effects of acquisitions	$	(410	)	$	(96	)

Non-Cash Investing And Financing Activities

Non-cash investing and financing activities are as follows:



	Six Months Ended June 30,
	2017		2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,363	$	861
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
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988	$	—

Inventories (Tables)

6 Months Ended

Jun. 30, 2017

Inventory, Gross [Abstract]

Schedule Of Inventories

Inventories consisted of the following:



	June 30, 2017		December 31, 2016
Natural gas and NGLs	$	546	$	699
Crude oil	681		683
Refined products	76		113
Spare parts and other	217		217
Total inventories	$	1,520	$	1,712

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2017

Fair Value Measurements [Abstract]

Fair Value Of Assets And Liabilities Measured And Recorded On Recurring Basis



				Fair Value Measurements at June 30, 2017
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	9		$	9		$	—
Swing Swaps IFERC	3			1			2
Fixed Swaps/Futures	38			38			—
Forward Physical Swaps	4			—			4
Power:
Forwards	13			—			13
Futures	1			1			—
Natural Gas Liquids – Forwards/Swaps	77			77			—
Crude – Futures	9			9			—
Total commodity derivatives	154			135			19
Total assets	$	154		$	135		$	19
Liabilities:
Interest rate derivatives	$	(201	)	$	—		$	(201	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(9		)	(9		)	—
Swing Swaps IFERC	(2		)	—			(2		)
Fixed Swaps/Futures	(25		)	(25		)	—
Forward Physical Swaps	(1		)	—			(1		)
Power:
Forwards	(12		)	—			(12		)
Futures	(1		)	(1		)	—
Natural Gas Liquids – Forwards/Swaps	(70		)	(70		)	—
Refined Products – Futures	(3		)	(3		)	—
Crude – Futures	(5		)	(5		)	—
Total commodity derivatives	(128		)	(113		)	(15		)
Total liabilities	$	(329	)	$	(113	)	$	(216	)



				Fair Value Measurements at December 31, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	14		$	14		$	—		$	—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	96			96			—			—
Forward Physical Swaps	1			—			1			—
Power:
Forwards	4			—			4			—
Futures	1			1			—			—
Options – Calls	1			1			—			—
Natural Gas Liquids – Forwards/Swaps	233			233			—			—
Refined Products – Futures	1			1			—			—
Crude – Futures	9			9			—			—
Total commodity derivatives	362			355			7			—
Total assets	$	362		$	355		$	7		$	—
Liabilities:
Interest rate derivatives	$	(193	)	$	—		$	(193	)	$	—
Embedded derivatives in Preferred Units	(1		)	—			—			(1		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(11		)	(11		)	—			—
Swing Swaps IFERC	(3		)	—			(3		)	—
Fixed Swaps/Futures	(149		)	(149		)	—			—
Power:
Forwards	(5		)	—			(5		)	—
Futures	(1		)	(1		)	—			—
Natural Gas Liquids – Forwards/Swaps	(273		)	(273		)	—			—
Refined Products – Futures	(17		)	(17		)	—			—
Crude – Futures	(13		)	(13		)	—			—
Total commodity derivatives	(472		)	(464		)	(8		)	—
Total liabilities	$	(666	)	$	(464	)	$	(201	)	$	(1	)

Net Income Per Limited Partner Unit (Tables)

6 Months Ended

Jun. 30, 2017

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

A reconciliation of net income (loss) and weighted average units used in computing basic and diluted net income (loss) per unit is as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Net income	$	292		$	472		$	656		$	848
Less: Income attributable to noncontrolling interest	93			102			133			167
Net income, net of noncontrolling interest	199			370			523			681
General Partner’s interest in net income	251			223			457			520
Class H Unitholder’s interest in net income	—			85			98			164
Class I Unitholder’s interest in net income	—			2			—			4
Common Unitholders’ interest in net income (loss)	(52		)	60			(32		)	(7		)
Additional (earnings) losses allocated to General Partner	15			(3		)	12			(6		)
Distributions on employee unit awards, net of allocation to General Partner	(6		)	(5		)	(13		)	(10		)
Net income (loss) available to Common Unitholders	$	(43	)	$	52		$	(33	)	$	(23	)
Weighted average Common Units – basic ⁽¹⁾	1,021.7			752.4			922.5			743.9
Basic net income (loss) per Common Unit	$	(0.04	)	$	0.07		$	(0.04	)	$	(0.03	)

Net income (loss) available to Common Unitholders	$	(43	)	$	52		$	(33	)	$	(23	)
Income attributable to Preferred Units	—			(4		)	—			(3		)
Diluted net income (loss) available to Common Unitholders	$	(43	)	$	48		$	(33	)	$	(26	)
Weighted average Common Units – basic ⁽¹⁾	1,021.7			752.4			922.5			743.9
Dilutive effect of unvested employee unit awards	—			1.0			—			—
Dilutive effect of Preferred Units	—			0.5			—			0.5
Weighted average Common Units – diluted ⁽¹⁾	1,021.7			753.9			922.5			744.4
Diluted net income (loss) per Common Unit	$	(0.04	)	$	0.06		$	(0.04	)	$	(0.03	)

⁽¹⁾Excludes Common Units owned by the Partnership’s consolidated subsidiaries.

Equity (Tables)

6 Months Ended

Jun. 30, 2017

Schedule of Distributions Made To General and Limited Partners [Table Text Block]

The following table shows the target distribution levels and distribution “splits” between the general partner and the holders of the Partnership’s common units:



		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	IDRs	Partners ⁽¹⁾
Minimum Quarterly Distribution	$0.0750	—%	100%
First Target Distribution	up to $0.0833	—%	100%
Second Target Distribution	above $0.0833 up to $0.0958	13%	87%
Third Target Distribution	above $0.0958 up to $0.2638	35%	65%
Thereafter	above $0.2638	48%	52%

Change In Common Units

The changes in outstanding common units during the six months ended June 30, 2017 were as follows:



		Number of Units
Number of common units at December 31, 2016 ⁽¹⁾		794.8
Common units issued in connection with equity distribution agreements		15.6
Common units issued in connection with the distribution reinvestment plan		2.8
Common units issued to ETE in a private placement transaction		23.7
Common unit increase from Sunoco Logistics Merger ⁽²⁾		255.4
Issuance of common units under equity incentive plans		0.3
Number of common units at June 30, 2017		1,092.6

Distributions Made to Limited Partner, by Distribution [Table Text Block]

Following are distributions declared and/or paid by the Partnership subsequent to the Sunoco Logistics Merger:



Quarter Ended	Record Date	Payment Date	Rate
March 31, 2017	May 10, 2017	May 15, 2017	$	0.5350
June 30, 2017	August 7, 2017	August 14, 2017	0.5500

Schedule of Future Relinquishments of Incentive Distribution Rights [Table Text Block]

ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods.



	Total Year
2017 (remainder)	$	336
2018	153
2019	128
Each year beyond 2019	33

Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:



	June 30, 2017			December 31, 2016
Available-for-sale securities	$	5		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial gain related to pensions and other postretirement benefits	4			7
Investments in unconsolidated affiliates, net	3			4
Total AOCI, net of tax	$	7		$	8

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)

6 Months Ended

Jun. 30, 2017

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]

Schedule of Rent Expense [Table Text Block]



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Rental expense	$	19	$	21	$	39	$	39

Environmental Exit Costs by Cost [Table Text Block]



	June 30, 2017		December 31, 2016
Current	$	38	$	26
Non-current	276		283
Total environmental liabilities	$	314	$	309

Derivative Assets And Liabilities (Tables)

6 Months Ended

Jun. 30, 2017

Derivative [Line Items]

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:



	June 30, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	465,000		2017	(682,500	)	2017
Basis Swaps IFERC/NYMEX⁽¹⁾	33,112,500		2017	2,242,500		2017
Options – Puts	11,500,000		2018	—		—
Power (Megawatt):
Forwards	497,530		2017-2018	391,880		2017-2018
Futures	(212,880	)	2017-2018	109,564		2017-2018
Options – Puts	(364,000	)	2017	(50,400	)	2017
Options – Calls	607,200		2017	186,400		2017
Crude (Bbls) – Futures	(1,569,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(3,630,000	)	2017-2018	10,750,000		2017-2018
Swing Swaps IFERC	39,900,000		2017	(5,662,500	)	2017
Fixed Swaps/Futures	(39,250,000	)	2017-2019	(52,652,500	)	2017-2019
Forward Physical Contracts	(9,302,540	)	2017	(22,492,489	)	2017
Natural Gas Liquid (Bbls) – Forwards/Swaps	(4,501,400	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) – Futures	(803,000	)	2017	(2,240,000	)	2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(32,440,000	)	2017	(36,370,000	)	2017
Fixed Swaps/Futures	(32,440,000	)	2017	(36,370,000	)	2017
Hedged Item – Inventory	32,440,000		2017	36,370,000		2017


⁽¹⁾	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Interest Rate Swaps Outstanding

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
Term	Type⁽¹⁾	June 30, 2017		December 31, 2016
July 2017⁽²⁾	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300


⁽¹⁾	Floating rates are based on 3-month LIBOR.


⁽²⁾	Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

Fair Value Of Derivative Instruments

The following table provides a summary of our derivative assets and liabilities:



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	June 30, 2017		December 31, 2016		June 30, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	8	$	—	$	(1	)	$	(4	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	127		338		(109		)	(416		)
Commodity derivatives	19		24		(18		)	(52		)
Interest rate derivatives	—		—		(201		)	(193		)
Embedded derivatives in Preferred Units	—		—		—			(1		)
	146		362		(328		)	(662		)
Total derivatives	$	154	$	362	$	(329	)	$	(666	)

Derivatives, Offsetting Fair Value Amounts [Table Text Block]



		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	June 30, 2017			December 31, 2016			June 30, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(201	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	19			24			(18		)	(52		)
Broker cleared derivative contracts	Other current assets	135			338			(110		)	(420		)
Total gross derivatives		154			362			(329		)	(666		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(11		)	(4		)	11			4
Payments on margin deposit	Other current assets	(110		)	(338		)	110			338
Total net derivatives		$	33		$	20		$	(208	)	$	(324	)

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,				Six Months Ended June 30,
		2017		2016		2017		2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	6	$	21	$	2	$	17
Total		$	6	$	21	$	2	$	17

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 June 30,						Six Months Ended June 30,
		2017			2016			2017			2016
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	15		$	(7	)	$	26		$	(16	)
Commodity derivatives – Non-trading	Cost of products sold	7			(48		)	(3		)	(43		)
Interest rate derivatives	Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Embedded derivatives	Other, net	—			(4		)	1			(4		)
Total		$	(3	)	$	(140	)	$	4		$	(214	)

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579240-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41620-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2017

The following table summarizes the affiliate revenues on our consolidated statements of operations:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Affiliated revenues	$	133	$	133	$	251	$	207



	June 30, 2017		December 31, 2016
Accounts receivable from related companies:
ETE	$	—	$	22
Sunoco LP	179		96
PES	8		6
FGT	9		15
Lake Charles LNG	1		4
Trans-Pecos Pipeline, LLC	4		1
Comanche Trail Pipeline, LLC	1		—
Traverse Rover LLC	100		—
Other	62		65
Total accounts receivable from related companies:	$	364	$	209

Accounts payable to related companies:
Sunoco LP	$	177	$	20
FGT	—		1
Lake Charles LNG	2		3
Other	21		19
Total accounts payable to related companies:	$	200	$	43



	June 30, 2017		December 31, 2016
Long-term notes receivable (payable) – related companies:
Sunoco LP	$	87	$	87
Phillips 66	—		(250		)
Net long-term notes receivable (payable) – related companies	$	87	$	(163	)

Reportable Segments (Tables)

6 Months Ended

Jun. 30, 2017

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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	699		$	428		$	1,467		$	874
Intersegment revenues	54			113			102			225
	753			541			1,569			1,099
Interstate transportation and storage:
Revenues from external customers	201			229			432			483
Intersegment revenues	6			5			10			10
	207			234			442			493
Midstream:
Revenues from external customers	633			690			1,198			1,217
Intersegment revenues	982			640			2,054			1,205
	1,615			1,330			3,252			2,422
NGL and refined products transportation and services:
Revenues from external customers	1,767			1,445			3,885			2,617
Intersegment revenues	1			42			160			203
	1,768			1,487			4,045			2,820
Crude oil transportation and services:
Revenues from external customers	2,460			1,904			5,035			3,290
Intersegment revenues	126			85			240			164
	2,586			1,989			5,275			3,454
All other:
Revenues from external customers	816			593			1,454			1,289
Intersegment revenues	54			118			186			276
	870			711			1,640			1,565
Eliminations	(1,223		)	(1,003		)	(2,752		)	(2,083		)
Total revenues	$	6,576		$	5,289		$	13,471		$	9,770

Operating Segments [Member]

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	148		$	149		$	317		$	328
Interstate transportation and storage	262			278			527			570
Midstream	412			298			732			561
NGL and refined products transportation and services	391			341			773			689
Crude oil transportation and services	279			124			434			352
All other	107			180			230			282
Total	1,599			1,370			3,013			2,782
Depreciation, depletion and amortization	(557		)	(496		)	(1,117		)	(966		)
Interest expense, net	(346		)	(317		)	(685		)	(636		)
Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Non-cash unit-based compensation expense	(15		)	(19		)	(38		)	(38		)
Unrealized gains (losses) on commodity risk management activities	34			(18		)	98			(81		)
Inventory valuation adjustments	(58		)	132			(56		)	106
Adjusted EBITDA related to unconsolidated affiliates	(247		)	(252		)	(486		)	(471		)
Equity in earnings (losses) of unconsolidated affiliates	(61		)	119			12			195
Other, net	47			25			69			41
Income before income tax expense (benefit)	$	371		$	463		$	790		$	781

Assets Segments [Member]

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]



	June 30, 2017		December 31, 2016
Assets:
Intrastate transportation and storage	$	7,129	$	5,164
Interstate transportation and storage	12,153		10,833
Midstream	17,240		17,873
NGL and refined products transportation and services	16,407		14,128
Crude oil transportation and services	16,137		15,941
All other	5,153		6,252
Total assets	$	74,219	$	70,191

Guarantor Financial Information (Tables)

6 Months Ended

Jun. 30, 2017

Guarantor Financial Information [Abstract]

Condensed Income Statement [Table Text Block]

The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows:



	June 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	23		$	249	$	—		$	272
All other current assets	—			—			5,114		—			5,114
Property, plant and equipment, net	—			—			54,536		—			54,536
Investments in unconsolidated affiliates	24,154			11,502			4,228		(35,656		)	4,228
All other assets	—			4			10,065		—			10,069
Total assets	$	24,154		$	11,529		$	74,192	$	(35,656	)	$	74,219

Current liabilities	$	(1,491	)	$	(3,421	)	$	11,901	$	—		$	6,989
Non-current liabilities	—			7,062			30,753		—			37,815
Noncontrolling interest	—			—			3,799		—			3,799
Total partners' capital	25,645			7,888			27,739		(35,656		)	25,616
Total liabilities and equity	$	24,154		$	11,529		$	74,192	$	(35,656	)	$	74,219



	December 31, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	41		$	319	$	—		$	360
All other current assets	—			2			5,367		—			5,369
Property, plant and equipment, net	—			—			50,917		—			50,917
Investments in unconsolidated affiliates	23,350			10,664			4,280		(34,014		)	4,280
All other assets	—			5			9,260		—			9,265
Total assets	$	23,350		$	10,712		$	70,143	$	(34,014	)	$	70,191

Current liabilities	$	(1,761	)	$	(3,800	)	$	11,764	$	—		$	6,203
Non-current liabilities	299			7,313			30,148		(299		)	37,461
Noncontrolling interest	—			—			1,297		—			1,297
Total partners' capital	24,812			7,199			26,934		(33,715		)	25,230
Total liabilities and equity	$	23,350		$	10,712		$	70,143	$	(34,014	)	$	70,191



	Three Months Ended June 30, 2017
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	6,576		$	—		$	6,576
Operating costs, expenses, and other	—		1			5,843			—			5,844
Operating income (loss)	—		(1		)	733			—			732
Interest expense, net	—		(39		)	(307		)	—			(346		)
Equity in earnings (losses) of unconsolidated affiliates	199		137			(61		)	(336		)	(61		)
Losses on interest rate derivatives	—		—			(25		)	—			(25		)
Other, net	—		3			69			(1		)	71
Income before income tax expense	199		100			409			(337		)	371
Income tax expense	—		—			79			—			79
Net income	199		100			330			(337		)	292
Less: Net income attributable to noncontrolling interest	—		—			93			—			93
Net income attributable to partners	$	199	$	100		$	237		$	(337	)	$	199

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	199		100			329			(337		)	291
Comprehensive income attributable to noncontrolling interest	—		—			93			—			93
Comprehensive income attributable to partners	$	199	$	100		$	236		$	(337	)	$	198



	Three Months Ended June 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	5,289		$	—		$	5,289
Operating costs, expenses, and other	—		1			4,573			—			4,574
Operating income (loss)	—		(1		)	716			—			715
Interest expense, net	—		(39		)	(278		)	—			(317		)
Equity in earnings of unconsolidated affiliates	451		242			119			(693		)	119
Losses on interest rate derivatives	—		—			(81		)	—			(81		)
Other, net	—		—			27			—			27
Income before income tax benefit	451		202			503			(693		)	463
Income tax benefit	—		—			(9		)	—			(9		)
Net income	451		202			512			(693		)	472
Less: Net income attributable to noncontrolling interest	—		—			18			—			—
Net income attributable to partners	$	451	$	202		$	494		$	(693	)	$	472

Other comprehensive income	$	—	$	—		$	4		$	—		$	4
Comprehensive income	451		202			516			(693		)	476
Comprehensive income attributable to noncontrolling interest	—		—			18			—			18
Comprehensive income attributable to partners	$	451	$	202		$	498		$	(693	)	$	458



	Six Months Ended June 30, 2017
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	13,471		$	—		$	13,471
Operating costs, expenses, and other	—		1			12,084			—			12,085
Operating income (loss)	—		(1		)	1,387			—			1,386
Interest expense, net	—		(81		)	(604		)	—			(685		)
Equity in earnings of unconsolidated affiliates	1,010		765			12			(1,775		)	12
Losses on interest rate derivatives	—		—			(20		)	—			(20		)
Other, net	—		3			95			(1		)	97
Income before income tax expense	1,010		686			870			(1,776		)	790
Income tax expense	—		—			134			—			134
Net income	1,010		686			736			(1,776		)	656
Less: Net income attributable to noncontrolling interest	—		—			133			—			133
Net income attributable to partners	$	1,010	$	686		$	603		$	(1,776	)	$	523

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	1,010		686			735			(1,776		)	655
Comprehensive income attributable to noncontrolling interest	—		—			133			—			133
Comprehensive income attributable to partners	$	1,010	$	686		$	602		$	(1,776	)	$	522



	Six Months Ended June 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	9,770		$	—		$	9,770
Operating costs, expenses, and other	—		1			8,440			—			8,441
Operating income (loss)	—		(1		)	1,330			—			1,329
Interest expense, net	—		(77		)	(559		)	—			(636		)
Equity in earnings of unconsolidated affiliates	811		425			195			(1,236		)	195
Losses on interest rate derivatives	—		—			(151		)	—			(151		)
Other, net	—		—			44			—			44
Income before income tax benefit	811		347			859			(1,236		)	781
Income tax benefit	—		—			(67		)	—			(67		)
Net income	811		347			926			(1,236		)	848
Less: Net income attributable to noncontrolling interest	—		—			36			—			36
Net income attributable to partners	$	811	$	347		$	890		$	(1,236	)	$	812

Other comprehensive loss	$	—	$	—		$	(10	)	$	—		$	(10	)
Comprehensive income	811		347			916			(1,236		)	838
Comprehensive income attributable to noncontrolling interest	—		—			36			—			36
Comprehensive income attributable to partners	$	811	$	347		$	880		$	(1,236	)	$	802



	Six Months Ended June 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	1,010		$	652		$	1,764		$	(1,776	)	$	1,650
Cash flows used in investing activities	(716		)	(421		)	(2,125		)	1,776			(1,486		)
Cash flows provided by (used in) financing activities	(294		)	(249		)	291			—			(252		)
Change in cash	—			(18		)	(70		)	—			(88		)
Cash at beginning of period	—			41			319			—			360
Cash at end of period	$	—		$	23		$	249		$	—		$	272



	Six Months Ended June 30, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	811		$	320		$	1,531		$	(1,236	)	$	1,426
Cash flows used in investing activities	(1,029		)	(847		)	(585		)	1,236			(1,225		)
Cash flows provided by (used in) financing activities	218			526			(1,086		)	—			(342		)
Change in cash	—			(1		)	(140		)	—			(141		)
Cash at beginning of period	—			37			490			—			527
Cash at end of period	$	—		$	36		$	350		$	—		$	386

Operations And Organization Operations And Organization (Details) shares in Millions	1 Months Ended	6 Months Ended
	Apr. 30, 2017 shares	Jun. 30, 2017
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%
Rover Pipeline LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		65.00%
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%
SXL and ETP Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.5
Sale of Stock, Number of Shares Issued in Transaction	832

Acquisitions and Contribution Transactions Narrative (Details) - USD ($) $ in Millions	1 Months Ended		6 Months Ended
	Jul. 31, 2017	Feb. 28, 2017	Jun. 30, 2017	Feb. 01, 2017	Dec. 31, 2016
Goodwill			$ 3,919		$ 3,897
Intangible assets, net			5,443		4,696
Property, plant and equipment			62,790		$ 58,220
Capital contributions from noncontrolling interest			1,444
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross		$ 2,000
Energy Transfer Crude Oil Company, LLC [Member] \| Subsequent Event [Member] \| Dakota Access, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	15.00%
Dakota Access and ETCOC [Member] \| Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		25.00%
Dakota Access and ETCOC [Member] \| Bakken Pipeline Investments LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		75.00%
Bakken Pipeline Investments LLC [Member] \| Bakken Holdings Company LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired				49.00%
Sunoco Logistics [Member] \| Permian Express Partners LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		85.00%
Capital contributions from noncontrolling interest			988
Sunoco Logistics [Member] \| Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Sunoco Logistics [Member] \| Subsequent Event [Member] \| Permian Express Partners LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	88.00%
Bakken Pipeline [Member] \| Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		25.00%
Bakken Pipeline [Member] \| ETP and Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		38.25%
Bakken Pipeline [Member] \| MarEn Bakken Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		36.75%
Customer Relationships [Member] \| Sunoco Logistics [Member] \| Permian Express Partners LLC [Member]
Intangible assets, net			547
Property, plant and equipment			$ 435

Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Cash and Cash Equivalents [Abstract]
Accounts receivable	$ 88	$ (471)
Accounts receivable from related companies	(115)	(129)
Inventories	137	(157)
Other current assets	77	(53)
Other non-current assets, net	(39)	8
Accounts payable	(286)	509
Accounts payable to related companies	131	21
Accrued and other current liabilities	(389)	(22)
Other non-current liabilities	7	20
Derivative assets and liabilities, net	(21)	178
Net change in operating assets and liabilities, net of effects of acquisitions	$ (410)	$ (96)

Cash And Cash Equivalents Non-Cash Investing and Financing Activities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 1,363	$ 861
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP	0	194
Net gains from subsidiary common unit issuances	0	14
NON-CASH FINANCING ACTIVITIES:
Capital Contributions from Noncontrolling Interest	$ 988	$ 0

Inventories (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Inventory, Gross [Abstract]
Natural gas and NGLs	$ 546	$ 699
Crude oil	681	683
Refined products	76	113
Spare parts and other	217	217
Total inventories	$ 1,520	$ 1,712

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Fair Value Measurements [Abstract]
Transfers between levels in fair value hierarchy	$ 0
Aggregate fair value of long-term debt	34,680	$ 33,850
Long-term Debt	$ 33,390	$ 32,930

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, 2017

Jun. 30, 2016

Jun. 30, 2017

Jun. 30, 2016

Earnings Per Share [Abstract]

Net income

$ 292

$ 472

$ 656

$ 848

Less: Income attributable to noncontrolling interest

102

133

167

Net income, net of noncontrolling interest

199

370

523

681

General Partner’s interest in net income

251

223

457

520

Class H Unitholder’s interest in net income

164

Class I Unitholder’s interest in net income

Common Unitholders’ interest in net income (loss)

(52)

(32)

(7)

Additional (earnings) losses allocated to General Partner

(3)

(6)

Distributions on employee unit awards, net of allocation to General Partner

(6)

(5)

(13)

(10)

Net income (loss) available to Common Unitholders

(43)

(33)

(23)

Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities

$ 0

$ (4)

$ 0

$ (3)

Weighted average Common Units – basic (1)

^[1]

1,021.7

752.4

922.5

743.9

Diluted net income (loss) available to Common Unitholders

$ (43)

$ 48

$ (33)

$ (26)

Dilutive effect of unvested employee unit awards

0.0

1.0

0.0

Incremental Common Shares Attributable to Dilutive Effect of Conversion of Preferred Stock

0.0

0.5

0.0

0.5

Weighted average Common Units – diluted (1)

^[1]

1,021.7

753.9

922.5

744.4

Basic net income (loss) per Common Unit

$ (0.04)

$ 0.07

$ (0.04)

$ (0.03)

Diluted net income (loss) per Common Unit

$ (0.04)

$ 0.06

$ (0.04)

$ (0.03)

[1]	Excludes Common Units owned by the Partnership’s consolidated subsidiaries.

Net Income Per Limited Partner Unit Narrative (Details)	1 Months Ended
Net Income Per Limited Partner Unit Narrative (Details)	Apr. 30, 2017
SXL and ETP Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.5

Debt Obligations Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Repayments of Long-term Debt	$ 10,953	$ 7,514
Proceeds from Issuance of Long-term Debt	11,466	$ 7,811
ETLP [Member] \| ETLP Credit Facility due November 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity	3,750
Long-term Line of Credit	1,540
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	1,670
Commercial Paper	241
Line of Credit Facility, Maximum Borrowing Capacity	3,250
Bakken Pipeline [Member] \| Bakken Term Note [Member]
Line of Credit Facility, Maximum Borrowing Capacity	2,500
PennTex $275 million Revolving Credit Facility due December 2019 [Member] \| PennTex [Member]
Line of Credit Facility, Current Borrowing Capacity	275
Long-term Line of Credit	148
Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] \| Sunoco Logistics [Member]
Line of Credit Facility, Current Borrowing Capacity			$ 1,000
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] \| Bakken Project [Member]
Long-term Line of Credit	$ 2,500

Series A Preferred Units (Details) - USD ($) shares in Millions, $ in Millions	1 Months Ended	6 Months Ended
	Jan. 31, 2017	Jun. 30, 2017	Jun. 30, 2016
Payments for Repurchase of Preferred Stock and Preference Stock	$ 53	$ 53	$ 0
ETP Series A Preferred Units [Member]
Partners' Capital Account, Units, Redeemed	1.9

Equity Narrative (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended		3 Months Ended			6 Months Ended
	Feb. 28, 2017	Jan. 31, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Jun. 30, 2017	Jun. 30, 2016
Proceeds from Sale of Equity Method Investments						$ 0	$ 2,200
Common units issued in connection with the distribution reinvestment plan						2.8
Net gains from subsidiary common unit issuances						$ 0	14
Proceeds from Issuance of Common Limited Partners Units						990	$ 408
Noncontrolling Interest, Increase from Sale of Parent Equity Interest						2,000
Sunoco Logistics [Member]
Rate					$ 0.52
Post-Merger ETP [Member]
Rate			$ 0.5500	$ 0.5350
Distribution Made to Limited Partner, Distribution Date			Aug. 14, 2017	May 15, 2017
Distribution Made to Limited Partner, Date of Record			Aug. 07, 2017	May 10, 2017
ETP [Member]
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units			$ 1,000
Rate					$ 0.7033
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement						358
Stock Issued During Period, Value, Dividend Reinvestment Plan						$ 71
Partners' Capital Account, Units, Sold in Private Placement		23.7
PennTex [Member]
Sale of Stock, Price Per Share			$ 20.00			$ 20.00
Equity Distribution Agreement [Member] \| ETP [Member]
Fees and Commissions						$ 4
Second Target Distribution [Member]
Distribution Payment Targets			0.0833			above $0.0833 up to $0.0958
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross	$ 2,000
Sunoco Logistics [Member] \| ETP [Member]
Distribution Made to Limited Partner, Distribution Date					Feb. 14, 2017
Sunoco Logistics [Member] \| Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
Dakota Access and ETCOC [Member] \| Bakken Pipeline Investments LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	75.00%
Dakota Access and ETCOC [Member] \| Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	25.00%
Bakken Pipeline [Member] \| Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	25.00%
Bakken Pipeline [Member] \| ETP and Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	38.25%
Bakken Pipeline [Member] \| MarEn Bakken Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	36.75%
IDRs [Member] \| Second Target Distribution [Member]
Marginal Percentage Interest in Distributions			13.00%			13.00%
IDRs [Member] \| Maximum [Member]
Marginal Percentage Interest in Distributions			50.00%			50.00%

Equity Common Unit Activity (Details) - shares
shares in Millions

1 Months Ended

6 Months Ended

Jan. 31, 2017

Jun. 30, 2017

Number of common units at December 31, 2016 (1)

^[1]

794.8

Common units issued in connection with equity distribution agreements

15.6

Common units issued in connection with the distribution reinvestment plan

2.8

Number of common units at June 30, 2017

1,092.6

Partners' Capital Account, Units, Unit-based Compensation

0.3

ETP [Member]

Partners' Capital Account, Units, Sold in Private Placement

23.7

ETP [Member] | Bakken Pipeline Transaction [Member]

Stock Redeemed or Called During Period, Shares

^[2]

(255.4)

[1]	The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
[2]	Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger.

Equity Distribution Targets (Details)

3 Months Ended

6 Months Ended

Jun. 30, 2017

Minimum Quarterly Distribution [Member]

Distribution Payment Targets

0.0750

First Target Distribution [Member]

Distribution Payment Targets

up to $0.0833

Second Target Distribution [Member]

Distribution Payment Targets

0.0833

above $0.0833 up to $0.0958

Third Target Distribution [Member]

Distribution Payment Targets

above $0.0958 up to $0.2638

Thereafter [Member]

Distribution Payment Targets

above $0.2638

IDRs [Member] | Minimum Quarterly Distribution [Member]

Marginal Percentage Interest in Distributions

0.00%

IDRs [Member] | First Target Distribution [Member]

Marginal Percentage Interest in Distributions

0.00%

IDRs [Member] | Second Target Distribution [Member]

Marginal Percentage Interest in Distributions

13.00%

IDRs [Member] | Third Target Distribution [Member]

Marginal Percentage Interest in Distributions

35.00%

IDRs [Member] | Thereafter [Member]

Marginal Percentage Interest in Distributions

48.00%

Limited Partners | Minimum Quarterly Distribution [Member]

Marginal Percentage Interest in Distributions

100.00%

^[1]

100.00%

^[1]

Limited Partners | First Target Distribution [Member]

Marginal Percentage Interest in Distributions

100.00%

^[1]

100.00%

^[1]

Limited Partners | Second Target Distribution [Member]

Marginal Percentage Interest in Distributions

87.00%

^[1]

87.00%

^[1]

Limited Partners | Third Target Distribution [Member]

Marginal Percentage Interest in Distributions

65.00%

^[1]

65.00%

^[1]

Limited Partners | Thereafter [Member]

Marginal Percentage Interest in Distributions

52.00%

^[1]

52.00%

^[1]

[1]	(1) Includes general partner and limited partner interests, based on the proportionate ownership of each.

Equity Quarterly Distributions Of Available Cash (Details) - $ / shares	3 Months Ended
	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016
Post-Merger ETP [Member]
Distribution Made to Member or Limited Partner [Line Items]
Record Date	Aug. 07, 2017	May 10, 2017
Payment Date	Aug. 14, 2017	May 15, 2017
Rate	$ 0.5500	$ 0.5350
ETP [Member]
Distribution Made to Member or Limited Partner [Line Items]
Rate			$ 0.7033
Sunoco Logistics [Member]
Distribution Made to Member or Limited Partner [Line Items]
Rate			$ 0.52

Equity Net IDR Schedule (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
Equity Net IDR Schedule (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Currently Effective IDRs [Member] \| ETE \| Subsequent Event [Member]
Relinquishment of Incentive Distributions	$ 336	$ 33	$ 128	$ 153

Equity AOCI (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
Equity AOCI (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 5	$ 2
Foreign currency translation adjustment	(5)	(5)
Actuarial gain related to pensions and other postretirement benefits	4	7
Investments in unconsolidated affiliates, net	3	4
Total AOCI, net of tax	$ 7	$ 8

Income Taxes (Details) $ in Millions	6 Months Ended
Income Taxes (Details) $ in Millions	Jun. 30, 2017 USD ($)
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	$ 77

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)	1 Months Ended			3 Months Ended		6 Months Ended		12 Months Ended
	May 31, 2017 USD ($)	Apr. 30, 2015 USD ($)	Jan. 31, 2012 USD ($)	Jun. 30, 2017 USD ($) sites	Jun. 30, 2016 USD ($)	Jun. 30, 2017 USD ($) sites	Jun. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2016 USD ($)
Maximum lease expiration year						Dec. 31, 2034
Loss contingency accrual, at carrying value				$ 71,000,000		$ 71,000,000			$ 77,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed				0		0
Accrual for Environmental Loss Contingencies				$ 314,000,000		$ 314,000,000			$ 309,000,000
Sites where remediation operations are responsibility of third parties \| sites				9		9
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
AmeriGas [Member]
Contingent Residual Support Agreement, Amount			$ 1,550,000,000
Debt Instrument, Interest Rate, Stated Percentage				7.00%		7.00%
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				6		6
Payments for Environmental Liabilities				$ 8,000,000	$ 8,000,000	$ 10,000,000	$ 14,000,000
Proposed Environmental Penalty				$ 200,000		$ 200,000
Sunoco, Inc. [Member] \| Multidistrict Legislation [Member]
Loss Contingency, Pending Claims, Number				4		4
BP Products North America [Member]
Loss Contingency, Damages Awarded, Value	$ 13,000,000	$ 62,000,000						$ 41,000,000
Sunoco [Member]
Sites where remediation operations are responsibility of third parties				49		49
Sunoco Logistics [Member]
Proposed Environmental Penalty				$ 100,000		$ 100,000
Rover Pipeline LLC [Member]
Sites where remediation operations are responsibility of third parties				27		27
Proposed Environmental Penalty				$ 900,000		$ 900,000
Federal [Member] \| Sunoco Pipeline L.P. [Member]
Proposed Environmental Penalty				7,000,000		7,000,000
State and Local Jurisdiction [Member] \| Sunoco Pipeline L.P. [Member]
Proposed Environmental Penalty				$ 1,000,000		$ 1,000,000

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Operating Leases, Rental Expense (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Rental expense	$ 19	$ 21	$ 39	$ 39

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Environmental Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Environmental Exit Cost [Line Items]
Current	$ 38	$ 26
Non-current	276	283
Total environmental liabilities	$ 314	$ 309

Derivative Assets And Liabilities Outstanding Interest Rate Derivatives (Details) - USD ($)
$ in Millions

6 Months Ended

Jun. 30, 2017

Dec. 31, 2016

July 2017 [Member]

Notional Amount

^[1]

$ 0

$ 500

Type

^[1],[2]

Forward-starting to pay a fixed rate of 3.90% and receive a floating rate

July 2018 [Member]

Notional Amount

^[1]

$ 300

200

Type

^[1],[2]

Forward-starting to pay a fixed rate of 3.76% and receive a floating rate

December 2018 [Member]

Notional Amount

$ 1,200

1,200

Type

^[2]

Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%

July 2019 [Member]

Notional Amount

^[1]

$ 300

200

Type

^[1],[2]

Forward-starting to pay a fixed rate of 3.64% and receive a floating rate

July 2020 [Member]

Notional Amount

^[1]

$ 400

Type

^[1],[2]

Forward-starting to pay a fixed rate of 3.52% and receive a floating rate

March 2019 [Member]

Notional Amount

$ 300

Type

^[2]

Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%

[1]	Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
[2]	Floating rates are based on 3-month LIBOR.

Derivative Assets And Liabilities Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Total derivatives assets	$ 154	$ 362
Total derivatives liabilities	(329)	(666)
Designated as Hedging Instrument [Member] \| Commodity derivatives (margin deposits)
Total derivatives assets	8	0
Total derivatives liabilities	(1)	(4)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	146	362
Total derivatives liabilities	(328)	(662)
Not Designated as Hedging Instrument [Member] \| Commodity derivatives (margin deposits)
Total derivatives assets	127	338
Total derivatives liabilities	(109)	(416)
Not Designated as Hedging Instrument [Member] \| Commodity derivatives
Total derivatives assets	19	24
Total derivatives liabilities	(18)	(52)
Not Designated as Hedging Instrument [Member] \| Interest rate derivatives
Total derivatives assets	0	0
Total derivatives liabilities	(201)	(193)
Embedded Derivatives in Preferred Units [Member] \| Not Designated as Hedging Instrument [Member]
Total derivatives assets	0	0
Total derivatives liabilities	$ 0	$ (1)

Derivative Assets And Liabilities Fair Value of Derivatives, Netting Basis (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 154	$ 362
Derivative Liability, Fair Value, Gross Liability	(329)	(666)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(11)	(4)
Derivative Liability, Fair Value, Amount Offset Against Collateral	11	4
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(110)	(338)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	110	338
Derivative Asset, Fair Value, Net	33	20
Derivative Liability, Fair Value, Net	(208)	(324)
Without offsetting agreements [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(201)	(194)
OTC Contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	19	24
Derivative Liability, Fair Value, Gross Liability	(18)	(52)
Broker cleared derivative contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	135	338
Derivative Liability, Fair Value, Gross Liability	$ (110)	$ (420)

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, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Commodity derivatives	$ 6	$ 21	$ 2	$ 17
Commodity Derivatives [Member]
Commodity derivatives	$ 6	$ 21	$ 2	$ 17

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, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	$ 6	$ 21	$ 2	$ 17
Amount of Gain/(Loss) Recognized in Income on Derivatives	(3)	(140)	4	(214)
Losses on interest rate derivatives	(25)	(81)	(20)	(151)
Commodity Derivatives - Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	15	(7)	26	(16)
Commodity derivatives
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	6	21	2	17
Amount of Gain/(Loss) Recognized in Income on Derivatives	7	(48)	(3)	(43)
Other Income (Expenses) [Member] \| Embedded Derivatives in Preferred Units [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 0	$ (4)	$ 1	$ (4)

Related Party Transactions Affiliated Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Related Party Transactions [Abstract]
Affiliated revenues	$ 133	$ 133	$ 251	$ 207

Related Party Transactions Related Party A/R and A/P (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Total accounts receivable from related companies:	$ 364	$ 209
Total accounts payable to related companies:	200	43
Long-term notes payable – related companies	0	(250)
Net Related Party Receivable (Payable)	87	(163)
ETE
Total accounts receivable from related companies:	0	22
Sunoco LP
Notes Receivable, Related Parties, Noncurrent	87	87
Total accounts receivable from related companies:	179	96
Total accounts payable to related companies:	177	20
PES
Total accounts receivable from related companies:	8	6
FGT
Total accounts receivable from related companies:	9	15
Total accounts payable to related companies:	0	1
Lake Charles LNG
Total accounts receivable from related companies:	1	4
Total accounts payable to related companies:	2	3
Trans-Pecos Pipeline, LLC
Total accounts receivable from related companies:	4	1
Comanche Trail Pipeline, LLC [Member]
Total accounts receivable from related companies:	1	0
Traverse Rover LLC [Member]
Total accounts receivable from related companies:	100	0
Other
Total accounts receivable from related companies:	62	65
Total accounts payable to related companies:	21	19
Phillips 66 Partners LP [Member]
Long-term notes payable – related companies	$ 0	$ (250)

Reportable Segments Segment Revenues (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Segment Reporting Information [Line Items]
Revenues	$ 6,576	$ 5,289	$ 13,471	$ 9,770
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Revenues	753	541	1,569	1,099
Intrastate transportation and storage \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	699	428	1,467	874
Intrastate transportation and storage \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	54	113	102	225
Interstate transportation and storage
Segment Reporting Information [Line Items]
Revenues	207	234	442	493
Interstate transportation and storage \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	201	229	432	483
Interstate transportation and storage \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	6	5	10	10
Midstream
Segment Reporting Information [Line Items]
Revenues	1,615	1,330	3,252	2,422
Midstream \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	633	690	1,198	1,217
Midstream \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	982	640	2,054	1,205
NGL and refined products transportation and services
Segment Reporting Information [Line Items]
Revenues	1,768	1,487	4,045	2,820
NGL and refined products transportation and services \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	1,767	1,445	3,885	2,617
NGL and refined products transportation and services \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	1	42	160	203
Crude oil transportation and services
Segment Reporting Information [Line Items]
Revenues	2,586	1,989	5,275	3,454
Crude oil transportation and services \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	2,460	1,904	5,035	3,290
Crude oil transportation and services \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	126	85	240	164
All other
Segment Reporting Information [Line Items]
Revenues	870	711	1,640	1,565
All other \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	816	593	1,454	1,289
All other \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	54	118	186	276
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (1,223)	$ (1,003)	$ (2,752)	$ (2,083)

Reportable Segments Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 1,599	$ 1,370	$ 3,013	$ 2,782
Depreciation, depletion and amortization	(557)	(496)	(1,117)	(966)
Interest expense, net	(346)	(317)	(685)	(636)
Losses on interest rate derivatives	(25)	(81)	(20)	(151)
Non-cash unit-based compensation expense	(15)	(19)	(38)	(38)
Unrealized gains (losses) on commodity risk management activities	34	(18)	98	(81)
Inventory valuation adjustments	(58)	132	(56)	106
Adjusted EBITDA related to unconsolidated affiliates	(247)	(252)	(486)	(471)
Equity in earnings (losses) of unconsolidated affiliates	(61)	119	12	195
Other, net	47	25	69	41
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	371	463	790	781
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	148	149	317	328
Interstate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	262	278	527	570
Midstream
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	412	298	732	561
NGL and refined products transportation and services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	391	341	773	689
Crude oil transportation and services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	279	124	434	352
All other
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 107	$ 180	$ 230	$ 282

Reportable Segments Segment Assets (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Assets	$ 74,219	$ 70,191
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Assets	7,129	5,164
Interstate transportation and storage
Segment Reporting Information [Line Items]
Assets	12,153	10,833
Midstream
Segment Reporting Information [Line Items]
Assets	17,240	17,873
NGL and refined products transportation and services
Segment Reporting Information [Line Items]
Assets	16,407	14,128
Crude oil transportation and services
Segment Reporting Information [Line Items]
Assets	16,137	15,941
All other
Segment Reporting Information [Line Items]
Assets	$ 5,153	$ 6,252

Reportable Segments Reportable Segments Narrative (Details) - Sunoco LP shares in Millions	Jun. 30, 2017 shares
Investments in and Advances to Affiliates, Balance, Shares	43.5
Equity Method Investment, Ownership Percentage	43.70%

Guarantor Financial Information Balance Sheet (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015
Cash and Cash Equivalents, at Carrying Value	$ 272	$ 360	$ 386	$ 527
Other current assets	160	298
Property, Plant and Equipment, Net	54,536	50,917
Advances to and investments in unconsolidated affiliates	4,228	4,280
Other Assets, Noncurrent	707	672
Assets	74,219	70,191
Liabilities, Current	6,989	6,203
Other non-current liabilities	1,066	952
Noncontrolling interest	3,799	7,885
Partners' Capital	25,616	18,642
Liabilities and Equity	74,219	70,191
Pro Forma [Member]
Cash and Cash Equivalents, at Carrying Value	272	360	386	527
Other current assets	5,114	5,369
Property, Plant and Equipment, Net	54,536	50,917
Advances to and investments in unconsolidated affiliates	4,228	4,280
Other Assets, Noncurrent	10,069	9,265
Assets	74,219	70,191
Liabilities, Current	6,989	6,203
Liabilities, Noncurrent	37,815	37,461
Noncontrolling interest	3,799	1,297
Partners' Capital	25,616	25,230
Liabilities and Equity	74,219	70,191
Pro Forma [Member] \| Parent Guarantor [Member]
Cash and Cash Equivalents, at Carrying Value	0	0	0	0
Other current assets	0	0
Property, Plant and Equipment, Net	0	0
Advances to and investments in unconsolidated affiliates	24,154	23,350
Other Assets, Noncurrent	0	0
Assets	24,154	23,350
Liabilities, Current	(1,491)	(1,761)
Liabilities, Noncurrent	0	299
Noncontrolling interest	0	0
Partners' Capital	25,645	24,812
Liabilities and Equity	24,154	23,350
Pro Forma [Member] \| Subsidiary Issuer [Member]
Cash and Cash Equivalents, at Carrying Value	23	41	36	37
Other current assets	0	2
Property, Plant and Equipment, Net	0	0
Advances to and investments in unconsolidated affiliates	11,502	10,664
Other Assets, Noncurrent	4	5
Assets	11,529	10,712
Liabilities, Current	(3,421)	(3,800)
Liabilities, Noncurrent	7,062	7,313
Noncontrolling interest	0	0
Partners' Capital	7,888	7,199
Liabilities and Equity	11,529	10,712
Pro Forma [Member] \| Non-Guarantor Subsidiaries [Member]
Cash and Cash Equivalents, at Carrying Value	249	319	350	490
Other current assets	5,114	5,367
Property, Plant and Equipment, Net	54,536	50,917
Advances to and investments in unconsolidated affiliates	4,228	4,280
Other Assets, Noncurrent	10,065	9,260
Assets	74,192	70,143
Liabilities, Current	11,901	11,764
Liabilities, Noncurrent	30,753	30,148
Noncontrolling interest	3,799	1,297
Partners' Capital	27,739	26,934
Liabilities and Equity	74,192	70,143
Pro Forma [Member] \| Adjustments and eliminations
Cash and Cash Equivalents, at Carrying Value	0	0	$ 0	$ 0
Other current assets	0	0
Property, Plant and Equipment, Net	0	0
Advances to and investments in unconsolidated affiliates	(35,656)	(34,014)
Other Assets, Noncurrent	0	0
Assets	(35,656)	(34,014)
Liabilities, Current	0	0
Liabilities, Noncurrent	0	(299)
Noncontrolling interest	0	0
Partners' Capital	(35,656)	(33,715)
Liabilities and Equity	$ (35,656)	$ (34,014)

Guarantor Financial Information Statements of Operations (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Revenues	$ 6,576	$ 5,289	$ 13,471	$ 9,770
Costs and Expenses	5,844	4,574	12,085	8,441
OPERATING INCOME	732	715	1,386	1,329
Interest Expense	(346)	(317)	(685)	(636)
Equity in earnings (losses) of unconsolidated affiliates	(61)	119	12	195
Losses on interest rate derivatives	(25)	(81)	(20)	(151)
Other Nonoperating Income (Expense)	71	27	97	44
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	371	463	790	781
Income tax expense (benefit)	79	(9)	134	(67)
Net income	292	472	656	848
Less: Net income attributable to noncontrolling interest	93	102	133	167
Net Income (Loss) Attributable to Parent	199	370	523	681
Other Comprehensive Income (Loss), Net of Tax	(1)	4	(1)	(10)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	291	476	655	838
Less: Comprehensive income attributable to noncontrolling interest	93	102	133	167
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	198	374	522	671
Pro Forma [Member]
Revenues	6,576	5,289	13,471	9,770
Costs and Expenses	5,844	4,574	12,085	8,441
OPERATING INCOME	732	715	1,386	1,329
Interest Expense	(346)	(317)	(685)	(636)
Equity in earnings (losses) of unconsolidated affiliates	(61)	119	12	195
Losses on interest rate derivatives	(25)	(81)	(20)	(151)
Other Nonoperating Income (Expense)	71	27	97	44
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	371	463	790	781
Income tax expense (benefit)	79	(9)	134	(67)
Net income	292	472	656	848
Less: Net income attributable to noncontrolling interest	93	0	133	36
Net Income (Loss) Attributable to Parent	199	472	523	812
Other Comprehensive Income (Loss), Net of Tax	(1)	4	(1)	(10)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	291	476	655	838
Less: Comprehensive income attributable to noncontrolling interest	93	18	133	36
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	198	458	522	802
Pro Forma [Member] \| Parent Guarantor [Member]
Revenues	0	0	0	0
Costs and Expenses	0	0	0	0
OPERATING INCOME	0	0	0	0
Interest Expense	0	0	0	0
Equity in earnings (losses) of unconsolidated affiliates	199	451	1,010	811
Losses on interest rate derivatives	0	0	0	0
Other Nonoperating Income (Expense)	0	0	0	0
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	199	451	1,010	811
Income tax expense (benefit)	0	0	0	0
Net income	199	451	1,010	811
Less: Net income attributable to noncontrolling interest	0	0	0	0
Net Income (Loss) Attributable to Parent	199	451	1,010	811
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	199	451	1,010	811
Less: Comprehensive income attributable to noncontrolling interest	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	199	451	1,010	811
Pro Forma [Member] \| Subsidiary Issuer [Member]
Revenues	0	0	0	0
Costs and Expenses	1	1	1	1
OPERATING INCOME	(1)	(1)	(1)	(1)
Interest Expense	(39)	(39)	(81)	(77)
Equity in earnings (losses) of unconsolidated affiliates	137	242	765	425
Losses on interest rate derivatives	0	0	0	0
Other Nonoperating Income (Expense)	3	0	3	0
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	100	202	686	347
Income tax expense (benefit)	0	0	0	0
Net income	100	202	686	347
Less: Net income attributable to noncontrolling interest	0	0	0	0
Net Income (Loss) Attributable to Parent	100	202	686	347
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	100	202	686	347
Less: Comprehensive income attributable to noncontrolling interest	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	100	202	686	347
Pro Forma [Member] \| Non-Guarantor Subsidiaries [Member]
Revenues	6,576	5,289	13,471	9,770
Costs and Expenses	5,843	4,573	12,084	8,440
OPERATING INCOME	733	716	1,387	1,330
Interest Expense	(307)	(278)	(604)	(559)
Equity in earnings (losses) of unconsolidated affiliates	(61)	119	12	195
Losses on interest rate derivatives	(25)	(81)	(20)	(151)
Other Nonoperating Income (Expense)	69	27	95	44
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	409	503	870	859
Income tax expense (benefit)	79	(9)	134	(67)
Net income	330	512	736	926
Less: Net income attributable to noncontrolling interest	93	18	133	36
Net Income (Loss) Attributable to Parent	237	494	603	890
Other Comprehensive Income (Loss), Net of Tax	(1)	4	(1)	(10)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	329	516	735	916
Less: Comprehensive income attributable to noncontrolling interest	93	18	133	36
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	236	498	602	880
Pro Forma [Member] \| Adjustments and eliminations
Revenues	0	0	0	0
Costs and Expenses	0	0	0	0
OPERATING INCOME	0	0	0	0
Interest Expense	0	0	0	0
Equity in earnings (losses) of unconsolidated affiliates	(336)	(693)	(1,775)	(1,236)
Losses on interest rate derivatives	0	0	0	0
Other Nonoperating Income (Expense)	(1)	0	(1)	0
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	(337)	(693)	(1,776)	(1,236)
Income tax expense (benefit)	0	0	0	0
Net income	(337)	(693)	(1,776)	(1,236)
Less: Net income attributable to noncontrolling interest	0	0	0	0
Net Income (Loss) Attributable to Parent	(337)	(693)	(1,776)	(1,236)
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(337)	(693)	(1,776)	(1,236)
Less: Comprehensive income attributable to noncontrolling interest	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (337)	$ (693)	$ (1,776)	$ (1,236)

Guarantor Financial Information Cash Flows (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
Net Cash Provided by (Used in) Operating Activities	$ 1,650	$ 1,426
Net Cash Provided by (Used in) Investing Activities	(1,486)	(1,225)
Net Cash Provided by (Used in) Financing Activities	(252)	(342)
Cash and Cash Equivalents, Period Increase (Decrease)	(88)	(141)
Cash and Cash Equivalents, at Carrying Value	272	386	$ 360	$ 527
Pro Forma [Member]
Net Cash Provided by (Used in) Operating Activities	1,650	1,426
Net Cash Provided by (Used in) Investing Activities	(1,486)	(1,225)
Net Cash Provided by (Used in) Financing Activities	(252)	(342)
Cash and Cash Equivalents, Period Increase (Decrease)	(88)	(141)
Cash and Cash Equivalents, at Carrying Value	272	386	360	527
Pro Forma [Member] \| Parent Guarantor [Member]
Net Cash Provided by (Used in) Operating Activities	1,010	811
Net Cash Provided by (Used in) Investing Activities	(716)	(1,029)
Net Cash Provided by (Used in) Financing Activities	(294)	218
Cash and Cash Equivalents, Period Increase (Decrease)	0	0
Cash and Cash Equivalents, at Carrying Value	0	0	0	0
Pro Forma [Member] \| Subsidiary Issuer [Member]
Net Cash Provided by (Used in) Operating Activities	652	320
Net Cash Provided by (Used in) Investing Activities	(421)	(847)
Net Cash Provided by (Used in) Financing Activities	(249)	526
Cash and Cash Equivalents, Period Increase (Decrease)	(18)	(1)
Cash and Cash Equivalents, at Carrying Value	23	36	41	37
Pro Forma [Member] \| Non-Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities	1,764	1,531
Net Cash Provided by (Used in) Investing Activities	(2,125)	(585)
Net Cash Provided by (Used in) Financing Activities	291	(1,086)
Cash and Cash Equivalents, Period Increase (Decrease)	(70)	(140)
Cash and Cash Equivalents, at Carrying Value	249	350	319	490
Pro Forma [Member] \| Adjustments and eliminations
Net Cash Provided by (Used in) Operating Activities	(1,776)	(1,236)
Net Cash Provided by (Used in) Investing Activities	1,776	1,236
Net Cash Provided by (Used in) Financing Activities	0	0
Cash and Cash Equivalents, Period Increase (Decrease)	0	0
Cash and Cash Equivalents, at Carrying Value	$ 0	$ 0	$ 0	$ 0

Fair Value Measurements Fair Value Heigharchy (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Derivative Liability, Fair Value, Gross Liability	$ (329)	$ (666)
Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	154	362
Assets, Fair Value Disclosure, Recurring	154	362
Interest rate derivatives, Liabilities	(201)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		(1)
Price Risk Derivative Liabilities, at Fair Value	(128)	(472)
Liabilities, Fair Value Disclosure, Recurring	(329)	(666)
Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	135	355
Assets, Fair Value Disclosure, Recurring	135	355
Interest rate derivatives, Liabilities	0	0
Embedded Derivative, Fair Value of Embedded Derivative Liability		0
Price Risk Derivative Liabilities, at Fair Value	(113)	(464)
Liabilities, Fair Value Disclosure, Recurring	(113)	(464)
Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	19	7
Assets, Fair Value Disclosure, Recurring	19	7
Interest rate derivatives, Liabilities	(201)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		0
Price Risk Derivative Liabilities, at Fair Value	(15)	(8)
Liabilities, Fair Value Disclosure, Recurring	(216)	(201)
Fair Value, Measurements, Recurring [Member] \| Level 3
Price Risk Derivative Assets, at Fair Value		0
Assets, Fair Value Disclosure, Recurring		0
Interest rate derivatives, Liabilities		0
Embedded Derivative, Fair Value of Embedded Derivative Liability		(1)
Price Risk Derivative Liabilities, at Fair Value		0
Liabilities, Fair Value Disclosure, Recurring		(1)
Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC/NYMEX [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	9	14
Price Risk Derivative Liabilities, at Fair Value	(9)	(11)
Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC/NYMEX [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	9	14
Price Risk Derivative Liabilities, at Fair Value	(9)	(11)
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
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	3	2
Price Risk Derivative Liabilities, at Fair Value	(2)	(3)
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	1	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	2	2
Price Risk Derivative Liabilities, at Fair Value	(2)	(3)
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [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 - Natural Gas [Member] \| Fixed Swaps/Futures [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	38	96
Price Risk Derivative Liabilities, at Fair Value	(25)	(149)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	38	96
Price Risk Derivative Liabilities, at Fair Value	(25)	(149)
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
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Swaps [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	4	1
Price Risk Derivative Liabilities, at Fair Value	(1)
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	1
Price Risk Derivative Liabilities, at Fair Value	(1)
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Swaps [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 3
Price Risk Derivative Assets, at Fair Value		0
Commodity Derivatives - Power [Member] \| Forward Swaps [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	13	4
Price Risk Derivative Liabilities, at Fair Value	(12)	(5)
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	13	4
Price Risk Derivative Liabilities, at Fair Value	(12)	(5)
Commodity Derivatives - Power [Member] \| Forward Swaps [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 - Power [Member] \| Options - Calls [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Commodity Derivatives - Power [Member] \| Options - Calls [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value		1
Commodity Derivatives - Power [Member] \| Options - Calls [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value		0
Commodity Derivatives - Power [Member] \| Options - Calls [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 3
Price Risk Derivative Assets, at Fair Value		0
Commodity Derivatives - Power [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	1
Price Risk Derivative Liabilities, at Fair Value	(1)	(1)
Commodity Derivatives - Power [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	1	1
Price Risk Derivative Liabilities, at Fair Value	(1)	(1)
Commodity Derivatives - Power [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 - 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
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	77	233
Price Risk Derivative Liabilities, at Fair Value	(70)	(273)
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	77	233
Price Risk Derivative Liabilities, at Fair Value	(70)	(273)
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
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Refined Products [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value	(3)	(17)
Commodity Derivatives - Refined Products [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value	(3)	(17)
Commodity Derivatives - Refined Products [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 - Refined Products [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
Commodity Derivatives - Crude [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	9	9
Price Risk Derivative Liabilities, at Fair Value	(5)	(13)
Commodity Derivatives - Crude [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	9	9
Price Risk Derivative Liabilities, at Fair Value	(5)	(13)
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
Price Risk Derivative Liabilities, at Fair Value		$ 0