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Document And Entity Information - shares	9 Months Ended
Document And Entity Information - shares	Sep. 30, 2017	Nov. 03, 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		1,155,493,524
Document Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 379	$ 360
Accounts receivable, net	3,083	3,002
Accounts receivable from related companies	335	209
Inventories	1,591	1,712
Income Taxes Receivable, Current	151	128
Derivative assets	40	20
Other current assets	201	298
Total current assets	5,780	5,729
Property, plant and equipment	65,735	58,220
Accumulated depreciation and depletion	(8,763)	(7,303)
Property, plant and equipment, net	56,972	50,917
Advances to and investments in unconsolidated affiliates	4,221	4,280
Other non-current assets, net	752	672
Intangible assets, net	5,379	4,696
Goodwill	3,907	3,897
Total assets	77,011	70,191
Current liabilities:
Accounts payable	3,410	2,900
Accounts payable to related companies	204	43
Derivative liabilities	128	166
Accrued and other current liabilities	2,434	1,905
Current maturities of long-term debt	710	1,189
Total current liabilities	6,886	6,203
Long-term debt, less current maturities	33,630	31,741
Long-term notes payable – related company	0	250
Non-current derivative liabilities	132	76
Deferred income taxes	4,374	4,394
Other non-current liabilities	1,111	952
Commitments and contingencies
Preferred Units	0	33
Redeemable noncontrolling interests	21	15
Equity:
General Partner	252	206
Limited Partners:
Common Unitholders	26,400	14,946
Class H Unitholder	0	3,480
Class I Unitholder	0	2
Accumulated other comprehensive income	14	8
Total partners’ capital	26,666	18,642
Noncontrolling interest	4,191	7,885
Total equity	30,857	26,527
Total liabilities and equity	$ 77,011	$ 70,191

Consolidated Statements Of Operations - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
REVENUES:
Natural gas sales	$ 1,098	$ 1,069	$ 3,132	$ 2,602
NGL sales	1,750	1,249	4,782	3,339
Crude sales	2,273	1,649	6,751	4,572
Gathering, transportation and other fees	1,027	986	3,118	2,991
Refined product sales	334	177	1,109	656
Other	491	401	1,552	1,141
Total revenues	6,973	5,531	20,444	15,301
COSTS AND EXPENSES:
Cost of products sold	4,876	3,844	14,582	10,280
Operating expenses	571	475	1,603	1,359
Depreciation, depletion and amortization	596	503	1,713	1,469
Selling, general and administrative	105	71	335	226
Total costs and expenses	6,148	4,893	18,233	13,334
OPERATING INCOME	825	638	2,211	1,967
OTHER INCOME (EXPENSE):
Interest expense, net	(367)	(345)	(1,052)	(981)
Equity in earnings of unconsolidated affiliates	127	65	139	260
Equity Method Investment, Other than Temporary Impairment	0	(308)	0	(308)
Losses on interest rate derivatives	(8)	(28)	(28)	(179)
Other, net	72	52	169	96
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	649	74	1,439	855
Income tax expense (benefit)	(112)	(64)	22	(131)
NET INCOME	761	138	1,417	986
Less: Net income attributable to noncontrolling interest	110	64	243	231
NET INCOME ATTRIBUTABLE TO PARTNERS	651	74	1,174	755
General Partner’s interest in net income	270	220	727	740
Class H Unitholder’s interest in net income	0	93	98	257
Class I Unitholder’s interest in net income	0	2	0	6
Common Unitholders’ interest in net income (loss)	$ 381	$ (241)	$ 349	$ (248)
NET INCOME (LOSS) PER COMMON UNIT:
Basic	$ 0.33	$ (0.33)	$ 0.35	$ (0.36)
Diluted	$ 0.33	$ (0.33)	$ 0.34	$ (0.36)

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 761	$ 138	$ 1,417	$ 986
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	2	0	5	5
Actuarial gain (loss) relating to pension and other postretirement benefit plans	5	0	2	(3)
Foreign currency translation adjustments	0	0	0	(1)
Change in other comprehensive income from unconsolidated affiliates	0	2	(1)	(9)
Total other comprehensive income (loss)	7	2	6	(8)
Comprehensive income	768	140	1,423	978
Less: Comprehensive income attributable to noncontrolling interest	110	64	243	231
Comprehensive income attributable to partners	$ 658	$ 76	$ 1,180	$ 747

Consolidated Statement Of Equity - 9 months ended Sep. 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	2,543	681	1,765	95	2	0	0
Distributions to noncontrolling interest	(306)	0	0	0	0	0	(306)
Units issued for cash	2,162	0	2,162	0	0	0	0
Partners' Capital Account, Acquisitions	0	0	9,459	(3,483)	0	0	(5,976)
Capital contributions from noncontrolling interest	1,907	0	0	0	0	0	1,907
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	6	0	0	0	0	6	0
Other, net	(33)	0	37	0	0	0	(70)
Net income	1,417	727	349	98	0	0	243
Balance, September 30, 2017 at Sep. 30, 2017	$ 30,857	$ 252	$ 26,400	$ 0	$ 0	$ 14	$ 4,191

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Statement of Cash Flows [Abstract]
Equity Method Investment, Other than Temporary Impairment	$ 0	$ 308
OPERATING ACTIVITIES
Net income	1,417	986
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,713	1,469
Deferred income taxes	(1)	(154)
Amortization included in interest expense	5	(16)
Inventory valuation adjustments	(30)	(143)
Unit-based compensation expense	57	60
Distributions on unvested awards	(21)	(19)
Equity in earnings of unconsolidated affiliates	(139)	(260)
Distributions from unconsolidated affiliates	319	292
Other non-cash	(168)	(230)
Net change in operating assets and liabilities, net of effects of acquisition	185	172
Net cash provided by operating activities	3,337	2,465
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	264	159
Capital expenditures, excluding allowance for equity funds used during construction	(6,074)	(5,787)
Contributions in aid of construction costs	18	44
Contributions to unconsolidated affiliates	(230)	(47)
Distributions from unconsolidated affiliates in excess of cumulative earnings	116	112
Proceeds from the sale of assets	33	6
Change in restricted cash	0	(8)
Other	(6)	(1)
Net cash used in investing activities	(4,687)	(3,640)
FINANCING ACTIVITIES
Proceeds from borrowings	19,978	13,073
Repayments of long-term debt	(18,487)	(11,308)
Proceeds from (Repayments of) Related Party Debt	(255)	(1)
Units issued for cash	2,162	794
Subsidiary units issued for cash	0	1,305
Capital contributions from noncontrolling interest	919	187
Distributions to partners	(2,543)	(2,669)
Distributions to noncontrolling interest	(306)	(334)
Payments for Repurchase of Preferred Stock and Preference Stock	53	0
Debt issuance costs	50	22
Proceeds from (Payments for) Other Financing Activities	4	0
Net cash provided by financing activities	1,369	1,025
Increase (decrease) in cash and cash equivalents	19	(150)
Cash and cash equivalents, beginning of period	360	527
Cash and cash equivalents, end of period	$ 379	$ 377

Operations And Organization

9 Months Ended

Sep. 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 99.1 to the Partnership’s Current Report on Form 8-K filed on August 14, 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.

For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.

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

ASU 2014-09

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method, which requires recognition, upon the date of initial application, of the cumulative effect of the retrospective application of the standard.

We are continuing the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standard. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts (as discussed below) 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.

We currently anticipate a change to revenues and costs associated with the accounting for noncash consideration in multiple of our reportable segments as well as the accounting for certain processing contracts in our midstream segment. We do not expect these changes in the accounting for noncash consideration or processing contracts to impact net income.

We are still evaluating the potential impact of the adoption of ASU 2014-09 to contributions in aid of construction costs (“CIAC”) arrangements and materiality of any related changes. While we do not expect any impacts to net income from the application of the standard to other transactions, we have not concluded whether the application of the standard to CIAC transactions could impact net income.

We continue to assess the impact of the disclosure requirements under the new standard and are evaluating the manner in which we will disaggregate revenue into categories that show how economic factors affect the nature, timing and uncertainty of revenue and cash flows generated from contracts with customers. 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.

ASU 2016-02

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. 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.

ASU 2016-09

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.

ASU 2016-16

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.

ASU 2016-17

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.

ASU 2017-04

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance 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.

ASU 2017-12

In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

Acquisitions and Contribution Transactions	9 Months Ended
Acquisitions and Contribution Transactions	Sep. 30, 2016
Acquisitions [Abstract]
Business Combination Disclosure [Text Block]	ACQUISITIONS AND CONTRIBUTION TRANSACTIONS Rover Contribution Agreement In July 2017, ETP announced that it had entered into a contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), for the purchase by Blackstone of a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). The agreement with Blackstone required Blackstone to contribute, at closing, funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments. The transaction closed in October 2017. As a result of this closing, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Permian Express Partners In February 2017, Sunoco Logistics formed Permian Express Partners LLC (“PEP”), a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment. In July 2017, 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 the Partnership’s 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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-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1383-128463

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6996-128479

+ Details

Cash And Cash Equivalents

9 Months Ended

Sep. 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:



	Nine Months Ended September 30,
	2017			2016
Accounts receivable	$	(77	)	$	(595	)
Accounts receivable from related companies	46			80
Inventories	150			(299		)
Other current assets	37			(135		)
Other non-current assets, net	(89		)	(1		)
Accounts payable	96			635
Accounts payable to related companies	(11		)	24
Accrued and other current liabilities	(26		)	213
Other non-current liabilities	57			31
Derivative assets and liabilities, net	2			219
Net change in operating assets and liabilities, net of effects of acquisitions	$	185		$	172

Non-cash investing and financing activities are as follows:



	Nine Months Ended September 30,
	2017		2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,236	$	991
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	—		34
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988	$	—

Inventories

9 Months Ended

Sep. 30, 2017

Inventory, Gross [Abstract]

Inventories

INVENTORIES

Inventories consisted of the following:



	September 30, 2017		December 31, 2016
Natural gas and NGLs	$	609	$	699
Crude oil	696		683
Refined products	69		113
Spare parts and other	217		217
Total inventories	$	1,591	$	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

9 Months Ended

Sep. 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 September 30, 2017 were $35.89 billion and $34.34 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations were $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 nine months ended September 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 September 30, 2017 and December 31, 2016 based on inputs used to derive their fair values:



				Fair Value Measurements at September 30, 2017
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	16		$	16		$	—
Swing Swaps IFERC	2			—			2
Fixed Swaps/Futures	28			28			—
Forward Physical Swaps	3			—			3
Power:
Forwards	11			—			11
Futures	1			1			—
Options – Puts	1			1			—
Natural Gas Liquids – Forwards/Swaps	213			213			—
Refined Products – Futures	2			2			—
Crude – Futures	2			2			—
Total commodity derivatives	279			263			16
Total assets	$	279		$	263		$	16
Liabilities:
Interest rate derivatives	$	(210	)	$	—		$	(210	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(22		)	(22		)	—
Swing Swaps IFERC	(3		)	(1		)	(2		)
Fixed Swaps/Futures	(22		)	(22		)	—
Forward Physical Swaps	(1		)	—			(1		)
Power:
Forwards	(9		)	—			(9		)
Futures	(1		)	(1		)	—
Natural Gas Liquids – Forwards/Swaps	(261		)	(261		)	—
Refined Products – Futures	(2		)	(2		)	—
Crude – Futures	(1		)	(1		)	—
Total commodity derivatives	(322		)	(310		)	(12		)
Total liabilities	$	(532	)	$	(310	)	$	(222	)



				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

9 Months Ended

Sep. 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Net income	$	761		$	138		$	1,417		$	986
Less: Income attributable to noncontrolling interest	110			64			243			231
Net income, net of noncontrolling interest	651			74			1,174			755
General Partner’s interest in net income	270			220			727			740
Class H Unitholder’s interest in net income	—			93			98			257
Class I Unitholder’s interest in net income	—			2			—			6
Common Unitholders’ interest in net income (loss)	381			(241		)	349			(248		)
Additional (earnings) distributions allocated to General Partner	—			(3		)	12			(9		)
Distributions on employee unit awards, net of allocation to General Partner	(6		)	(5		)	(19		)	(15		)
Net income (loss) available to Common Unitholders	$	375		$	(249	)	$	342		$	(272	)
Weighted average Common Units – basic ⁽¹⁾	1,125.2			761.1			990.9			749.7
Basic net income (loss) per Common Unit	$	0.33		$	(0.33	)	$	0.35		$	(0.36	)

Dilutive effect of unvested employee unit awards	3.7			—			4.6			—
Weighted average Common Units – diluted ⁽¹⁾	1,128.9			761.1			995.5			749.7
Diluted net income (loss) per Common Unit	$	0.33		$	(0.33	)	$	0.34		$	(0.36	)

⁽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	9 Months Ended
Debt Obligations	Sep. 30, 2017
Debt Disclosure [Abstract]
Debt Obligations	DEBT OBLIGATIONS ETP Senior Notes Redemption In October 2017, the Partnership redeemed all of the outstanding $500 million aggregate principal amount of ETLP’s 6.50% senior notes due July 2021 and all of the outstanding $700 million aggregate principal amount of ETLP’s 5.50% senior notes due April 2023. The aggregate amount paid to redeem these notes, including call premiums, was approximately $1.23 billion. ETP Senior Notes Offering In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net proceeds from the offering were used to redeem all of the $500 million aggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility (described below) and for general partnership purposes. The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal is payable upon maturity. Interest on the senior notes is paid semi-annually. The senior notes are guaranteed by the parent company (ETP) on a senior unsecured basis as long as it guarantees any of Sunoco Logistics Partners Operations L.P.’s other long-term debt. As a result of the parent guarantee, the senior notes will rank equally in right of payment with the Partnership’s existing and future senior debt, and senior in right of payment to any subordinated debt the Partnership may incur. 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 September 30, 2017, the ETLP Credit Facility had $2.06 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 September 30, 2017, the Sunoco Logistics Credit Facility had $35 million of outstanding borrowings. 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 September 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”). 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 September 30, 2017.

Preferred Units (Notes)	9 Months Ended
Preferred Units (Notes)	Sep. 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

9 Months Ended

Sep. 30, 2017

Partners' Capital Notes [Abstract]

Equity

EQUITY

The changes in outstanding common units during the nine months ended September 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 public offerings		54.0
Common units issued in connection with equity distribution agreements		22.6
Common units issued in connection with the distribution reinvestment plan		4.6
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		0.4
Number of common units at September 30, 2017		1,155.5


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


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

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 nine months ended September 30, 2017, the Partnership received proceeds of $498 million, net of $5 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. In July 2017, the Partnership initiated a new distribution reinvestment plan. During the nine months ended September 30, 2017, distributions of $106 million were reinvested under the distribution reinvestment plan.

August 2017 Units Offering

In August 2017, the Partnership issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by the Partnership to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

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. In July 2017, the Partnership contributed a portion of its ownership interest in Dakota Access and ETCO to PEP, a strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

PennTex Tender Offer and Limited Call Right Exercise

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

Quarterly Distributions of Available Cash

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
September 30, 2017	November 7, 2017	November 14, 2017	0.5650

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



	Total Year
2017 (remainder)	$	173
2018	153
2019	128
Each year beyond 2019	33

Accumulated Other Comprehensive Income

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



	September 30, 2017			December 31, 2016
Available-for-sale securities	$	7		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial gain related to pensions and other postretirement benefits	9			7
Investments in unconsolidated affiliates, net	3			4
Total AOCI, net of tax	$	14		$	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)	9 Months Ended
Income Taxes (Notes)	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES For the nine months ended September 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 $68 million during the period. In addition, for the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one of the subsidiaries. The three and nine months ended September 30, 2017 also reflect increased income tax expense due to higher earnings among the Partnership’s consolidated corporate subsidiaries. For the three and nine months ended September 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

9 Months Ended

Sep. 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 provides contingent residual support for any AmeriGas notes.

Guarantee of Sunoco LP Notes

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

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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Rental expense	$	29	$	19	$	68	$	58

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

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 Standing Rock Sioux Tribe (“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 temporary restraining order (“TRO”) request moot.

After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the 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 Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete this additional work by April 2018. 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/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As of September 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.

Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The court approved the Judicial Consent Order on October 10, 2017.

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (the “Regency Litigation Defendants”).

The Regency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Merger Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. A hearing on these motions is currently set for January 9, 2018.

The Regency Merger Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Merger Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.

Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation

On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise 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’s motion for rehearing to the Court of Appeals was denied. ETP intends to file a petition for review with the Texas Supreme Court.

Sunoco Logistics Merger Litigation

Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits have been voluntarily dismissed. The five remaining lawsuits have been consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs seek rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and attorneys’ fees.

The ETP-SXL Defendants cannot predict the outcome of the Sunoco Logistics Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing, nor can the ETP-SXL Defendants predict the amount of time and expense that will be required to resolve the Sunoco Logistics Merger Litigation. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Sunoco Logistics Merger.

Litigation filed by BP Products

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

SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.

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

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.

Other Litigation and Contingencies

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, 2017 and December 31, 2016, accruals of approximately $66 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 Notice of Violations (“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 the 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 approximately $2.3 million 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. On September 18, 2017, the FERC authorized Rover to resume HDD activities at the Tuscarawas River site and nine other river crossing sites. On October 20, 2017, the FERC authorized Rover to resume HDD activities at two additional sites.

On July 17, 2017, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Cease and Desist order requiring Rover, among other things, to cease any land development activity in Doddridge and Tyler Counties. Under the order, Rover had 20 days to submit a corrective action plan and schedule for agency review. The order followed several notices of violation WVDEP issued to Rover alleging stormwater non-compliance. Rover is complying with the order and has already addressed many of the stormwater control issues. On August 9, 2017, WVDEP lifted the Cease and Desist requirement.

On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project. On August 1, 2017 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 SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project. 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. SPLP 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 September 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 September 30, 2017, Sunoco, Inc. had been named as a PRP at approximately 44 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.



	September 30, 2017		December 31, 2016
Current	$	36	$	26
Non-current	276		283
Total environmental liabilities	$	312	$	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 September 30, 2017 and 2016, Sunoco, Inc. recorded $4 million and $10 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2017 and 2016, Sunoco, Inc. recorded $14 million and $24 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

9 Months Ended

Sep. 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:



	September 30, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	1,297,500		2017-2018	(682,500	)	2017
Basis Swaps IFERC/NYMEX⁽¹⁾	(15,810,000	)	2017-2019	2,242,500		2017
Options – Puts	13,000,000		2018	—		—
Power (Megawatt):
Forwards	665,040		2017-2018	391,880		2017-2018
Futures	(213,840	)	2017-2018	109,564		2017-2018
Options – Puts	(280,800	)	2017-2018	(50,400	)	2017
Options – Calls	545,600		2017-2018	186,400		2017
Crude (Bbls) – Futures	(160,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	67,500		2017-2020	10,750,000		2017-2018
Swing Swaps IFERC	91,897,500		2017-2019	(5,662,500	)	2017
Fixed Swaps/Futures	(20,220,000	)	2017-2019	(52,652,500	)	2017-2019
Forward Physical Contracts	(140,937,993	)	2017-2018	(22,492,489	)	2017
Natural Gas Liquid (Bbls) – Forwards/Swaps	(8,747,200	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) – Futures	(701,000	)	2017	(2,240,000	)	2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(41,102,500	)	2017	(36,370,000	)	2017
Fixed Swaps/Futures	(41,102,500	)	2017	(36,370,000	)	2017
Hedged Item – Inventory	41,102,500		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⁾	September 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
	September 30, 2017		December 31, 2016		September 30, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	7	$	—	$	—		$	(4	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	222		338		(262		)	(416		)
Commodity derivatives	50		24		(60		)	(52		)
Interest rate derivatives	—		—		(210		)	(193		)
Embedded derivatives in Preferred Units	—		—		—			(1		)
	272		362		(532		)	(662		)
Total derivatives	$	279	$	362	$	(532	)	$	(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	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(210	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	50			24			(60		)	(52		)
Broker cleared derivative contracts	Other current assets	229			338			(262		)	(420		)
Total gross derivatives		279			362			(532		)	(666		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(10		)	(4		)	10			4
Payments on margin deposit	Other current assets	(220		)	(338		)	220			338
Total net derivatives		$	49		$	20		$	(302	)	$	(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 September 30,					Nine Months Ended September 30,
		2017		2016			2017		2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	2	$	(9	)	$	4	$	8
Total		$	2	$	(9	)	$	4	$	8



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,						Nine Months Ended September 30,
		2017			2016			2017			2016
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	(5	)	$	(8	)	$	21		$	(24	)
Commodity derivatives – Non-trading	Cost of products sold	(12		)	(14		)	(15		)	(57		)
Interest rate derivatives	Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Embedded derivatives	Other, net	—			8			1			4
Total		$	(25	)	$	(42	)	$	(21	)	$	(256	)

- 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

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+ Details

Related Party Transactions

9 Months Ended

Sep. 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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Affiliated revenues	$	190	$	63	$	441	$	270

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



	September 30, 2017		December 31, 2016
Accounts receivable from related companies:
ETE	$	—	$	22
Sunoco LP	204		96
FGT	15		15
Other	116		76
Total accounts receivable from related companies:	$	335	$	209

Accounts payable to related companies:
Sunoco LP	$	178	$	20
Other	26		23
Total accounts payable to related companies:	$	204	$	43



	September 30, 2017		December 31, 2016
Long-term notes receivable (payable) – related companies:
Sunoco LP	$	85	$	87
Phillips 66	—		(250		)
Net long-term notes receivable (payable) – related companies	$	85	$	(163	)

Reportable Segments

9 Months Ended

Sep. 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 owned by the Partnership. As of September 30, 2017, the Partnership owned 43.5 million Sunoco LP common 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.

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	729		$	583		$	2,196		$	1,457
Intersegment revenues	44			175			146			400
	773			758			2,342			1,857
Interstate transportation and storage:
Revenues from external customers	220			231			652			714
Intersegment revenues	4			5			14			15
	224			236			666			729
Midstream:
Revenues from external customers	665			582			1,863			1,799
Intersegment revenues	1,100			761			3,154			1,966
	1,765			1,343			5,017			3,765
NGL and refined products transportation and services:
Revenues from external customers	1,989			1,397			5,874			4,014
Intersegment revenues	81			148			241			315
	2,070			1,545			6,115			4,329
Crude oil transportation and services:
Revenues from external customers	2,714			1,856			7,749			5,146
Intersegment revenues	11			—			16			—
	2,725			1,856			7,765			5,146
All other:
Revenues from external customers	656			882			2,110			2,171
Intersegment revenues	27			74			139			350
	683			956			2,249			2,521
Eliminations	(1,267		)	(1,163		)	(3,710		)	(3,046		)
Total revenues	$	6,973		$	5,531		$	20,444		$	15,301



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	163		$	133		$	480		$	461
Interstate transportation and storage	273			278			800			848
Midstream	356			314			1,088			875
NGL and refined products transportation and services	423			383			1,196			1,072
Crude oil transportation and services	396			169			830			521
All other	133			113			363			395
Total	1,744			1,390			4,757			4,172
Depreciation, depletion and amortization	(596		)	(503		)	(1,713		)	(1,469		)
Interest expense, net	(367		)	(345		)	(1,052		)	(981		)
Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Non-cash unit-based compensation expense	(19		)	(22		)	(57		)	(60		)
Unrealized gains (losses) on commodity risk management activities	(81		)	(15		)	17			(96		)
Inventory valuation adjustments	86			37			30			143
Adjusted EBITDA related to unconsolidated affiliates	(279		)	(240		)	(765		)	(711		)
Equity in earnings of unconsolidated affiliates	127			65			139			260
Impairment of investment in an unconsolidated affiliate	—			(308		)	—			(308		)
Other, net	42			43			111			84
Income before income tax expense (benefit)	$	649		$	74		$	1,439		$	855



	September 30, 2017		December 31, 2016
Assets:
Intrastate transportation and storage	$	5,179	$	5,164
Interstate transportation and storage	12,194		10,833
Midstream	19,781		17,873
NGL and refined products transportation and services	16,445		14,128
Crude oil transportation and services	17,267		15,941
All other	6,145		6,252
Total assets	$	77,011	$	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

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-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8906-108599

+ Details

Guarantor Financial Information (Notes)

9 Months Ended

Sep. 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:



	September 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	49		$	330	$	—		$	379
All other current assets	—			77			5,324		—			5,401
Property, plant and equipment, net	—			—			56,972		—			56,972
Investments in unconsolidated affiliates	25,174			11,605			4,221		(36,779		)	4,221
All other assets	—			25			10,013		—			10,038
Total assets	$	25,174		$	11,756		$	76,860	$	(36,779	)	$	77,011

Current liabilities	$	(1,494	)	$	(3,819	)	$	12,199	$	—		$	6,886
Non-current liabilities	—			7,664			31,604		—			39,268
Noncontrolling interest	—			—			4,191		—			4,191
Total partners’ capital	26,668			7,911			28,866		(36,779		)	26,666
Total liabilities and equity	$	25,174		$	11,756		$	76,860	$	(36,779	)	$	77,011



	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 September 30, 2017
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	6,973		$	—		$	6,973
Operating costs, expenses, and other	—		—			6,148			—			6,148
Operating income	—		—			825			—			825
Interest expense, net	—		(32		)	(335		)	—			(367		)
Equity in earnings of unconsolidated affiliates	647		236			127			(883		)	127
Losses on interest rate derivatives	—		—			(8		)	—			(8		)
Other, net	—		1			71			—			72
Income before income tax benefit	647		205			680			(883		)	649
Income tax benefit	—		—			(112		)	—			(112		)
Net income	647		205			792			(883		)	761
Less: Net income attributable to noncontrolling interest	—		—			110			—			110
Net income attributable to partners	$	647	$	205		$	682		$	(883	)	$	651

Other comprehensive income	$	—	$	—		$	7		$	—		$	7
Comprehensive income	647		205			799			(883		)	768
Comprehensive income attributable to noncontrolling interest	—		—			110			—			110
Comprehensive income attributable to partners	$	647	$	205		$	689		$	(883	)	$	658



	Three Months Ended September 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	5,531		$	—		$	5,531
Operating costs, expenses, and other	—		—			4,893			—			4,893
Operating income	—		—			638			—			638
Interest expense, net	—		(39		)	(306		)	—			(345		)
Equity in earnings of unconsolidated affiliates	119		193			65			(312		)	65
Impairment of investment in an unconsolidated affiliate	—		—			(308		)	—			(308		)
Losses on interest rate derivatives	—		—			(28		)	—			(28		)
Other, net	—		—			52			—			52
Income before income tax benefit	119		154			113			(312		)	74
Income tax benefit	—		—			(64		)	—			(64		)
Net income	119		154			177			(312		)	138
Less: Net income attributable to noncontrolling interest	—		—			21			—			21
Net income attributable to partners	$	119	$	154		$	156		$	(312	)	$	117

Other comprehensive income	$	—	$	—		$	2		$	—		$	2
Comprehensive income	119		154			179			(312		)	140
Comprehensive income attributable to noncontrolling interest	—		—			21			—			21
Comprehensive income attributable to partners	$	119	$	154		$	158		$	(312	)	$	119



	Nine Months Ended September 30, 2017
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	20,444		$	—		$	20,444
Operating costs, expenses, and other	—		1			18,232			—			18,233
Operating income (loss)	—		(1		)	2,212			—			2,211
Interest expense, net	—		(113		)	(939		)	—			(1,052		)
Equity in earnings of unconsolidated affiliates	1,657		1,001			139			(2,658		)	139
Losses on interest rate derivatives	—		—			(28		)	—			(28		)
Other, net	—		4			166			(1		)	169
Income before income tax expense	1,657		891			1,550			(2,659		)	1,439
Income tax expense	—		—			22			—			22
Net income	1,657		891			1,528			(2,659		)	1,417
Less: Net income attributable to noncontrolling interest	—		—			216			—			216
Net income attributable to partners	$	1,657	$	891		$	1,312		$	(2,659	)	$	1,201

Other comprehensive income	$	—	$	—		$	6		$	—		$	6
Comprehensive income	1,657		891			1,534			(2,659		)	1,423
Comprehensive income attributable to noncontrolling interest	—		—			216			—			216
Comprehensive income attributable to partners	$	1,657	$	891		$	1,318		$	(2,659	)	$	1,207



	Nine Months Ended September 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	15,301		$	—		$	15,301
Operating costs, expenses, and other	—		1			13,333			—			13,334
Operating income (loss)	—		(1		)	1,968			—			1,967
Interest expense, net	—		(116		)	(865		)	—			(981		)
Equity in earnings of unconsolidated affiliates	930		618			260			(1,548		)	260
Impairment of investment in an unconsolidated affiliate	—		—			(308		)	—			(308		)
Losses on interest rate derivatives	—		—			(179		)	—			(179		)
Other, net	—		—			96			—			96
Income before income tax benefit	930		501			972			(1,548		)	855
Income tax benefit	—		—			(131		)	—			(131		)
Net income	930		501			1,103			(1,548		)	986
Less: Net income attributable to noncontrolling interest	—		—			57			—			57
Net income attributable to partners	$	930	$	501		$	1,046		$	(1,548	)	$	929

Other comprehensive loss	$	—	$	—		$	(8	)	$	—		$	(8	)
Comprehensive income	930		501			1,095			(1,548		)	978
Comprehensive income attributable to noncontrolling interest	—		—			57			—			57
Comprehensive income attributable to partners	$	930	$	501		$	1,038		$	(1,548	)	$	921



	Nine Months Ended September 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	1,657		$	802		$	3,538		$	(2,660	)	$	3,337
Cash flows used in investing activities	(1,348		)	(1,127		)	(4,872		)	2,660			(4,687		)
Cash flows provided by (used in) financing activities	(309		)	333			1,345			—			1,369
Change in cash	—			8			11			—			19
Cash at beginning of period	—			41			319			—			360
Cash at end of period	$	—		$	49		$	330		$	—		$	379



	Nine Months Ended September 30, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	929		$	491		$	2,593		$	(1,548	)	$	2,465
Cash flows used in investing activities	(1,537		)	(918		)	(2,733		)	1,548			(3,640		)
Cash flows provided by (used in) financing activities	606			429			(10		)	—			1,025
Change in cash	(2		)	2			(150		)	—			(150		)
Cash at beginning of period	—			37			490			—			527
Cash at end of period	$	(2	)	$	39		$	340		$	—		$	377

- 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)	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
New Accounting Pronouncements, Policy [Policy Text Block]	Recent Accounting Pronouncements ASU 2014-09 In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method, which requires recognition, upon the date of initial application, of the cumulative effect of the retrospective application of the standard. We are continuing the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standard. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts (as discussed below) 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. We currently anticipate a change to revenues and costs associated with the accounting for noncash consideration in multiple of our reportable segments as well as the accounting for certain processing contracts in our midstream segment. We do not expect these changes in the accounting for noncash consideration or processing contracts to impact net income. We are still evaluating the potential impact of the adoption of ASU 2014-09 to contributions in aid of construction costs (“CIAC”) arrangements and materiality of any related changes. While we do not expect any impacts to net income from the application of the standard to other transactions, we have not concluded whether the application of the standard to CIAC transactions could impact net income. We continue to assess the impact of the disclosure requirements under the new standard and are evaluating the manner in which we will disaggregate revenue into categories that show how economic factors affect the nature, timing and uncertainty of revenue and cash flows generated from contracts with customers. 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. ASU 2016-02 In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. 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. ASU 2016-09 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. ASU 2016-16 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. ASU 2016-17 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. ASU 2017-04 In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance 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. ASU 2017-12 In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

Cash And Cash Equivalents (Tables)

9 Months Ended

Sep. 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:



	Nine Months Ended September 30,
	2017			2016
Accounts receivable	$	(77	)	$	(595	)
Accounts receivable from related companies	46			80
Inventories	150			(299		)
Other current assets	37			(135		)
Other non-current assets, net	(89		)	(1		)
Accounts payable	96			635
Accounts payable to related companies	(11		)	24
Accrued and other current liabilities	(26		)	213
Other non-current liabilities	57			31
Derivative assets and liabilities, net	2			219
Net change in operating assets and liabilities, net of effects of acquisitions	$	185		$	172

Non-Cash Investing And Financing Activities

Non-cash investing and financing activities are as follows:



	Nine Months Ended September 30,
	2017		2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,236	$	991
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	—		34
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988	$	—

Inventories (Tables)

9 Months Ended

Sep. 30, 2017

Inventory, Gross [Abstract]

Schedule Of Inventories

Inventories consisted of the following:



	September 30, 2017		December 31, 2016
Natural gas and NGLs	$	609	$	699
Crude oil	696		683
Refined products	69		113
Spare parts and other	217		217
Total inventories	$	1,591	$	1,712

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Measurements [Abstract]

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



				Fair Value Measurements at September 30, 2017
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	16		$	16		$	—
Swing Swaps IFERC	2			—			2
Fixed Swaps/Futures	28			28			—
Forward Physical Swaps	3			—			3
Power:
Forwards	11			—			11
Futures	1			1			—
Options – Puts	1			1			—
Natural Gas Liquids – Forwards/Swaps	213			213			—
Refined Products – Futures	2			2			—
Crude – Futures	2			2			—
Total commodity derivatives	279			263			16
Total assets	$	279		$	263		$	16
Liabilities:
Interest rate derivatives	$	(210	)	$	—		$	(210	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(22		)	(22		)	—
Swing Swaps IFERC	(3		)	(1		)	(2		)
Fixed Swaps/Futures	(22		)	(22		)	—
Forward Physical Swaps	(1		)	—			(1		)
Power:
Forwards	(9		)	—			(9		)
Futures	(1		)	(1		)	—
Natural Gas Liquids – Forwards/Swaps	(261		)	(261		)	—
Refined Products – Futures	(2		)	(2		)	—
Crude – Futures	(1		)	(1		)	—
Total commodity derivatives	(322		)	(310		)	(12		)
Total liabilities	$	(532	)	$	(310	)	$	(222	)



				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)

9 Months Ended

Sep. 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Net income	$	761		$	138		$	1,417		$	986
Less: Income attributable to noncontrolling interest	110			64			243			231
Net income, net of noncontrolling interest	651			74			1,174			755
General Partner’s interest in net income	270			220			727			740
Class H Unitholder’s interest in net income	—			93			98			257
Class I Unitholder’s interest in net income	—			2			—			6
Common Unitholders’ interest in net income (loss)	381			(241		)	349			(248		)
Additional (earnings) distributions allocated to General Partner	—			(3		)	12			(9		)
Distributions on employee unit awards, net of allocation to General Partner	(6		)	(5		)	(19		)	(15		)
Net income (loss) available to Common Unitholders	$	375		$	(249	)	$	342		$	(272	)
Weighted average Common Units – basic ⁽¹⁾	1,125.2			761.1			990.9			749.7
Basic net income (loss) per Common Unit	$	0.33		$	(0.33	)	$	0.35		$	(0.36	)

Dilutive effect of unvested employee unit awards	3.7			—			4.6			—
Weighted average Common Units – diluted ⁽¹⁾	1,128.9			761.1			995.5			749.7
Diluted net income (loss) per Common Unit	$	0.33		$	(0.33	)	$	0.34		$	(0.36	)

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

Equity (Tables)

9 Months Ended

Sep. 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 nine months ended September 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 public offerings		54.0
Common units issued in connection with equity distribution agreements		22.6
Common units issued in connection with the distribution reinvestment plan		4.6
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		0.4
Number of common units at September 30, 2017		1,155.5

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
September 30, 2017	November 7, 2017	November 14, 2017	0.5650

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)	$	173
2018	153
2019	128
Each year beyond 2019	33

Accumulated Other Comprehensive Income

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



	September 30, 2017			December 31, 2016
Available-for-sale securities	$	7		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial gain related to pensions and other postretirement benefits	9			7
Investments in unconsolidated affiliates, net	3			4
Total AOCI, net of tax	$	14		$	8

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

9 Months Ended

Sep. 30, 2017

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

Schedule of Rent Expense [Table Text Block]



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Rental expense	$	29	$	19	$	68	$	58

Environmental Exit Costs by Cost [Table Text Block]



	September 30, 2017		December 31, 2016
Current	$	36	$	26
Non-current	276		283
Total environmental liabilities	$	312	$	309

Derivative Assets And Liabilities (Tables)

9 Months Ended

Sep. 30, 2017

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:



	September 30, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	1,297,500		2017-2018	(682,500	)	2017
Basis Swaps IFERC/NYMEX⁽¹⁾	(15,810,000	)	2017-2019	2,242,500		2017
Options – Puts	13,000,000		2018	—		—
Power (Megawatt):
Forwards	665,040		2017-2018	391,880		2017-2018
Futures	(213,840	)	2017-2018	109,564		2017-2018
Options – Puts	(280,800	)	2017-2018	(50,400	)	2017
Options – Calls	545,600		2017-2018	186,400		2017
Crude (Bbls) – Futures	(160,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	67,500		2017-2020	10,750,000		2017-2018
Swing Swaps IFERC	91,897,500		2017-2019	(5,662,500	)	2017
Fixed Swaps/Futures	(20,220,000	)	2017-2019	(52,652,500	)	2017-2019
Forward Physical Contracts	(140,937,993	)	2017-2018	(22,492,489	)	2017
Natural Gas Liquid (Bbls) – Forwards/Swaps	(8,747,200	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) – Futures	(701,000	)	2017	(2,240,000	)	2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(41,102,500	)	2017	(36,370,000	)	2017
Fixed Swaps/Futures	(41,102,500	)	2017	(36,370,000	)	2017
Hedged Item – Inventory	41,102,500		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⁾	September 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
	September 30, 2017		December 31, 2016		September 30, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	7	$	—	$	—		$	(4	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	222		338		(262		)	(416		)
Commodity derivatives	50		24		(60		)	(52		)
Interest rate derivatives	—		—		(210		)	(193		)
Embedded derivatives in Preferred Units	—		—		—			(1		)
	272		362		(532		)	(662		)
Total derivatives	$	279	$	362	$	(532	)	$	(666	)

Derivatives, Offsetting Fair Value Amounts [Table Text Block]



		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(210	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	50			24			(60		)	(52		)
Broker cleared derivative contracts	Other current assets	229			338			(262		)	(420		)
Total gross derivatives		279			362			(532		)	(666		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(10		)	(4		)	10			4
Payments on margin deposit	Other current assets	(220		)	(338		)	220			338
Total net derivatives		$	49		$	20		$	(302	)	$	(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 September 30,					Nine Months Ended September 30,
		2017		2016			2017		2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	2	$	(9	)	$	4	$	8
Total		$	2	$	(9	)	$	4	$	8

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,						Nine Months Ended September 30,
		2017			2016			2017			2016
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	(5	)	$	(8	)	$	21		$	(24	)
Commodity derivatives – Non-trading	Cost of products sold	(12		)	(14		)	(15		)	(57		)
Interest rate derivatives	Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Embedded derivatives	Other, net	—			8			1			4
Total		$	(25	)	$	(42	)	$	(21	)	$	(256	)

- 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)

9 Months Ended

Sep. 30, 2017

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Affiliated revenues	$	190	$	63	$	441	$	270



	September 30, 2017		December 31, 2016
Accounts receivable from related companies:
ETE	$	—	$	22
Sunoco LP	204		96
FGT	15		15
Other	116		76
Total accounts receivable from related companies:	$	335	$	209

Accounts payable to related companies:
Sunoco LP	$	178	$	20
Other	26		23
Total accounts payable to related companies:	$	204	$	43



	September 30, 2017		December 31, 2016
Long-term notes receivable (payable) – related companies:
Sunoco LP	$	85	$	87
Phillips 66	—		(250		)
Net long-term notes receivable (payable) – related companies	$	85	$	(163	)

Reportable Segments (Tables)

9 Months Ended

Sep. 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	729		$	583		$	2,196		$	1,457
Intersegment revenues	44			175			146			400
	773			758			2,342			1,857
Interstate transportation and storage:
Revenues from external customers	220			231			652			714
Intersegment revenues	4			5			14			15
	224			236			666			729
Midstream:
Revenues from external customers	665			582			1,863			1,799
Intersegment revenues	1,100			761			3,154			1,966
	1,765			1,343			5,017			3,765
NGL and refined products transportation and services:
Revenues from external customers	1,989			1,397			5,874			4,014
Intersegment revenues	81			148			241			315
	2,070			1,545			6,115			4,329
Crude oil transportation and services:
Revenues from external customers	2,714			1,856			7,749			5,146
Intersegment revenues	11			—			16			—
	2,725			1,856			7,765			5,146
All other:
Revenues from external customers	656			882			2,110			2,171
Intersegment revenues	27			74			139			350
	683			956			2,249			2,521
Eliminations	(1,267		)	(1,163		)	(3,710		)	(3,046		)
Total revenues	$	6,973		$	5,531		$	20,444		$	15,301

Operating Segments [Member]

Segment Reporting Information [Line Items]

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	163		$	133		$	480		$	461
Interstate transportation and storage	273			278			800			848
Midstream	356			314			1,088			875
NGL and refined products transportation and services	423			383			1,196			1,072
Crude oil transportation and services	396			169			830			521
All other	133			113			363			395
Total	1,744			1,390			4,757			4,172
Depreciation, depletion and amortization	(596		)	(503		)	(1,713		)	(1,469		)
Interest expense, net	(367		)	(345		)	(1,052		)	(981		)
Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Non-cash unit-based compensation expense	(19		)	(22		)	(57		)	(60		)
Unrealized gains (losses) on commodity risk management activities	(81		)	(15		)	17			(96		)
Inventory valuation adjustments	86			37			30			143
Adjusted EBITDA related to unconsolidated affiliates	(279		)	(240		)	(765		)	(711		)
Equity in earnings of unconsolidated affiliates	127			65			139			260
Impairment of investment in an unconsolidated affiliate	—			(308		)	—			(308		)
Other, net	42			43			111			84
Income before income tax expense (benefit)	$	649		$	74		$	1,439		$	855

Assets Segments [Member]

Segment Reporting Information [Line Items]

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



	September 30, 2017		December 31, 2016
Assets:
Intrastate transportation and storage	$	5,179	$	5,164
Interstate transportation and storage	12,194		10,833
Midstream	19,781		17,873
NGL and refined products transportation and services	16,445		14,128
Crude oil transportation and services	17,267		15,941
All other	6,145		6,252
Total assets	$	77,011	$	70,191

Guarantor Financial Information (Tables)

9 Months Ended

Sep. 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:



	September 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	49		$	330	$	—		$	379
All other current assets	—			77			5,324		—			5,401
Property, plant and equipment, net	—			—			56,972		—			56,972
Investments in unconsolidated affiliates	25,174			11,605			4,221		(36,779		)	4,221
All other assets	—			25			10,013		—			10,038
Total assets	$	25,174		$	11,756		$	76,860	$	(36,779	)	$	77,011

Current liabilities	$	(1,494	)	$	(3,819	)	$	12,199	$	—		$	6,886
Non-current liabilities	—			7,664			31,604		—			39,268
Noncontrolling interest	—			—			4,191		—			4,191
Total partners’ capital	26,668			7,911			28,866		(36,779		)	26,666
Total liabilities and equity	$	25,174		$	11,756		$	76,860	$	(36,779	)	$	77,011



	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 September 30, 2017
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	6,973		$	—		$	6,973
Operating costs, expenses, and other	—		—			6,148			—			6,148
Operating income	—		—			825			—			825
Interest expense, net	—		(32		)	(335		)	—			(367		)
Equity in earnings of unconsolidated affiliates	647		236			127			(883		)	127
Losses on interest rate derivatives	—		—			(8		)	—			(8		)
Other, net	—		1			71			—			72
Income before income tax benefit	647		205			680			(883		)	649
Income tax benefit	—		—			(112		)	—			(112		)
Net income	647		205			792			(883		)	761
Less: Net income attributable to noncontrolling interest	—		—			110			—			110
Net income attributable to partners	$	647	$	205		$	682		$	(883	)	$	651

Other comprehensive income	$	—	$	—		$	7		$	—		$	7
Comprehensive income	647		205			799			(883		)	768
Comprehensive income attributable to noncontrolling interest	—		—			110			—			110
Comprehensive income attributable to partners	$	647	$	205		$	689		$	(883	)	$	658



	Three Months Ended September 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	5,531		$	—		$	5,531
Operating costs, expenses, and other	—		—			4,893			—			4,893
Operating income	—		—			638			—			638
Interest expense, net	—		(39		)	(306		)	—			(345		)
Equity in earnings of unconsolidated affiliates	119		193			65			(312		)	65
Impairment of investment in an unconsolidated affiliate	—		—			(308		)	—			(308		)
Losses on interest rate derivatives	—		—			(28		)	—			(28		)
Other, net	—		—			52			—			52
Income before income tax benefit	119		154			113			(312		)	74
Income tax benefit	—		—			(64		)	—			(64		)
Net income	119		154			177			(312		)	138
Less: Net income attributable to noncontrolling interest	—		—			21			—			21
Net income attributable to partners	$	119	$	154		$	156		$	(312	)	$	117

Other comprehensive income	$	—	$	—		$	2		$	—		$	2
Comprehensive income	119		154			179			(312		)	140
Comprehensive income attributable to noncontrolling interest	—		—			21			—			21
Comprehensive income attributable to partners	$	119	$	154		$	158		$	(312	)	$	119



	Nine Months Ended September 30, 2017
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	20,444		$	—		$	20,444
Operating costs, expenses, and other	—		1			18,232			—			18,233
Operating income (loss)	—		(1		)	2,212			—			2,211
Interest expense, net	—		(113		)	(939		)	—			(1,052		)
Equity in earnings of unconsolidated affiliates	1,657		1,001			139			(2,658		)	139
Losses on interest rate derivatives	—		—			(28		)	—			(28		)
Other, net	—		4			166			(1		)	169
Income before income tax expense	1,657		891			1,550			(2,659		)	1,439
Income tax expense	—		—			22			—			22
Net income	1,657		891			1,528			(2,659		)	1,417
Less: Net income attributable to noncontrolling interest	—		—			216			—			216
Net income attributable to partners	$	1,657	$	891		$	1,312		$	(2,659	)	$	1,201

Other comprehensive income	$	—	$	—		$	6		$	—		$	6
Comprehensive income	1,657		891			1,534			(2,659		)	1,423
Comprehensive income attributable to noncontrolling interest	—		—			216			—			216
Comprehensive income attributable to partners	$	1,657	$	891		$	1,318		$	(2,659	)	$	1,207



	Nine Months Ended September 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	15,301		$	—		$	15,301
Operating costs, expenses, and other	—		1			13,333			—			13,334
Operating income (loss)	—		(1		)	1,968			—			1,967
Interest expense, net	—		(116		)	(865		)	—			(981		)
Equity in earnings of unconsolidated affiliates	930		618			260			(1,548		)	260
Impairment of investment in an unconsolidated affiliate	—		—			(308		)	—			(308		)
Losses on interest rate derivatives	—		—			(179		)	—			(179		)
Other, net	—		—			96			—			96
Income before income tax benefit	930		501			972			(1,548		)	855
Income tax benefit	—		—			(131		)	—			(131		)
Net income	930		501			1,103			(1,548		)	986
Less: Net income attributable to noncontrolling interest	—		—			57			—			57
Net income attributable to partners	$	930	$	501		$	1,046		$	(1,548	)	$	929

Other comprehensive loss	$	—	$	—		$	(8	)	$	—		$	(8	)
Comprehensive income	930		501			1,095			(1,548		)	978
Comprehensive income attributable to noncontrolling interest	—		—			57			—			57
Comprehensive income attributable to partners	$	930	$	501		$	1,038		$	(1,548	)	$	921



	Nine Months Ended September 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	1,657		$	802		$	3,538		$	(2,660	)	$	3,337
Cash flows used in investing activities	(1,348		)	(1,127		)	(4,872		)	2,660			(4,687		)
Cash flows provided by (used in) financing activities	(309		)	333			1,345			—			1,369
Change in cash	—			8			11			—			19
Cash at beginning of period	—			41			319			—			360
Cash at end of period	$	—		$	49		$	330		$	—		$	379



	Nine Months Ended September 30, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	929		$	491		$	2,593		$	(1,548	)	$	2,465
Cash flows used in investing activities	(1,537		)	(918		)	(2,733		)	1,548			(3,640		)
Cash flows provided by (used in) financing activities	606			429			(10		)	—			1,025
Change in cash	(2		)	2			(150		)	—			(150		)
Cash at beginning of period	—			37			490			—			527
Cash at end of period	$	(2	)	$	39		$	340		$	—		$	377

Operations And Organization Operations And Organization (Details) shares in Millions	1 Months Ended	9 Months Ended
	Apr. 30, 2017 shares	Sep. 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		9 Months Ended
	Oct. 31, 2017	Jul. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Intangible assets, net			$ 5,379	$ 4,696
Property, plant and equipment			65,735	$ 58,220
Capital contributions from noncontrolling interest			1,907
Rover Pipeline LLC [Member] \| Holdco [Member] \| Pending Rover Contribution [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		65.00%
Holdco [Member] \| ETP [Member] \| Pending Rover Contribution [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		49.90%
Energy Transfer Crude Oil Company, LLC [Member] \| Dakota Access, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		15.00%
Sunoco Logistics [Member] \| Permian Express Partners LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		88.00%
Intangible assets, net			547
Property, plant and equipment			435
Capital contributions from noncontrolling interest			$ 988
Subsequent Event [Member] \| Blackstone [Member] \| Pending Rover Contribution [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	49.90%
Subsequent Event [Member] \| ETP [Member] \| Pending Rover Contribution [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.10%

Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash and Cash Equivalents [Abstract]
Accounts receivable	$ (77)	$ (595)
Accounts receivable from related companies	46	80
Inventories	150	(299)
Other current assets	37	(135)
Other non-current assets, net	(89)	(1)
Accounts payable	96	635
Accounts payable to related companies	(11)	24
Accrued and other current liabilities	(26)	213
Other non-current liabilities	57	31
Derivative assets and liabilities, net	2	219
Net change in operating assets and liabilities, net of effects of acquisitions	$ 185	$ 172

Cash And Cash Equivalents Non-Cash Investing and Financing Activities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 1,236	$ 991
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	34
NON-CASH FINANCING ACTIVITIES:
Capital Contributions from Noncontrolling Interest	$ 988	$ 0

Inventories (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Inventory, Gross [Abstract]
Natural gas and NGLs	$ 609	$ 699
Crude oil	696	683
Refined products	69	113
Spare parts and other	217	217
Total inventories	$ 1,591	$ 1,712

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Fair Value Measurements [Abstract]
Transfers between levels in fair value hierarchy	$ 0
Aggregate fair value of long-term debt	35,890	$ 33,850
Long-term Debt	$ 34,340	$ 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

9 Months Ended

Sep. 30, 2017

Sep. 30, 2016

Sep. 30, 2017

Sep. 30, 2016

Earnings Per Share [Abstract]

Net income

$ 761

$ 138

$ 1,417

$ 986

Less: Income attributable to noncontrolling interest

110

243

231

Net income, net of noncontrolling interest

651

1,174

755

General Partner’s interest in net income

270

220

727

740

Class H Unitholder’s interest in net income

257

Class I Unitholder’s interest in net income

Common Unitholders’ interest in net income (loss)

381

(241)

349

(248)

Additional (earnings) distributions allocated to General Partner

(3)

(9)

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

(6)

(5)

(19)

(15)

Net income (loss) available to Common Unitholders

$ 375

$ (249)

$ 342

$ (272)

Weighted average Common Units – basic (1)

^[1]

1,125.2

761.1

990.9

749.7

Dilutive effect of unvested employee unit awards

3.7

0.0

4.6

0.0

Weighted average Common Units – diluted (1)

^[1]

1,128.9

761.1

995.5

749.7

Basic net income (loss) per Common Unit

$ 0.33

$ (0.33)

$ 0.35

$ (0.36)

Diluted net income (loss) per Common Unit

$ 0.33

$ (0.33)

$ 0.34

$ (0.36)

[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	1 Months Ended	3 Months Ended
	Oct. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Proceeds from Issuance of Senior Long-term Debt		$ 2,220
ETLP [Member] \| ETLP Credit Facility due November 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity		3,750
Long-term Line of Credit		2,060
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		35
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
4.0% Senior Notes due October 2027 [Member]
Senior Notes		$ 750
Debt Instrument, Interest Rate, Stated Percentage		4.00%
5.40% Senior Notes due October 2047 [Member]
Senior Notes		$ 1,500
Debt Instrument, Interest Rate, Stated Percentage		5.40%
6.5% Senior Notes due May 15, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage		6.50%
Early Repayment of Senior Debt		$ 500
PennTex $275 million Revolving Credit Facility due December 2019 [Member] \| PennTex [Member]
Line of Credit Facility, Current Borrowing Capacity		275
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
Subsequent Event [Member]
Early Repayment of Senior Debt	$ 1,230
Subsequent Event [Member] \| 6.5% Senior Notes due May 15, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Early Repayment of Senior Debt	$ 500
Subsequent Event [Member] \| 5.5% Senior Notes, due April 15, 2023 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Early Repayment of Senior Debt	$ 700

Preferred Units (Details) - USD ($) shares in Millions, $ in Millions	1 Months Ended	9 Months Ended
	Jan. 31, 2017	Sep. 30, 2017	Sep. 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				9 Months Ended
	Aug. 31, 2017	Feb. 28, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2017	Sep. 30, 2016	Feb. 01, 2017
Partners' Capital Account, Units, Sold in Public Offering	54.0						54.0
Proceeds from Issuance of Common Limited Partners Units	$ 997						$ 2,162	$ 794
Sunoco Logistics [Member]
Rate						$ 0.52
Post-Merger ETP [Member]
Rate			$ 0.5650	$ 0.5500	$ 0.5350
Distribution Made to Limited Partner, Distribution Date			Nov. 14, 2017	Aug. 14, 2017	May 15, 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							498
Stock Issued During Period, Value, Dividend Reinvestment Plan							$ 106
PennTex [Member]
Sale of Stock, Price Per Share			$ 20.00				$ 20.00
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross		$ 2,000
Bakken Pipeline Investments LLC [Member] \| Bakken Holdings Company LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired									49.00%
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%
IDRs [Member] \| Maximum [Member]
Marginal Percentage Interest in Distributions			50.00%				50.00%
Second Target Distribution [Member]
Distribution Payment Targets			0.0833
Equity Distribution Agreement [Member] \| ETP [Member]
Fees and Commissions							$ 5

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

1 Months Ended

9 Months Ended

Aug. 31, 2017

Jan. 31, 2017

Sep. 30, 2017

Partners' Capital Notes [Abstract]

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

^[1]

794.8

Partners' Capital Account, Units, Sold in Public Offering

54.0

Common units issued in connection with equity distribution agreements

22.6

Common units issued in connection with the distribution reinvestment plan

4.6

Number of common units at September 30, 2017

1,155.5

Partners' Capital Account, Units, Sold in Private Placement

23.7

Partners' Capital Account, Units, Acquisitions

^[2]

255.4

Partners' Capital Account, Units, Unit-based Compensation

0.4

[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)

9 Months Ended

Sep. 30, 2017

Minimum Quarterly Distribution [Member]

Distribution Payment Targets

0.0750

Minimum Quarterly Distribution [Member] | IDRs [Member]

Marginal Percentage Interest in Distributions

0.00%

Minimum Quarterly Distribution [Member] | Limited Partners

Marginal Percentage Interest in Distributions

100.00%

^[1]

First Target Distribution [Member]

Distribution Payment Targets

up to $0.0833

First Target Distribution [Member] | IDRs [Member]

Marginal Percentage Interest in Distributions

0.00%

First Target Distribution [Member] | Limited Partners

Marginal Percentage Interest in Distributions

100.00%

^[1]

Second Target Distribution [Member]

Distribution Payment Targets

above $0.0833 up to $0.0958

Second Target Distribution [Member] | IDRs [Member]

Marginal Percentage Interest in Distributions

13.00%

Second Target Distribution [Member] | Limited Partners

Marginal Percentage Interest in Distributions

87.00%

^[1]

Third Target Distribution [Member]

Distribution Payment Targets

above $0.0958 up to $0.2638

Third Target Distribution [Member] | IDRs [Member]

Marginal Percentage Interest in Distributions

35.00%

Third Target Distribution [Member] | Limited Partners

Marginal Percentage Interest in Distributions

65.00%

^[1]

Thereafter [Member]

Distribution Payment Targets

above $0.2638

Thereafter [Member] | IDRs [Member]

Marginal Percentage Interest in Distributions

48.00%

Thereafter [Member] | Limited Partners

Marginal Percentage Interest in Distributions

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
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016
Post-Merger ETP [Member]
Distribution Made to Member or Limited Partner [Line Items]
Record Date	Nov. 07, 2017	Aug. 07, 2017	May 10, 2017
Payment Date	Nov. 14, 2017	Aug. 14, 2017	May 15, 2017
Rate	$ 0.5650	$ 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	3 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
ETE \| Subsequent Event [Member]
Relinquishment of Incentive Distributions	$ 173	$ 33	$ 128	$ 153

Equity AOCI (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
Equity AOCI (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 7	$ 2
Foreign currency translation adjustment	(5)	(5)
Actuarial gain related to pensions and other postretirement benefits	9	7
Investments in unconsolidated affiliates, net	3	4
Total AOCI, net of tax	$ 14	$ 8

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Sep. 30, 2017	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ 68
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Restructuring Charges, Amount	$ 154

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)	1 Months Ended			3 Months Ended		9 Months Ended		12 Months Ended
	May 31, 2017 USD ($)	Apr. 30, 2015 USD ($)	Jan. 31, 2012 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2016 USD ($)
Maximum lease expiration year						Dec. 31, 2034
Loss contingency accrual, at carrying value				$ 66,000,000		$ 66,000,000			$ 77,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed				0		0
Accrual for Environmental Loss Contingencies				312,000,000		312,000,000			$ 309,000,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount				319,000,000		319,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount				595,000,000		595,000,000
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				$ 4,000,000	$ 10,000,000	$ 14,000,000	$ 24,000,000
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				44		44
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				$ 2,300,000		$ 2,300,000
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		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Rental expense	$ 29	$ 19	$ 68	$ 58

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Environmental Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Environmental Exit Cost [Line Items]
Current	$ 36	$ 26
Non-current	276	283
Total environmental liabilities	$ 312	$ 309

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

9 Months Ended

Sep. 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	Sep. 30, 2017	Dec. 31, 2016
Total derivatives assets	$ 279	$ 362
Total derivatives liabilities	(532)	(666)
Designated as Hedging Instrument [Member] \| Commodity derivatives (margin deposits)
Total derivatives assets	7	0
Total derivatives liabilities	0	(4)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	272	362
Total derivatives liabilities	(532)	(662)
Not Designated as Hedging Instrument [Member] \| Commodity derivatives (margin deposits)
Total derivatives assets	222	338
Total derivatives liabilities	(262)	(416)
Not Designated as Hedging Instrument [Member] \| Commodity derivatives
Total derivatives assets	50	24
Total derivatives liabilities	(60)	(52)
Not Designated as Hedging Instrument [Member] \| Interest rate derivatives
Total derivatives assets	0	0
Total derivatives liabilities	(210)	(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	Sep. 30, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 279	$ 362
Derivative Liability, Fair Value, Gross Liability	(532)	(666)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(10)	(4)
Derivative Liability, Fair Value, Amount Offset Against Collateral	10	4
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(220)	(338)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	220	338
Derivative Asset, Fair Value, Net	49	20
Derivative Liability, Fair Value, Net	(302)	(324)
Without offsetting agreements [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(210)	(194)
OTC Contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	50	24
Derivative Liability, Fair Value, Gross Liability	(60)	(52)
Broker cleared derivative contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	229	338
Derivative Liability, Fair Value, Gross Liability	$ (262)	$ (420)

Derivative Assets And Liabilities Partnership's Derivative Assets And Liabilities, Recognized OCI On Derivatives (Effective Portion) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Commodity derivatives	$ 2	$ (9)	$ 4	$ 8
Commodity Derivatives [Member]
Commodity derivatives	$ 2	$ (9)	$ 4	$ 8

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		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	$ 2	$ (9)	$ 4	$ 8
Amount of Gain/(Loss) Recognized in Income on Derivatives	(25)	(42)	(21)	(256)
Losses on interest rate derivatives	(8)	(28)	(28)	(179)
Commodity Derivatives - Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(5)	(8)	21	(24)
Commodity derivatives
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	2	(9)	4	8
Amount of Gain/(Loss) Recognized in Income on Derivatives	(12)	(14)	(15)	(57)
Other Income (Expenses) [Member] \| Embedded Derivatives in Preferred Units [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 0	$ 8	$ 1	$ 4

Related Party Transactions Affiliated Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Related Party Transactions [Abstract]
Affiliated revenues	$ 190	$ 63	$ 441	$ 270

Related Party Transactions Related Party A/R and A/P (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Total accounts receivable from related companies:	$ 335	$ 209
Total accounts payable to related companies:	204	43
Long-term notes payable – related companies	0	(250)
Net Related Party Receivable (Payable)	85	(163)
ETE
Total accounts receivable from related companies:	0	22
Sunoco LP
Notes Receivable, Related Parties, Noncurrent	85	87
Total accounts receivable from related companies:	204	96
Total accounts payable to related companies:	178	20
FGT
Total accounts receivable from related companies:	15	15
Other
Total accounts receivable from related companies:	116	76
Total accounts payable to related companies:	26	23
Phillips 66 Partners LP [Member]
Long-term notes payable – related companies	$ 0	$ (250)

Reportable Segments Segment Revenues (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information [Line Items]
Revenues	$ 6,973	$ 5,531	$ 20,444	$ 15,301
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Revenues	773	758	2,342	1,857
Intrastate transportation and storage \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	729	583	2,196	1,457
Intrastate transportation and storage \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	44	175	146	400
Interstate transportation and storage
Segment Reporting Information [Line Items]
Revenues	224	236	666	729
Interstate transportation and storage \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	220	231	652	714
Interstate transportation and storage \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	4	5	14	15
Midstream
Segment Reporting Information [Line Items]
Revenues	1,765	1,343	5,017	3,765
Midstream \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	665	582	1,863	1,799
Midstream \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	1,100	761	3,154	1,966
NGL and refined products transportation and services
Segment Reporting Information [Line Items]
Revenues	2,070	1,545	6,115	4,329
NGL and refined products transportation and services \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	1,989	1,397	5,874	4,014
NGL and refined products transportation and services \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	81	148	241	315
Crude oil transportation and services
Segment Reporting Information [Line Items]
Revenues	2,725	1,856	7,765	5,146
Crude oil transportation and services \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	2,714	1,856	7,749	5,146
Crude oil transportation and services \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	11	0	16	0
All other
Segment Reporting Information [Line Items]
Revenues	683	956	2,249	2,521
All other \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	656	882	2,110	2,171
All other \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	27	74	139	350
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (1,267)	$ (1,163)	$ (3,710)	$ (3,046)

Reportable Segments Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 1,744	$ 1,390	$ 4,757	$ 4,172
Depreciation, depletion and amortization	(596)	(503)	(1,713)	(1,469)
Interest expense, net	(367)	(345)	(1,052)	(981)
Losses on interest rate derivatives	(8)	(28)	(28)	(179)
Non-cash unit-based compensation expense	(19)	(22)	(57)	(60)
Unrealized gains (losses) on commodity risk management activities	(81)	(15)	17	(96)
Inventory valuation adjustments	86	37	30	143
Adjusted EBITDA related to unconsolidated affiliates	(279)	(240)	(765)	(711)
Equity in earnings of unconsolidated affiliates	127	65	139	260
Other, net	42	43	111	84
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	649	74	1,439	855
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	163	133	480	461
Interstate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	273	278	800	848
Midstream
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	356	314	1,088	875
NGL and refined products transportation and services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	423	383	1,196	1,072
Crude oil transportation and services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	396	169	830	521
All other
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 133	$ 113	$ 363	$ 395

Reportable Segments Segment Assets (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Assets	$ 77,011	$ 70,191
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Assets	5,179	5,164
Interstate transportation and storage
Segment Reporting Information [Line Items]
Assets	12,194	10,833
Midstream
Segment Reporting Information [Line Items]
Assets	19,781	17,873
NGL and refined products transportation and services
Segment Reporting Information [Line Items]
Assets	16,445	14,128
Crude oil transportation and services
Segment Reporting Information [Line Items]
Assets	17,267	15,941
All other
Segment Reporting Information [Line Items]
Assets	$ 6,145	$ 6,252

Reportable Segments Reportable Segments Narrative (Details) - Sunoco LP shares in Millions	Sep. 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	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Cash and Cash Equivalents, at Carrying Value	$ 379	$ 360	$ 377	$ 527
Other current assets	201	298
Property, Plant and Equipment, Net	56,972	50,917
Advances to and investments in unconsolidated affiliates	4,221	4,280
Other Assets, Noncurrent	752	672
Assets	77,011	70,191
Liabilities, Current	6,886	6,203
Other non-current liabilities	1,111	952
Noncontrolling interest	4,191	7,885
Partners' Capital	26,666	18,642
Liabilities and Equity	77,011	70,191
Pro Forma [Member]
Cash and Cash Equivalents, at Carrying Value	379	360	377	527
Other current assets	5,401	5,369
Property, Plant and Equipment, Net	56,972	50,917
Advances to and investments in unconsolidated affiliates	4,221	4,280
Other Assets, Noncurrent	10,038	9,265
Assets	77,011	70,191
Liabilities, Current	6,886	6,203
Liabilities, Noncurrent	39,268	37,461
Noncontrolling interest	4,191	1,297
Partners' Capital	26,666	25,230
Liabilities and Equity	77,011	70,191
Pro Forma [Member] \| Parent Guarantor [Member]
Cash and Cash Equivalents, at Carrying Value	0	0	(2)	0
Other current assets	0	0
Property, Plant and Equipment, Net	0	0
Advances to and investments in unconsolidated affiliates	25,174	23,350
Other Assets, Noncurrent	0	0
Assets	25,174	23,350
Liabilities, Current	(1,494)	(1,761)
Liabilities, Noncurrent	0	299
Noncontrolling interest	0	0
Partners' Capital	26,668	24,812
Liabilities and Equity	25,174	23,350
Pro Forma [Member] \| Subsidiary Issuer [Member]
Cash and Cash Equivalents, at Carrying Value	49	41	39	37
Other current assets	77	2
Property, Plant and Equipment, Net	0	0
Advances to and investments in unconsolidated affiliates	11,605	10,664
Other Assets, Noncurrent	25	5
Assets	11,756	10,712
Liabilities, Current	(3,819)	(3,800)
Liabilities, Noncurrent	7,664	7,313
Noncontrolling interest	0	0
Partners' Capital	7,911	7,199
Liabilities and Equity	11,756	10,712
Pro Forma [Member] \| Non-Guarantor Subsidiaries [Member]
Cash and Cash Equivalents, at Carrying Value	330	319	340	490
Other current assets	5,324	5,367
Property, Plant and Equipment, Net	56,972	50,917
Advances to and investments in unconsolidated affiliates	4,221	4,280
Other Assets, Noncurrent	10,013	9,260
Assets	76,860	70,143
Liabilities, Current	12,199	11,764
Liabilities, Noncurrent	31,604	30,148
Noncontrolling interest	4,191	1,297
Partners' Capital	28,866	26,934
Liabilities and Equity	76,860	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	(36,779)	(34,014)
Other Assets, Noncurrent	0	0
Assets	(36,779)	(34,014)
Liabilities, Current	0	0
Liabilities, Noncurrent	0	(299)
Noncontrolling interest	0	0
Partners' Capital	(36,779)	(33,715)
Liabilities and Equity	$ (36,779)	$ (34,014)

Guarantor Financial Information Statements of Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues	$ 6,973	$ 5,531	$ 20,444	$ 15,301
Costs and Expenses	6,148	4,893	18,233	13,334
OPERATING INCOME	825	638	2,211	1,967
Interest Expense	(367)	(345)	(1,052)	(981)
Equity in earnings of unconsolidated affiliates	127	65	139	260
Equity Method Investment, Other than Temporary Impairment	0	(308)	0	(308)
Losses on interest rate derivatives	(8)	(28)	(28)	(179)
Other Nonoperating Income (Expense)	72	52	169	96
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	649	74	1,439	855
Income tax expense (benefit)	(112)	(64)	22	(131)
Net income	761	138	1,417	986
Less: Net income attributable to noncontrolling interest	110	64	243	231
Net Income (Loss) Attributable to Parent	651	74	1,174	755
Other Comprehensive Income (Loss), Net of Tax	7	2	6	(8)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	768	140	1,423	978
Less: Comprehensive income attributable to noncontrolling interest	110	64	243	231
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	658	76	1,180	747
Pro Forma [Member]
Revenues	6,973	5,531	20,444	15,301
Costs and Expenses	6,148	4,893	18,233	13,334
OPERATING INCOME	825	638	2,211	1,967
Interest Expense	(367)	(345)	(1,052)	(981)
Equity in earnings of unconsolidated affiliates	127	65	139	260
Equity Method Investment, Other than Temporary Impairment		(308)		(308)
Losses on interest rate derivatives	(8)	(28)	(28)	(179)
Other Nonoperating Income (Expense)	72	52	169	96
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	649	74	1,439	855
Income tax expense (benefit)	(112)	(64)	22	(131)
Net income	761	138	1,417	986
Less: Net income attributable to noncontrolling interest	110	21	216	57
Net Income (Loss) Attributable to Parent	651	117	1,201	929
Other Comprehensive Income (Loss), Net of Tax	7	2	6	(8)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	768	140	1,423	978
Less: Comprehensive income attributable to noncontrolling interest	110	21	216	57
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	658	119	1,207	921
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 of unconsolidated affiliates	647	119	1,657	930
Equity Method Investment, Other than Temporary Impairment		0		0
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	647	119	1,657	930
Income tax expense (benefit)	0	0	0	0
Net income	647	119	1,657	930
Less: Net income attributable to noncontrolling interest	0	0	0	0
Net Income (Loss) Attributable to Parent	647	119	1,657	930
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	647	119	1,657	930
Less: Comprehensive income attributable to noncontrolling interest	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	647	119	1,657	930
Pro Forma [Member] \| Subsidiary Issuer [Member]
Revenues	0	0	0	0
Costs and Expenses	0	0	1	1
OPERATING INCOME	0	0	(1)	(1)
Interest Expense	(32)	(39)	(113)	(116)
Equity in earnings of unconsolidated affiliates	236	193	1,001	618
Equity Method Investment, Other than Temporary Impairment		0		0
Losses on interest rate derivatives	0	0	0	0
Other Nonoperating Income (Expense)	1	0	4	0
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	205	154	891	501
Income tax expense (benefit)	0	0	0	0
Net income	205	154	891	501
Less: Net income attributable to noncontrolling interest	0	0	0	0
Net Income (Loss) Attributable to Parent	205	154	891	501
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	205	154	891	501
Less: Comprehensive income attributable to noncontrolling interest	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	205	154	891	501
Pro Forma [Member] \| Non-Guarantor Subsidiaries [Member]
Revenues	6,973	5,531	20,444	15,301
Costs and Expenses	6,148	4,893	18,232	13,333
OPERATING INCOME	825	638	2,212	1,968
Interest Expense	(335)	(306)	(939)	(865)
Equity in earnings of unconsolidated affiliates	127	65	139	260
Equity Method Investment, Other than Temporary Impairment		(308)		(308)
Losses on interest rate derivatives	(8)	(28)	(28)	(179)
Other Nonoperating Income (Expense)	71	52	166	96
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	680	113	1,550	972
Income tax expense (benefit)	(112)	(64)	22	(131)
Net income	792	177	1,528	1,103
Less: Net income attributable to noncontrolling interest	110	21	216	57
Net Income (Loss) Attributable to Parent	682	156	1,312	1,046
Other Comprehensive Income (Loss), Net of Tax	7	2	6	(8)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	799	179	1,534	1,095
Less: Comprehensive income attributable to noncontrolling interest	110	21	216	57
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	689	158	1,318	1,038
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 of unconsolidated affiliates	(883)	(312)	(2,658)	(1,548)
Equity Method Investment, Other than Temporary Impairment		0		0
Losses on interest rate derivatives	0	0	0	0
Other Nonoperating Income (Expense)	0	0	(1)	0
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	(883)	(312)	(2,659)	(1,548)
Income tax expense (benefit)	0	0	0	0
Net income	(883)	(312)	(2,659)	(1,548)
Less: Net income attributable to noncontrolling interest	0	0	0	0
Net Income (Loss) Attributable to Parent	(883)	(312)	(2,659)	(1,548)
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(883)	(312)	(2,659)	(1,548)
Less: Comprehensive income attributable to noncontrolling interest	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (883)	$ (312)	$ (2,659)	$ (1,548)

Guarantor Financial Information Cash Flows (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
Net Cash Provided by (Used in) Operating Activities	$ 3,337	$ 2,465
Net Cash Provided by (Used in) Investing Activities	(4,687)	(3,640)
Net Cash Provided by (Used in) Financing Activities	1,369	1,025
Cash and Cash Equivalents, Period Increase (Decrease)	19	(150)
Cash and Cash Equivalents, at Carrying Value	379	377	$ 360	$ 527
Pro Forma [Member]
Net Cash Provided by (Used in) Operating Activities	3,337	2,465
Net Cash Provided by (Used in) Investing Activities	(4,687)	(3,640)
Net Cash Provided by (Used in) Financing Activities	1,369	1,025
Cash and Cash Equivalents, Period Increase (Decrease)	19	(150)
Cash and Cash Equivalents, at Carrying Value	379	377	360	527
Pro Forma [Member] \| Parent Guarantor [Member]
Net Cash Provided by (Used in) Operating Activities	1,657	929
Net Cash Provided by (Used in) Investing Activities	(1,348)	(1,537)
Net Cash Provided by (Used in) Financing Activities	(309)	606
Cash and Cash Equivalents, Period Increase (Decrease)	0	(2)
Cash and Cash Equivalents, at Carrying Value	0	(2)	0	0
Pro Forma [Member] \| Subsidiary Issuer [Member]
Net Cash Provided by (Used in) Operating Activities	802	491
Net Cash Provided by (Used in) Investing Activities	(1,127)	(918)
Net Cash Provided by (Used in) Financing Activities	333	429
Cash and Cash Equivalents, Period Increase (Decrease)	8	2
Cash and Cash Equivalents, at Carrying Value	49	39	41	37
Pro Forma [Member] \| Non-Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities	3,538	2,593
Net Cash Provided by (Used in) Investing Activities	(4,872)	(2,733)
Net Cash Provided by (Used in) Financing Activities	1,345	(10)
Cash and Cash Equivalents, Period Increase (Decrease)	11	(150)
Cash and Cash Equivalents, at Carrying Value	330	340	319	490
Pro Forma [Member] \| Adjustments and eliminations
Net Cash Provided by (Used in) Operating Activities	(2,660)	(1,548)
Net Cash Provided by (Used in) Investing Activities	2,660	1,548
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	Sep. 30, 2017	Dec. 31, 2016
Derivative Liability, Fair Value, Gross Liability	$ (532)	$ (666)
Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	279	362
Assets, Fair Value Disclosure, Recurring	279	362
Interest rate derivatives, Liabilities	(210)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		(1)
Price Risk Derivative Liabilities, at Fair Value	(322)	(472)
Liabilities, Fair Value Disclosure, Recurring	(532)	(666)
Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	263	355
Assets, Fair Value Disclosure, Recurring	263	355
Interest rate derivatives, Liabilities	0	0
Embedded Derivative, Fair Value of Embedded Derivative Liability		0
Price Risk Derivative Liabilities, at Fair Value	(310)	(464)
Liabilities, Fair Value Disclosure, Recurring	(310)	(464)
Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	16	7
Assets, Fair Value Disclosure, Recurring	16	7
Interest rate derivatives, Liabilities	(210)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		0
Price Risk Derivative Liabilities, at Fair Value	(12)	(8)
Liabilities, Fair Value Disclosure, Recurring	(222)	(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	16	14
Price Risk Derivative Liabilities, at Fair Value	(22)	(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	16	14
Price Risk Derivative Liabilities, at Fair Value	(22)	(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	2	2
Price Risk Derivative Liabilities, at Fair Value	(3)	(3)
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	(1)	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	28	96
Price Risk Derivative Liabilities, at Fair Value	(22)	(149)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	28	96
Price Risk Derivative Liabilities, at Fair Value	(22)	(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	3	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	3	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	11	4
Price Risk Derivative Liabilities, at Fair Value	(9)	(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	11	4
Price Risk Derivative Liabilities, at Fair Value	(9)	(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 - Power [Member] \| Put Option [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1
Commodity Derivatives - Power [Member] \| Put Option [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	1
Commodity Derivatives - Power [Member] \| Put Option [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	0
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	213	233
Price Risk Derivative Liabilities, at Fair Value	(261)	(273)
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	213	233
Price Risk Derivative Liabilities, at Fair Value	(261)	(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	2	1
Price Risk Derivative Liabilities, at Fair Value	(2)	(17)
Commodity Derivatives - Refined Products [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	2	1
Price Risk Derivative Liabilities, at Fair Value	(2)	(17)
Commodity Derivatives - Refined Products [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	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	2	9
Price Risk Derivative Liabilities, at Fair Value	(1)	(13)
Commodity Derivatives - Crude [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	2	9
Price Risk Derivative Liabilities, at Fair Value	(1)	(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