Energy Transfer 10-Q 8 Nov 17 2017 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information	9 Months Ended
	Sep. 30, 2017shares
Entity Information [Abstract]
Entity Registrant Name	Energy Transfer, LP
Entity Central Index Key	1,012,569
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	0
Document Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 281	$ 360
Accounts receivable, net	1,351	3,002
Accounts receivable from related companies	798	209
Inventories	679	1,712
Income taxes receivable	151	128
Derivative assets	4	20
Other current assets	156	298
Total current assets	3,420	5,729
Property, plant and equipment	49,651	58,220
Accumulated depreciation and depletion	(7,281)	(7,303)
Property, plant and equipment, net	42,370	50,917
Advances to and investments in unconsolidated affiliates	11,509	4,280
Other non-current assets, net	664	672
Intangible assets, net	3,910	4,696
Goodwill	2,294	3,897
Total assets	64,167	70,191
Current liabilities:
Accounts payable	1,272	2,900
Accounts payable to related companies	314	43
Derivative liabilities	78	166
Accrued and other current liabilities	2,019	1,905
Current maturities of long-term debt	710	1,189
Total current liabilities	4,393	6,203
Long-term debt, less current maturities	25,987	31,741
Long-term notes payable – related company	0	250
Non-current derivative liabilities	132	76
Deferred income taxes	4,237	4,394
Other non-current liabilities	969	952
Commitments and contingencies
Preferred Units	0	33
Redeemable noncontrolling interests	0	15
Equity:
Partner’s capital	25,025	18,634
Accumulated other comprehensive income	14	8
Total partner’s capital	25,039	18,642
Noncontrolling interest	3,410	7,885
Total equity	28,449	26,527
Total liabilities and equity	$ 64,167	$ 70,191

Consolidated Statements Of Oper

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	1,737	1,249	4,762	3,339
Crude sales	3	1,649	3,074	4,572
Gathering, transportation and other fees	1,032	986	3,038	2,991
Refined product sales	0	177	626	656
Other	229	401	1,116	1,141
Total revenues	4,099	5,531	15,748	15,301
COSTS AND EXPENSES:
Cost of products sold	2,568	3,844	10,739	10,280
Operating expenses	382	475	1,290	1,359
Depreciation, depletion and amortization	472	503	1,507	1,469
Selling, general and administrative	87	71	284	226
Total costs and expenses	3,509	4,893	13,820	13,334
OPERATING INCOME	590	638	1,928	1,967
OTHER INCOME (EXPENSE):
Interest expense, net	(334)	(345)	(993)	(981)
Equity in earnings of unconsolidated affiliates	206	65	302	260
Impairment of investment in an unconsolidated affiliate	0	(308)	0	(308)
Losses on interest rate derivatives	(8)	(28)	(28)	(179)
Other, net	69	52	161	96
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	523	74	1,370	855
Income tax expense (benefit)	(120)	(64)	9	(131)
NET INCOME	643	138	1,361	986
Less: Net income attributable to noncontrolling interest	106	64	235	231
Less: Comprehensive income attributable to noncontrolling interest	106	64	235	231
NET INCOME ATTRIBUTABLE TO PARTNERS	$ 537	$ 74	$ 1,126	$ 755

Consolidated Statements Of Comp

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	$ 643	$ 138	$ 1,361	$ 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	650	140	1,367	978
Less: Comprehensive income attributable to noncontrolling interest	106	64	235	231
Less: Net income attributable to noncontrolling interest	106	64	235	231
Comprehensive income attributable to partners	$ 544	$ 76	$ 1,132	$ 747

Consolidated Statement Of Equit

Consolidated Statement Of Equity - 9 months ended Sep. 30, 2017 - USD ($) $ in Millions	Total	Partner’s Capital	Accumulated Other Comprehensive Income	Noncontrolling Interest
Balance, December 31, 2016 at Dec. 31, 2016	$ 26,527	$ 18,634	$ 8	$ 7,885
Distributions to partners	889	(889)	0	0
Distributions to noncontrolling interest	(292)	0	0	292
Units issued for cash	885	885	0	0
Capital contributions from noncontrolling interests	1,895	0	0	1,895
PennTex unit acquisition	(280)	(49)	0	(231)
Sunoco Logistics Merger	(2,769)	4,033	0	(6,802)
Sale of Bakken Pipeline interest	2,000	1,260	0	740
Other comprehensive income, net of tax	6	0	6	0
Other, net	5	(25)	0	20
Net income	1,361	1,126	0	235
Balance, September 30, 2017 at Sep. 30, 2017	$ 28,449	$ 25,025	$ 14	$ 3,410

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
OPERATING ACTIVITIES
Net income	$ 1,361	$ 986
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,507	1,469
Deferred income taxes	(1)	(154)
Amortization included in interest expense	(1)	(16)
Inventory valuation adjustments	(2)	(143)
Unit-based compensation expense	52	60
Impairment of investment in an unconsolidated affiliate	0	308
Distributions on unvested awards	(20)	(19)
Equity in earnings of unconsolidated affiliates	(302)	(260)
Distributions from unconsolidated affiliates	636	292
Other non-cash	(170)	(230)
Net change in operating assets and liabilities, net of effects of acquisition	(337)	172
Net cash provided by operating activities	2,723	2,465
INVESTING ACTIVITIES
Proceeds 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 PennTex noncontrolling interest	(280)	0
Cash paid for all other acquisitions	(142)	(159)
Deconsolidation of Sunoco Logistics	(75)	0
Capital expenditures, excluding allowance for equity funds used during construction	(5,268)	(5,787)
Contributions in aid of construction costs	18	44
Contributions to unconsolidated affiliates	(234)	(47)
Distributions from unconsolidated affiliates in excess of cumulative earnings	111	112
Proceeds from the sale of assets	31	6
Change in restricted cash	0	(8)
Other	(1)	(1)
Net cash used in investing activities	(3,840)	(3,640)
FINANCING ACTIVITIES
Proceeds from borrowings	16,608	13,073
Repayments of long-term debt	(15,864)	(11,308)
Cash paid to affiliate notes	(255)	(1)
Units issued for cash	885	794
Subsidiary units issued for cash	0	1,305
Capital contributions from noncontrolling interest	907	187
Distributions to partners	(889)	(2,669)
Distributions to noncontrolling interest	(292)	(334)
Redemption of Series A Preferred Units	(53)	0
Debt issuance costs	(20)	(22)
Other	11	0
Net cash provided by financing activities	1,038	1,025
Decrease in cash and cash equivalents	(79)	(150)
Cash and cash equivalents, beginning of period	360	527
Cash and cash equivalents, end of period	$ 281	$ 377

Operations And Organization

Operations And Organization	9 Months Ended
	Sep. 30, 2017
Operations And Organization [Abstract]
Operations And Organization	ORGANIZATION AND BASIS OF PRESENTATION Organization Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. Energy Transfer, LP and its subsidiaries are collectively referred to herein as the “Partnership,” “we,” “us,” “our” or “ETLP.” In April 2017, Energy Transfer Partners, L.P. merged with a subsidiary of Sunoco Logistics Partners L.P. (the “ Sunoco Logistics Merger ”), at which time it 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.” Following the completion of the Sunoco Logistics Merger, ETLP has no remaining publicly traded units outstanding. Additionally, subsequent to the Sunoco Logistics Merger, ETLP deconsolidated Sunoco Logistics 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 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 . Our financial statements reflect the following reportable business segments: • intrastate transportation and storage ; • interstate transportation and storage ; • midstream ; • liquids transportation and services ; • investment in ETP ; and • all other . Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in Energy Transfer Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2016 . 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 (Notes)

Acquisitions (Notes)	9 Months Ended
	Sep. 30, 2017
Business Combinations [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. West Texas Gulf Pipe Line Contribution In August 2017, certain wholly-owned subsidiaries of ETP contributed their equity ownership of West Texas Gulf Pipe Line (“WTG”) Company to ETP Holdco. This contribution is considered a transaction between commonly controlled entities and therefore no gain or loss was recognized as a result of the contribution. The months of May and June 2017 have been retrospectively restated to include WTG.

Cash And Cash Equivalents

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 and deconsolidations) included in cash flows from operating activities is comprised as follows: Nine Months Ended 2017 2016 Accounts receivable $ (547 ) $ (595 ) Accounts receivable from related companies (580 ) 80 Inventories 106 (299 ) Other current assets 76 (135 ) Other non-current assets, net (58 ) (1 ) Accounts payable 305 635 Accounts payable to related companies 133 24 Accrued and other current liabilities 177 213 Other non-current liabilities 74 31 Derivative assets and liabilities, net (23 ) 219 Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (337 ) $ 172 Non-cash investing and financing activities are as follows: Nine Months Ended 2017 2016 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 1,098 $ 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

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 $ 474 $ 699 Crude oil — 683 Refined products — 113 Spare parts and other 205 217 Total inventories $ 679 $ 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.

Advances to and Investments in

Advances to and Investments in Affiliates (Notes)	9 Months Ended
	Sep. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
Investments in and Advances to Affiliates, Schedule of Investments [Text Block]	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES Upon the completion of the Sunoco Logistics Merger , the Partnership deconsolidated ETP (formerly Sunoco Logistics). The Partnership holds an equity method investment in ETP due to its ownership of ETP Class E, Class G and Class K units. The Partnership previously had outstanding 8.9 million Class E Units, 90.7 million Class G Units and 101.5 million Class K Units, all of which were held by wholly-owned subsidiaries of the Partnership and were therefore eliminated in the Partnership’s consolidated financial statements. In connection with the Sunoco Logistics Merger, all of the Partnership’s outstanding Class E, Class G and Class K units were cancelled and converted into an equal number of newly created Class E, Class G and Class K units representing limited partner interests in ETP, with the same rights, preferences, privileges, duties and obligations as such classes had immediately prior to the Sunoco Logistics Merger, as described below. Consequently, the ETP Class E, Class G and Class K units are reflected as an equity method investment in ETP by the Partnership subsequent to the Sunoco Logistics Merger. The Partnership’s equity in earnings and cash distributions related to the Class E, Class G and Class K units is as follows: (i) the Class E Units are entitled to aggregate earnings allocation and cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year, (ii) the Class G Units are entitled to earnings allocation equal to ETPs income or loss excluding any income or loss generated by ETP Holdco or its consolidated subsidiaries and aggregate cash distributions equal to 26% of the total amount of cash generated by ETP and its subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class G Unit per year, and (iii) the Class K Units are entitled to aggregate earnings allocation and cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco. The investment in ETP has been recorded in the Partnership’s balance sheet at the historical carrying value as of the date of the Sunoco Logistics Merger. The following table presents aggregated selected income statement data for ETP and Citrus (on a 100% basis for all periods presented): Three Months Ended Nine Months Ended 2017 2016 2017 2016 ETP Revenue $ 6,973 $ 5,531 $ 20,444 $ 15,301 Operating income 825 638 2,211 1,967 Net income 761 138 1,417 986 Citrus Revenue $ 225 $ 223 $ 634 $ 628 Operating income 143 140 383 381 Net income 72 62 173 160 The Partnership has other equity method investments which were not, individually or in the aggregate, significant to our consolidated financial statements.

Fair Value Measurements

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 was $28.09 billion and $26.71 billion , respectively. As of December 31, 2016 , the aggregate fair value and carrying amount of our consolidated debt obligations was $33.85 billion and $32.93 billion , respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the 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 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 179 179 — Crude – Futures 2 2 — Total commodity derivatives 243 227 16 Total assets $ 243 $ 227 $ 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 (213 ) (213 ) — Crude – Futures (1 ) (1 ) — Total commodity derivatives (272 ) (260 ) (12 ) Total liabilities $ (482 ) $ (260 ) $ (222 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 14 $ 14 $ — $ — Swing Swaps IFERC 2 — 2 — Fixed Swaps/Futures 96 96 — — Forward Physical Swaps 1 — 1 — Power: Forwards 4 — 4 — Futures 1 1 — — Options – Calls 1 1 — — Natural Gas Liquids – Forwards/Swaps 233 233 — — Refined Products – Futures 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 )

Debt Obligations

Debt Obligations	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
Debt Obligations	DEBT OBLIGATIONS ETP Senior Notes Redemption In October 2017, ETP 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 . 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. 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)

Preferred Units (Notes)	9 Months Ended
	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

Equity	9 Months Ended
	Sep. 30, 2017
Partners' Capital Notes [Abstract]
Equity	EQUITY In connection with the Sunoco Logistics 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. Common Units Upon the completion of the Sunoco Logistics Merger , the Partnership’s equity distribution program, distribution reinvestment program and equity incentive plans have been terminated. Bakken Equity Sale In February 2017, Bakken Holdings Company LLC, an entity in which ETLP indirectly owns a 60% membership interest and ETP indirectly owns a 40% 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, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”). The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETLP 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. 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

Income Taxes (Notes)

Income Taxes (Notes)	9 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	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

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 Nine Months Ended 2017 2016 2017 2016 Rental expense $ 19 $ 19 $ 53 $ 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 ETLP 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 ETLP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETLP. The jury also found that ETLP owed Enterprise approximately $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETLP and awarded ETLP $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. 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. 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. 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 $ 28 $ 26 Non-current 275 283 Total environmental liabilities $ 303 $ 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 Liabiliti

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 liquids transportation and services segment to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. 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 (4,647,000 ) 2017-2019 (5,786,627 ) 2017 Refined Products (Bbls) – Futures — — (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 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 14 24 (10 ) (52 ) Interest rate derivatives — — (210 ) (193 ) Embedded derivatives in Preferred Units — — — (1 ) 236 362 (482 ) (662 ) Total derivatives $ 243 $ 362 $ (482 ) $ (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) 14 24 (10 ) (52 ) Broker cleared derivative contracts Other current assets 229 338 (262 ) (420 ) Total gross derivatives 243 362 (482 ) (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 $ 13 $ 20 $ (252 ) $ (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 Nine Months Ended 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 Nine Months Ended 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 (42 ) (14 ) (44 ) (57 ) Interest rate derivatives Losses on interest rate derivatives (8 ) (28 ) (28 ) (179 ) Embedded derivatives Other, net — 8 1 4 Total $ (55 ) $ (42 ) $ (50 ) $ (256 )

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2017
Related Party Transactions [Abstract]
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 Nine Months Ended 2017 2016 2017 2016 Affiliated revenues $ 179 $ 63 $ 344 $ 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 ETP 484 — Sunoco LP 192 96 FGT 15 15 Other 107 76 Total accounts receivable from related companies: $ 798 $ 209 Accounts payable to related companies: ETP $ 136 $ — Sunoco LP 178 20 Other — 23 Total accounts payable to related companies: $ 314 $ 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

Reportable Segments	9 Months Ended
	Sep. 30, 2017
Reportable Segments [Abstract]
Reportable Segments	REPORTABLE SEGMENTS 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 ; • liquids transportation and services ; • investment in ETP ; and • all other . As discussed in Note 1 , Sunoco Logistics changed its name to ETP upon the completion of the Sunoco Logistics Merger. Accordingly, the reportable segment previously named “Investment in Sunoco Logistics” has been renamed “Investment in ETP.” For periods prior to the Sunoco Logistics Merger, this reportable segment reflects the consolidated results of Sunoco Logistics. For periods subsequent to the Sunoco Logistics Merger, this segment reflects the investments in ETP’s Class E, Class G and Class K units that continue to be held by the Partnership’s subsidiaries, which are accounted for under the equity method. 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 ETLP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETLP 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 liquids transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our investment in ETP 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 Nine Months Ended 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 639 582 1,873 1,799 Intersegment revenues 1,128 761 3,144 1,966 1,767 1,343 5,017 3,765 Liquids transportation and services: Revenues from external customers 1,790 1,099 4,664 3,027 Intersegment revenues 22 113 203 214 1,812 1,212 4,867 3,241 Investment in ETP: Revenues from external customers 22 2,154 4,216 6,133 Intersegment revenues — 35 44 101 22 2,189 4,260 6,234 All other: Revenues from external customers 699 882 2,147 2,171 Intersegment revenues 19 74 138 350 718 956 2,285 2,521 Eliminations (1,217 ) (1,163 ) (3,689 ) (3,046 ) Total revenues $ 4,099 $ 5,531 $ 15,748 $ 15,301 Three Months Ended Nine Months Ended 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 Liquids transportation and services 449 240 1,032 687 Investment in ETP 182 312 724 906 All other 153 113 366 395 Total 1,576 1,390 4,490 4,172 Depreciation, depletion and amortization (472 ) (503 ) (1,507 ) (1,469 ) Interest expense, net (334 ) (345 ) (993 ) (981 ) Losses on interest rate derivatives (8 ) (28 ) (28 ) (179 ) Non-cash unit-based compensation expense (15 ) (22 ) (52 ) (60 ) Unrealized gains (losses) on commodity risk management activities (69 ) (15 ) 29 (96 ) Inventory valuation adjustments — 37 2 143 Adjusted EBITDA related to unconsolidated affiliates (430 ) (240 ) (1,016 ) (711 ) Equity in earnings of unconsolidated affiliates 206 65 302 260 Impairment of investment in an unconsolidated affiliate — (308 ) — (308 ) Other, net 69 43 143 84 Income before income tax (expense) benefit $ 523 $ 74 $ 1,370 $ 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 18,011 Liquids transportation and services 12,553 11,296 Investment in ETP 8,368 18,819 All other 6,092 6,068 Total assets $ 64,167 $ 70,191

Operations And Organization Acc

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 (Tabl

Cash And Cash Equivalents (Tables)	9 Months Ended
	Sep. 30, 2017
Cash and Cash Equivalents [Abstract]
Net Cash Provided By Operating Activities	Nine Months Ended 2017 2016 Accounts receivable $ (547 ) $ (595 ) Accounts receivable from related companies (580 ) 80 Inventories 106 (299 ) Other current assets 76 (135 ) Other non-current assets, net (58 ) (1 ) Accounts payable 305 635 Accounts payable to related companies 133 24 Accrued and other current liabilities 177 213 Other non-current liabilities 74 31 Derivative assets and liabilities, net (23 ) 219 Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ (337 ) $ 172
Non-Cash Investing And Financing Activities	Nine Months Ended 2017 2016 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 1,098 $ 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)

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 $ 474 $ 699 Crude oil — 683 Refined products — 113 Spare parts and other 205 217 Total inventories $ 679 $ 1,712

Advances to and Investments i24

Advances to and Investments in Affiliates (Tables)	9 Months Ended
	Sep. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments [Table Text Block]	The following table presents aggregated selected income statement data for ETP and Citrus (on a 100% basis for all periods presented): Three Months Ended Nine Months Ended 2017 2016 2017 2016 ETP Revenue $ 6,973 $ 5,531 $ 20,444 $ 15,301 Operating income 825 638 2,211 1,967 Net income 761 138 1,417 986 Citrus Revenue $ 225 $ 223 $ 634 $ 628 Operating income 143 140 383 381 Net income 72 62 173 160

Fair Value Measurements (Tables

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	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 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 179 179 — Crude – Futures 2 2 — Total commodity derivatives 243 227 16 Total assets $ 243 $ 227 $ 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 (213 ) (213 ) — Crude – Futures (1 ) (1 ) — Total commodity derivatives (272 ) (260 ) (12 ) Total liabilities $ (482 ) $ (260 ) $ (222 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Level 3 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 14 $ 14 $ — $ — Swing Swaps IFERC 2 — 2 — Fixed Swaps/Futures 96 96 — — Forward Physical Swaps 1 — 1 — Power: Forwards 4 — 4 — Futures 1 1 — — Options – Calls 1 1 — — Natural Gas Liquids – Forwards/Swaps 233 233 — — Refined Products – Futures 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 )

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2017
Accumulated Other Comprehensive Income	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, Commitmen27

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]	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 Nine Months Ended 2017 2016 2017 2016 Rental expense $ 19 $ 19 $ 53 $ 58
Environmental Exit Costs by Cost [Table Text Block]	The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements. September 30, 2017 December 31, 2016 Current $ 28 $ 26 Non-current 275 283 Total environmental liabilities $ 303 $ 309

Derivative Assets And Liabili28

Derivative Assets And Liabilities (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative [Line Items]
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 (4,647,000 ) 2017-2019 (5,786,627 ) 2017 Refined Products (Bbls) – Futures — — (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 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 14 24 (10 ) (52 ) Interest rate derivatives — — (210 ) (193 ) Embedded derivatives in Preferred Units — — — (1 ) 236 362 (482 ) (662 ) Total derivatives $ 243 $ 362 $ (482 ) $ (666 )
Derivatives, Offsetting Fair Value Amounts [Table Text Block]	The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: Asset Derivatives Liability Derivatives Balance Sheet Location 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) 14 24 (10 ) (52 ) Broker cleared derivative contracts Other current assets 229 338 (262 ) (420 ) Total gross derivatives 243 362 (482 ) (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 $ 13 $ 20 $ (252 ) $ (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 Nine Months Ended 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 Nine Months Ended 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 (42 ) (14 ) (44 ) (57 ) Interest rate derivatives Losses on interest rate derivatives (8 ) (28 ) (28 ) (179 ) Embedded derivatives Other, net — 8 1 4 Total $ (55 ) $ (42 ) $ (50 ) $ (256 )

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2017
Related Party Transactions [Abstract]
Related Party Transactions For Period Presented [Table Text Block]	The following table summarizes the affiliate revenues on our consolidated statements of operations: Three Months Ended Nine Months Ended 2017 2016 2017 2016 Affiliated revenues $ 179 $ 63 $ 344 $ 270
Related Party Transactions [table text block]	September 30, 2017 December 31, 2016 Accounts receivable from related companies: ETE $ — $ 22 ETP 484 — Sunoco LP 192 96 FGT 15 15 Other 107 76 Total accounts receivable from related companies: $ 798 $ 209 Accounts payable to related companies: ETP $ 136 $ — Sunoco LP 178 20 Other — 23 Total accounts payable to related companies: $ 314 $ 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)

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 Nine Months Ended 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 639 582 1,873 1,799 Intersegment revenues 1,128 761 3,144 1,966 1,767 1,343 5,017 3,765 Liquids transportation and services: Revenues from external customers 1,790 1,099 4,664 3,027 Intersegment revenues 22 113 203 214 1,812 1,212 4,867 3,241 Investment in ETP: Revenues from external customers 22 2,154 4,216 6,133 Intersegment revenues — 35 44 101 22 2,189 4,260 6,234 All other: Revenues from external customers 699 882 2,147 2,171 Intersegment revenues 19 74 138 350 718 956 2,285 2,521 Eliminations (1,217 ) (1,163 ) (3,689 ) (3,046 ) Total revenues $ 4,099 $ 5,531 $ 15,748 $ 15,301
Operating Segments [Member]
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Three Months Ended Nine Months Ended 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 Liquids transportation and services 449 240 1,032 687 Investment in ETP 182 312 724 906 All other 153 113 366 395 Total 1,576 1,390 4,490 4,172 Depreciation, depletion and amortization (472 ) (503 ) (1,507 ) (1,469 ) Interest expense, net (334 ) (345 ) (993 ) (981 ) Losses on interest rate derivatives (8 ) (28 ) (28 ) (179 ) Non-cash unit-based compensation expense (15 ) (22 ) (52 ) (60 ) Unrealized gains (losses) on commodity risk management activities (69 ) (15 ) 29 (96 ) Inventory valuation adjustments — 37 2 143 Adjusted EBITDA related to unconsolidated affiliates (430 ) (240 ) (1,016 ) (711 ) Equity in earnings of unconsolidated affiliates 206 65 302 260 Impairment of investment in an unconsolidated affiliate — (308 ) — (308 ) Other, net 69 43 143 84 Income before income tax (expense) benefit $ 523 $ 74 $ 1,370 $ 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 18,011 Liquids transportation and services 12,553 11,296 Investment in ETP 8,368 18,819 All other 6,092 6,068 Total assets $ 64,167 $ 70,191

Operations And Organization Ope

Operations And Organization Operations And Organization (Details)	9 Months Ended
	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%

Acquisitions (Details)

Acquisitions (Details) - Rover Contribution [Member]	1 Months Ended
	Oct. 31, 2017	Jul. 31, 2017
ETP [Member] | Holdco [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		49.90%
Holdco [Member] | Rover Pipeline LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		65.00%
Subsequent Event [Member] | ETP [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.10%
Subsequent Event [Member] | Blackstone [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	49.90%

Cash And Cash Equivalents Net C

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	$ (547)	$ (595)
Accounts receivable from related companies	(580)	80
Inventories	106	(299)
Other current assets	76	(135)
Other non-current assets, net	(58)	(1)
Accounts payable	305	635
Accounts payable to related companies	133	24
Accrued and other current liabilities	177	213
Other non-current liabilities	74	31
Derivative assets and liabilities, net	(23)	219
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$ (337)	$ 172

Cash And Cash Equivalents Non-C

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	$ 1,098	$ 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:
Contribution of property, plant and equipment from noncontrolling interest	$ 988	$ 0

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Inventory, Gross [Abstract]
Natural gas and NGLs	$ 474	$ 699
Crude oil	0	683
Refined products	0	113
Spare parts and other	205	217
Total inventories	$ 679	$ 1,712

Advances to and Investments i36

Advances to and Investments in Affiliates (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	Apr. 30, 2017
Schedule of Equity Method Investments [Line Items]
Revenues	$ 4,099	$ 5,531	$ 15,748	$ 15,301
OPERATING INCOME	590	638	1,928	1,967
Net income	$ 643	138	$ 1,361	986
Class E Unit Distribution Rate	11.10%		11.10%
Class E Unit Maximum Distribution	$ 1.41		$ 1.41
Class G Unit Distribution Rate	26.00%		26.00%
ETP [Member]
Schedule of Equity Method Investments [Line Items]
Revenues	$ 6,973	5,531	$ 20,444	15,301
OPERATING INCOME	825	638	2,211	1,967
Net income	761	138	1,417	986
Citrus [Member]
Schedule of Equity Method Investments [Line Items]
Revenues	225	223	634	628
OPERATING INCOME	143	140	383	381
Net income	$ 72	$ 62	$ 173	$ 160
Class E Units [Member]
Schedule of Equity Method Investments [Line Items]
Partners' Capital Account, Units					8.9
Class G Units [Member]
Schedule of Equity Method Investments [Line Items]
Partners' Capital Account, Units					90.7
Class G Unit Maximum Distribution	$ 3.75		$ 3.75
Class K Units [Member]
Schedule of Equity Method Investments [Line Items]
Partners' Capital Account, Units					101.5
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.67275

Fair Value Measurements Narrati

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	28,090	$ 33,850
Long-term Debt	$ 26,710	$ 32,930

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Heigharchy (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Derivative Liability, Fair Value, Gross Liability	$ (482)	$ (666)
Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	243	362
Assets, Fair Value Disclosure, Recurring	243	362
Interest rate derivatives, Liabilities	(210)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		(1)
Price Risk Derivative Liabilities, at Fair Value	(272)	(472)
Liabilities, Fair Value Disclosure, Recurring	(482)	(666)
Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	227	355
Assets, Fair Value Disclosure, Recurring	227	355
Interest rate derivatives, Liabilities	0	0
Embedded Derivative, Fair Value of Embedded Derivative Liability		0
Price Risk Derivative Liabilities, at Fair Value	(260)	(464)
Liabilities, Fair Value Disclosure, Recurring	(260)	(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	1
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	1	1
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	1
Price Risk Derivative Liabilities, at Fair Value	(1)	(1)
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	1	1
Price Risk Derivative Liabilities, at Fair Value	1	(1)
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	179	233
Price Risk Derivative Liabilities, at Fair Value	(213)	(273)
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	179	233
Price Risk Derivative Liabilities, at Fair Value	213	(273)
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(17)
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(17)
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
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

Debt Obligations Narrative (Det

Debt Obligations Narrative (Details) - USD ($) $ in Millions	1 Months Ended
	Oct. 31, 2017	Sep. 30, 2017
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
Bakken Pipeline [Member] | Bakken Term Note [Member]
Line of Credit Facility, Maximum Borrowing Capacity		2,500
PennTex $275 million Revolving Credit Facility due December 2019 [Member] | PennTex [Member]
Line of Credit Facility, Current Borrowing Capacity		275
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]
Early Repayment of Senior Debt	$ 500
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Subsequent Event [Member] | 5.5% Senior Notes, due April 15, 2023 [Member]
Early Repayment of Senior Debt	$ 700
Debt Instrument, Interest Rate, Stated Percentage	5.50%

Preferred Units (Details)

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 Preferred Units [Member]
Partners' Capital Account, Units, Redeemed	1.9

Equity Narrative (Details)

Equity Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Feb. 28, 2017	Sep. 30, 2017	Feb. 01, 2017
PennTex [Member]
Sale of Stock, Price Per Share		$ 20
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross	$ 2,000
ETLP [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	60.00%
Bakken Pipeline Investments LLC [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired			49.00%
Dakota Access and ETCOC [Member] | Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	25.00%
Dakota Access and ETCOC [Member] | Bakken Pipeline Investments LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	75.00%

Equity AOCI (Details)

Equity AOCI (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	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)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	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, Commitmen44

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2012USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)
Maximum lease expiration year				Dec. 31, 2034
Amounts recorded in balance sheets for contingencies and current litigation not disclosed		$ 0		$ 0
Accrual for Environmental Loss Contingencies		$ 303,000,000		$ 303,000,000		$ 309,000,000
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
Rover Pipeline LLC [Member]
Sites where remediation operations are responsibility of third parties		27		27
Proposed Environmental Penalty		$ 2,300,000		$ 2,300,000
Sunoco [Member]
Sites where remediation operations are responsibility of third parties		44		44
Related To Deductibles [Member]
Loss Contingency Accrual		$ 66,000,000		$ 66,000,000		$ 77,000,000
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
Disgorgement [Member]
Gain Contingency, Unrecorded Amount		$ 595,000,000		$ 595,000,000
Multidistrict Legislation [Member] | Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number		4		4
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount		$ 319,000,000		$ 319,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount		1,000,000		1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount		$ 536,000,000		$ 536,000,000

Regulatory Matters, Commitmen45

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	$ 19	$ 19	$ 53	$ 58

Regulatory Matters, Commitmen46

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	$ 28	$ 26
Non-current	275	283
Total environmental liabilities	$ 303	$ 309

Derivative Assets And Liabili47

Derivative Assets And Liabilities Outstanding Commodity Derivatives (Details)		9 Months Ended	12 Months Ended
		Sep. 30, 2017MMbtubarrelsMegawattbbl	Dec. 31, 2016MMbtubarrelsMegawattbbl
WTI Crude Oil [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
WTI Crude Oil [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | bbl		160,000	617,000
Natural Gas Liquids [Member] | Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2,017
Natural Gas Liquids [Member] | Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | bbl		4,647,000	5,786,627
Power [Member] | Forwards Swaps [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume | Megawatt		665,040	391,880
Power [Member] | Forwards Swaps [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Power [Member] | Forwards Swaps [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,018	2,018
Power [Member] | Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2,017
Power [Member] | Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume | Megawatt		545,600	186,400
Power [Member] | Options - Calls [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017
Power [Member] | Options - Calls [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,018
Power [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | Megawatt		213,840
Power [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume | Megawatt			109,564
Power [Member] | Future [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Power [Member] | Future [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,018	2,018
Power [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2,017
Power [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | Megawatt		280,800	50,400
Power [Member] | Options - Puts [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017
Power [Member] | Options - Puts [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,018
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		20,220,000	52,652,500
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member]
Notional Volume		41,102,500	36,370,000
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2,017
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume			682,500
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		1,297,500
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Minimum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Maximum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,019	2,019
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,018
Natural Gas [Member] | Forward Physical Swaps [Member] | Minimum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017
Natural Gas [Member] | Forward Physical Swaps [Member] | Maximum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,018
Natural Gas [Member] | Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2,017
Natural Gas [Member] | Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		140,937,993	22,492,489
Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Long [Member]
Notional Volume		41,102,500	36,370,000
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		67,500	10,750,000
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member]
Notional Volume		41,102,500	36,370,000
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives	[1]		2,017
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume	[1]	15,810,000
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume	[1]		2,242,500
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Minimum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017	2,017
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Maximum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,020	2,018
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,019
Natural Gas [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2,017
Natural Gas [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume			5,662,500
Natural Gas [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		91,897,500
Natural Gas [Member] | Swing Swaps IFERC [Member] | Minimum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017
Natural Gas [Member] | Swing Swaps IFERC [Member] | Maximum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,019
Natural Gas [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,018
Natural Gas [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		13,000,000	0
Natural Gas [Member] | Options - Puts [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,017
Natural Gas [Member] | Options - Puts [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2,019
Refined Products [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2,017
Refined Products [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | barrels		0	2,240,000
[1]	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Derivative Assets And Liabili48

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
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	0
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.52% 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%
March 2019 [Member]
Notional Amount		$ 300	$ 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 Liabili49

Derivative Assets And Liabilities Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Total derivatives assets	$ 243	$ 362
Total derivatives liabilities	(482)	(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	236	362
Total derivatives liabilities	(482)	(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	14	24
Total derivatives liabilities	10	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 Liabili50

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	$ 243	$ 362
Derivative Liability, Fair Value, Gross Liability	(482)	(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	13	20
Derivative Liability, Fair Value, Net	(252)	(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	14	24
Derivative Liability, Fair Value, Gross Liability	10	(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 Liabili51

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 Liabili52

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	(55)	(42)	(50)	(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	(42)	(14)	(44)	(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 Affi

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	$ 179	$ 63	$ 344	$ 270

Related Party Transactions Rela

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:	$ 798	$ 209
Total accounts payable to related companies:	314	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
ETP [Member]
Total accounts receivable from related companies:	484	0
Total accounts payable to related companies:	136	0
Sunoco LP
Notes Receivable, Related Parties, Noncurrent	85	87
Total accounts receivable from related companies:	192	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:	107	76
Total accounts payable to related companies:	0	23
Phillips 66 Partners LP [Member]
Long-term notes payable – related companies	$ 0	$ (250)

Reportable Segments Reportable

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

Reportable Segments Segment Rev

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	$ 4,099	$ 5,531	$ 15,748	$ 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	1,767	1,343	5,017	3,765
Midstream | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	639	582	1,873	1,799
Midstream | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	1,128	761	3,144	1,966
Liquids transportation and services
Segment Reporting Information [Line Items]
Revenues	1,812	1,212	4,867	3,241
Liquids transportation and services | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	1,790	1,099	4,664	3,027
Liquids transportation and services | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	22	113	203	214
Investment in ETP
Segment Reporting Information [Line Items]
Revenues	22	2,189	4,260	6,234
Investment in ETP | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	22	2,154	4,216	6,133
Investment in ETP | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	0	35	44	101
All other
Segment Reporting Information [Line Items]
Revenues	718	956	2,285	2,521
All other | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	699	882	2,147	2,171
All other | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	19	74	138	350
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (1,217)	$ (1,163)	$ (3,689)	$ (3,046)

Reportable Segments Segment Adj

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	$ 1,576	$ 1,390	$ 4,490	$ 4,172
Depreciation, depletion and amortization	(472)	(503)	(1,507)	(1,469)
Interest expense, net	(334)	(345)	(993)	(981)
Losses on interest rate derivatives	(8)	(28)	(28)	(179)
Non-cash unit-based compensation expense	(15)	(22)	(52)	(60)
Unrealized gains (losses) on commodity risk management activities	(69)	(15)	29	(96)
Inventory valuation adjustments	0	37	2	143
Adjusted EBITDA related to unconsolidated affiliates	(430)	(240)	(1,016)	(711)
Equity in earnings of unconsolidated affiliates	206	65	302	260
Impairment of investment in an unconsolidated affiliate	0	308	0	308
Other, net	69	43	143	84
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	523	74	1,370	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
Liquids transportation and services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	449	240	1,032	687
Investment in ETP
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	182	312	724	906
All other
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 153	$ 113	$ 366	$ 395

Reportable Segments Segment Ass

Reportable Segments Segment Assets (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Assets	$ 64,167	$ 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	18,011
Liquids transportation and services
Segment Reporting Information [Line Items]
Assets	12,553	11,296
Investment in ETP
Segment Reporting Information [Line Items]
Assets	8,368	18,819
All other
Segment Reporting Information [Line Items]
Assets	$ 6,092	$ 6,068