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Document And Entity Information - shares	9 Months Ended
Document And Entity Information - shares	Sep. 30, 2018	Nov. 02, 2018
Entity Information [Abstract]
Entity Registrant Name	Energy Transfer Operating, L.P.
Entity Central Index Key	0001161154
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		0
Document Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Entity Emerging Growth Company	false
Entity Small Business	false

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 379	$ 306
Accounts receivable, net	3,671	3,946
Accounts receivable from related companies	333	318
Inventories	1,507	1,589
Income taxes receivable	169	135
Derivative assets	93	24
Other current assets	201	210
Total current assets	6,353	6,528
Property, plant and equipment	70,966	67,699
Accumulated depreciation and depletion	(10,416)	(9,262)
Property, Plant and Equipment, Net	60,550	58,437
Advances to and investments in unconsolidated affiliates	3,599	3,816
Other non-current assets, net	863	758
Intangible assets, net	4,925	5,311
Goodwill	2,866	3,115
Total assets	79,156	77,965
Current liabilities:
Accounts payable	3,381	4,126
Accounts payable to related companies	287	209
Derivative liabilities	338	109
Accrued and other current liabilities	2,603	2,143
Current maturities of long-term debt	2,649	407
Total current liabilities	9,258	6,994
Long-term debt, less current maturities	31,198	32,687
Non-current derivative liabilities	57	145
Deferred income taxes	2,845	2,883
Other non-current liabilities	1,100	1,084
Commitments and contingencies
Redeemable noncontrolling interests	22	21
Equity:
Common Unitholders	25,628	26,531
General Partner	340	244
Accumulated other comprehensive income	8	3
Total partners’ capital	28,342	28,269
Noncontrolling interest	6,334	5,882
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	34,676	34,151
Total liabilities and equity	79,156	77,965
Series A Preferred Units [Member]
Equity:
Preferred units	944	944
Series B Preferred Units [Member]
Equity:
Preferred units	547	547
Series C Preferred Units [Member]
Equity:
Preferred units	439	0
Series D Preferred Units [Member]
Equity:
Preferred units	$ 436	$ 0

Consolidated Statements Of Operations - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
REVENUES:
Total revenues	$ 9,641	$ 6,973	$ 27,331	$ 20,444
COSTS AND EXPENSES:
Cost of products sold	6,745	4,922	19,873	14,595
Operating expenses	632	571	1,863	1,603
Depreciation, depletion and amortization	636	596	1,827	1,713
Selling, general and administrative	123	105	347	335
Total costs and expenses	8,136	6,194	23,910	18,246
OPERATING INCOME	1,505	779	3,421	2,198
OTHER INCOME (EXPENSE):
Interest expense, net	(387)	(352)	(1,091)	(1,020)
Equity in earnings of unconsolidated affiliates	113	127	147	139
Gain on Sunoco LP common unit repurchase	0	0	172	0
Loss on deconsolidation of CDM	0	0	(86)	0
Gains (losses) on interest rate derivatives	45	(8)	117	(28)
Other, net	21	57	127	137
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	1,297	603	2,807	1,426
Income tax expense (benefit)	(61)	(112)	(32)	22
NET INCOME	1,358	715	2,839	1,404
Less: Net income attributable to noncontrolling interest	223	110	557	266
NET INCOME ATTRIBUTABLE TO PARTNERS	1,135	605	2,282	1,138
Natural gas sales [Member]
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	1,026	1,098	3,112	3,132
NGL sales [Member]
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	2,695	1,750	6,866	4,782
Oil and Gas [Member]
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	3,841	2,381	11,336	7,268
Natural Gas, Midstream [Member]
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	1,579	1,027	4,440	3,118
Oil and Gas, Refining and Marketing [Member]
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	382	334	1,234	1,109
Product and Service, Other [Member]
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	$ 118	$ 383	$ 343	$ 1,035

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income	$ 1,358	$ 715	$ 2,839	$ 1,404
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	2	2	0	5
Actuarial gain (loss) relating to pension and other postretirement benefit plans	0	5	(2)	2
Change in other comprehensive income from unconsolidated affiliates	2	0	9	(1)
Total other comprehensive income (loss)	4	7	7	6
Comprehensive income	1,362	722	2,846	1,410
Less: Comprehensive income attributable to noncontrolling interest	223	110	557	266
Comprehensive income attributable to partners	$ 1,139	$ 612	$ 2,289	$ 1,144

Consolidated Statement Of Equity - 9 months ended Sep. 30, 2018 - USD ($) $ in Millions	Total	Series A Preferred Units [Member]	Series B Preferred Units [Member]	Series C Preferred Units [Member]	Series D Preferred Units [Member]	Common Units	General Partner	AOCI	Noncontrolling Interest
Balance, December 31, 2017 at Dec. 31, 2017	$ 34,151	$ 944	$ 547	$ 0	$ 0	$ 26,531	$ 244	$ 3	$ 5,882
Distributions to partners	(3,136)	(44)	(27)	(10)	0	(1,975)	(1,080)	0	0
Distributions to noncontrolling interest	(536)	0	0	0	0	0	0	0	(536)
Units issued for cash	925	0	0	436	431	58	0	0	0
Capital contributions from noncontrolling interest	438	0	0	0	0	0	0	0	438
Repurchases of common units	(24)	0	0	0	0	(24)	0	0	0
Other comprehensive income, net of tax	7	0	0	0	0	0	0	7	0
Other, net	12	1	0	1	1	41	17	(2)	(7)
Net income	2,839	45	27	14	6	997	1,193	0	557
Balance, September 30, 2018 at Sep. 30, 2018	$ 34,676	$ 944	$ 547	$ 439	$ 436	$ 25,628	$ 340	$ 8	$ 6,334

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

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+ Details

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
OPERATING ACTIVITIES
Net income	$ 2,839	$ 1,404
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,827	1,713
Deferred income taxes	(17)	(1)
Non-cash compensation expense	61	57
Gain on Sunoco LP common unit repurchase	(172)	0
Loss on deconsolidation of CDM	86	0
Distributions on unvested awards	(24)	(21)
Equity in earnings of unconsolidated affiliates	(147)	(139)
Distributions from unconsolidated affiliates	328	319
Other non-cash	(132)	(163)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	451	168
Net cash provided by operating activities	5,100	3,337
INVESTING ACTIVITIES
Proceeds from Divestiture of Businesses	1,227	0
Cash proceeds from Bakken pipeline transaction	0	2,000
Cash proceeds from Sunoco LP common unit repurchase	540	0
Cash paid for acquisition of PennTex noncontrolling interest	0	(280)
Cash paid for all other acquisitions	29	264
Capital expenditures, excluding allowance for equity funds used during construction	(4,962)	(6,074)
Contributions in aid of construction costs	95	18
Contributions to unconsolidated affiliates	(13)	(230)
Distributions from unconsolidated affiliates in excess of cumulative earnings	62	116
Proceeds from the sale of assets	13	33
Other	0	(6)
Net cash used in investing activities	(3,067)	(4,687)
FINANCING ACTIVITIES
Proceeds from borrowings	16,930	19,978
Repayments of debt	(16,520)	(18,487)
Cash paid to affiliate notes	0	(255)
Common units issued for cash	58	2,162
Preferred units issued for cash	867	0
Capital contributions from noncontrolling interest	438	919
Distributions to partners	(3,136)	(2,543)
Distributions to noncontrolling interest	(536)	(306)
Payments for Repurchase of Common Stock	24	0
Redemption of Legacy ETP Preferred Units	0	(53)
Debt issuance costs	42	50
Other	5	4
Net cash (used in) provided by financing activities	(1,960)	1,369
Increase in cash and cash equivalents	73	19
Cash and cash equivalents, beginning of period	306	360
Cash and cash equivalents, end of period	$ 379	$ 379

Operations And Basis of Presentation

9 Months Ended

Sep. 30, 2018

Operations And Organization [Abstract]

Operations And Organization

ORGANIZATION AND BASIS OF PRESENTATION

Organization

Energy Transfer Operating, L.P. is a consolidated subsidiary of Energy Transfer LP. In October 2018, Energy Transfer Equity, L.P. (“ETE”) and Energy Transfer Partners, L.P. (“ETP”) completed the merger of ETP with a wholly-owned subsidiary of ETE in a unit-for-unit exchange (the “ETE-ETP Merger”). In connection with the transaction, ETP unitholders (other than ETE and its subsidiaries) received 1.28 common units of ETE for each common unit of ETP they owned.

Immediately prior to the closing of the ETE-ETP Merger, the following also occurred:


•	the IDRs in ETP were converted into 1,168,205,710 ETP common units; and


•	the general partner interest in ETP was converted to a non-economic general partner interest and ETP issued 18,448,341 ETP common units to ETP GP.

Following the closing of the ETE-ETP Merger, ETE changed its name to “Energy Transfer LP” and its common units began trading on the New York Stock Exchange under the “ET” ticker symbol on Friday, October 19, 2018. In addition, ETP changed its name to “Energy Transfer Operating, L.P.” For purposes of maintaining clarity, the following references are used herein:


•	References to “ETP” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the ETE-ETP Merger and Energy Transfer Operating, L.P. subsequent to the close of the ETE-ETP Merger; and


•	References to “ETE” refer to the entity named Energy Transfer Equity, L.P. prior to the close of the ETE-ETP Merger and Energy Transfer LP subsequent to the close of the ETE-ETP Merger.

In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction (the “Sunoco Logistics Merger”), with the Energy Transfer Partners, L.P. unitholders receiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. In connection with the Sunoco Logistics Merger, Sunoco Logistics was renamed Energy Transfer Partners, L.P. and Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.

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

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, Colorado and Ohio.


•	Energy Transfer Interstate Holdings, LLC, (“ETIH”) with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales, which 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 Fayetteville Express Pipeline, LLC, which directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.


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


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


•	ETC Midcontinent Express Pipeline, L.L.C., which directly owns a 50% interest in MEP.


•	ET Rover Pipeline, LLC, which ETIH directly owns a 50.1% interest in, which owns a 65% interest in the Rover pipeline.


•	ETC Compression, LLC, engaged in natural gas compression services and related equipment sales. As discussed further in Note 2 below, in April 2018, we contributed certain assets to USAC.

•

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.’s assets primarily consist of its ownership in Retail Holdings, which owns noncontrolling interests in Sunoco LP and PES. ETP Holdco also holds an equity method investment in ETP through its ownership of ETP Class E, Class G, and Class K units, which investment is eliminated in ETP’s consolidated financial statements.


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

Our consolidated financial statements reflect the following reportable business segments:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services; and

•all other.

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

Basis of Presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements of Energy Transfer Partners, L.P. for the year ended December 31, 2017, included in the Partnership’s Annual Report on Form 10-K filed with the SEC on February 23, 2018. 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.

The historical common unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.

Change in Accounting Policy

Inventory Accounting Change

During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity.

As a result of this change in accounting policy, the consolidated statement of operations and comprehensive income in prior periods have been retrospectively adjusted, as follows:



	Three Months Ended September 30, 2017							Nine Months Ended September 30, 2017
	As Originally Reported		Effect of Change			As Adjusted		As Originally Reported		Effect of Change			As Adjusted
Cost of products sold	$	4,876	$	46		$	4,922	$	14,582	$	13		$	14,595
Operating income	825		(46		)	779		2,211		(13		)	2,198
Income before income tax expense (benefit)	649		(46		)	603		1,439		(13		)	1,426
Net income	761		(46		)	715		1,417		(13		)	1,404
Net income attributable to partners	651		(46		)	605		1,174		(36		)	1,138
Comprehensive income	768		(46		)	722		1,423		(13		)	1,410
Comprehensive income attributable to partners	658		(46		)	612		1,180		(36		)	1,144

As a result of this change in accounting policy, the consolidated statement of cash flows in prior periods have been retrospectively adjusted, as follows:



	Nine Months Ended September 30, 2017
	As Originally Reported			Effect of Change			As Adjusted
Net income	$	1,417		$	(13	)	$	1,404
Inventory valuation adjustments	(30		)	30			—
Net change in operating assets and liabilities, net of effects from acquisitions (change in inventories)	185			(17		)	168

Revenue Recognition Standard

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 adopted ASU 2014-09 on January 1, 2018.

Upon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to decreases in revenue (with offsetting decreases to cost of sales) resulting from recognition of non-cash consideration as revenue when received and as cost of sales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related to multiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. In addition to the evaluation performed, we have made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard.

Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to existing contracts for which the Partnership has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018.

The Partnership has elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect adjustment to partners’ capital was not material. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods.

The adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales and operating expenses. There were no material changes in the timing of recognition of revenue and therefore no material impacts to the balance sheet upon adoption.

The disclosure below shows the impact of adopting the new standard during the period of adoption compared to amounts that would have been reported under the Partnership’s previous revenue recognition policies:



	Three Months Ended September 30, 2018							Nine Months Ended September 30, 2018
	As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)			As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)
Revenues:
Natural gas sales	$	1,026	$	1,026	$	—		$	3,112	$	3,112	$	—
NGL sales	2,695		2,686		9			6,866		6,839		27
Crude sales	3,841		3,838		3			11,336		11,326		10
Gathering, transportation and other fees	1,579		1,783		(204		)	4,440		4,977		(537		)
Refined product sales	382		381		1			1,234		1,233		1
Other	118		118		—			343		343		—

Costs and expenses:
Cost of products sold	$	6,745	$	6,949	$	(204	)	$	19,873	$	20,410	$	(537	)
Operating expenses	632		619		13			1,863		1,825		38

Additional disclosures related to revenue are included in Note 11.

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 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 information about the amount, timing, and uncertainty of cash flows arising from a lease. The update requires lessees to record virtually all leases on their balance sheets. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the existing lease guidance in Topic 840. The Partnership plans to elect the package of transition practical expedients and will adopt this standard beginning with its first quarter of fiscal 2019 and apply it retrospectively at the beginning of the period of adoption through a cumulative-effect adjustment to retained earnings. The Partnership has performed several procedures to evaluate the impact of the adoption of this standard on the financial statements and disclosures and address the implications of Topic 842 on future lease arrangements. The procedures include reviewing all forms of leases, performing a completeness assessment over the lease population, establishing processes and controls to timely identify new and modified lease agreements, educating its employees on these new processes and controls and implementing a third-party supported lease accounting information system to account for our leases in accordance with the new standard. However, we are still in the process of quantifying this impact. We expect that upon adoption most of the Partnership’s lease commitments will be recognized as right of use assets and lease obligations.

ASU 2017-12

In August 2017, the FASB issued Accounting Standards Update 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.

ASU 2018-02

In February 2018, the FASB issued Accounting Standards Update No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Partnership elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material.

Acquisitions and Other Transactions

9 Months Ended

Sep. 30, 2017

Acquisitions [Abstract]

Business Combination Disclosure [Text Block]

ACQUISITIONS AND OTHER INVESTING TRANSACTIONS

ETE Contribution of Assets to ETP

Immediately prior to the closing of the ETE-ETP Merger discussed in Note 1, ETE contributed the following to ETP:


•	2,263,158 common units representing limited partner interests in Sunoco LP to ETP in exchange for 2,874,275 ETP common units;


•	100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETP in exchange for 42,812,389 ETP common units;


•	12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETP in exchange for 16,134,903 ETP common units; and


•	a 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC (collectively, “Lake Charles LNG and Other”) to ETP in exchange for 37,557,815 ETP common units.

ETP, Sunoco LP, USAC and Lake Charles LNG and Other are under common control of ETE; therefore, we expect to account for the contribution transactions at historical cost as a reorganization of entities under common control. Accordingly, beginning with the quarter ending December 31, 2018, ETP’s consolidated financial statements will be retrospectively adjusted to reflect consolidation of Sunoco LP and Lake Charles LNG and Other for all prior periods and consolidation of USAC subsequent to April 2, 2018 (the date ETE acquired USAC’s general partner).

The following table summarizes the assets and liabilities of Sunoco LP, USAC and Lake Charles LNG and Other as of September 30, 2018, which amounts will be retrospectively consolidated in ETP’s consolidated balance sheets beginning with the quarter ending December 31, 2018, subject to the elimination of intercompany balances:



	Sunoco LP		USAC		Lake Charles LNG and Other
Current assets	$	1,331	$	230	$	28
Property, plant and equipment, net	1,494		2,541		746
Goodwill	1,534		619		184
Intangible assets	655		399		35
Other non-current assets	134		25		909
Total assets	$	5,148	$	3,814	$	1,902

Current liabilities	$	1,086	$	173	$	107
Long-term debt, less current maturities	2,774		1,731		—
Other non-current liabilities	343		6		8
Preferred Units	—		477		—
Net assets	$	945	$	1,427	$	1,787

The unaudited financial information in the table below summarizes the combined results of our operations and those of Sunoco LP, USAC and Lake Charles LNG and Other on a pro forma basis, to reflect the retrospective consolidation of those entities. The pro forma financial information is presented for informational purposes only and is not indicative of the results of operations that would have been achieved. The pro forma adjustments include the effect of intercompany revenue eliminations:



	Unaudited Pro Forma
	Nine Months Ended September 30,
	2018		2017
Revenues	$	40,514	$	29,072
Net income attributable to partners	$	2,282	$	1,138

CDM Contribution

On April 2, 2018, ETP contributed to USAC all of the issued and outstanding membership interests of CDM for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“USAC Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The USAC Class B Units are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019.

Prior to the CDM Contribution, the CDM entities were indirect wholly-owned subsidiaries of ETP. Beginning April 2018, ETP’s consolidated financial statements reflected an equity method investment in USAC. CDM’s assets and liabilities were not reflected as held for sale, nor were CDM’s results reflected as discontinued operations in these financial statements. At September 30, 2018, the carrying value of ETP’s investment in USAC was $385 million, which is reflected in the all other segment. ETP recorded an $86 million loss on the deconsolidation of CDM including a $45 million accrual related to the indemnification of USAC related to an ongoing CDM sales and use tax audit.

In connection with the CDM Contribution, ETE acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC, and (ii) 12,466,912 USAC common units for cash consideration equal to $250 million.

Advances to and Investments in Affiliates (Notes)	9 Months Ended
Advances to and Investments in Affiliates (Notes)	Sep. 30, 2018
Schedule of Equity Method Investments [Line Items]
Investments in and Advances to Affiliates, Schedule of Investments [Text Block]	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES HPC ETP previously owned a 49.99% interest in HPC, which owns RIGS. In April 2018, ETP acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in ETP’s financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in ETP’s financial statements. Sunoco LP In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility. As of September 30, 2018, ETP owned 26.2 million Sunoco LP common units representing 31.8% of Sunoco LP’s total outstanding common units. Our investment in Sunoco LP is reflected in the all other segment. As of September 30, 2018, the carrying value of our investment in Sunoco LP was $542 million. Subsequent to the ETE-ETP Merger, ETP owns 28.5 million Sunoco LP common units. For the periods presented herein, ETP’s investment in Sunoco LP is reflected under the equity method of accounting; however, for periods subsequent to the ETE-ETP Merger, ETP will reflect Sunoco LP as a consolidated subsidiary. USAC As of September 30, 2018, ETP owned 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests in USAC. USAC provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. Our investment in USAC is reflected in the all other segment. As of September 30, 2018, the carrying value of our investment in USAC was $385 million. Subsequent to the ETE-ETP Merger, ETP owns 39.7 million USAC common units and 6.4 million USAC Class B Units. For the periods presented herein, ETP’s investment in USAC is reflected under the equity method of accounting; however, for periods subsequent to the ETE-ETP Merger, ETP will reflect USAC as a consolidated subsidiary.

Cash And Cash Equivalents

9 Months Ended

Sep. 30, 2018

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 September 30,
	2018			2017*
Accounts receivable	$	251		$	(77	)
Accounts receivable from related companies	206			46
Inventories	48			133
Other current assets	(23		)	37
Other non-current assets, net	(99		)	(89		)
Accounts payable	(177		)	96
Accounts payable to related companies	(199		)	(11		)
Accrued and other current liabilities	351			(26		)
Other non-current liabilities	21			57
Derivative assets and liabilities, net	72			2
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	451		$	168

* As adjusted. See Note 1.

Non-cash investing and financing activities are as follows:



	Nine Months Ended September 30,
	2018		2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,026	$	1,236
USAC limited partner interests received in the CDM Contribution (see Note 2)	411		—
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	—	$	988

Inventories

9 Months Ended

Sep. 30, 2018

Inventory, Gross [Abstract]

Inventories

INVENTORIES

Inventories consisted of the following:



	September 30, 2018		December 31, 2017
Natural gas, NGLs and refined products	$	615	$	733
Crude oil	643		551
Spare parts and other	249		305
Total inventories	$	1,507	$	1,589

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

Fair Value Measurements

9 Months Ended

Sep. 30, 2018

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, 2018 was $34.39 billion and $33.85 billion, respectively. As of December 31, 2017, the aggregate fair value and carrying amount of our consolidated debt obligations was $34.28 billion and $33.09 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, 2018, 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, 2018 and December 31, 2017 based on inputs used to derive their fair values:



				Fair Value Measurements at September 30, 2018
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	48		$	48		$	—
Swing Swaps IFERC	1			—			1
Fixed Swaps/Futures	25			25			—
Forward Physical Contracts	12			—			12
Power:
Forwards	36			—			36
Options – Puts	1			1			—
NGLs – Forwards/Swaps	476			476			—
Total commodity derivatives	599			550			49
Other non-current assets	28			18			10
Total assets	$	627		$	568		$	59
Liabilities:
Interest rate derivatives	$	(97	)	$	—		$	(97	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(89		)	(89		)	—
Swing Swaps IFERC	(1		)	—			(1		)
Fixed Swaps/Futures	(26		)	(26		)	—
Forward Physical Contracts	(7		)	—			(7		)
Power:
Forwards	(30		)	—			(30		)
Futures	(1		)	(1		)	—
NGLs – Forwards/Swaps	(521		)	(521		)	—
Refined Products – Futures	(5		)	(5		)	—
Crude – Forwards/Swaps	(190		)	(190		)	—
Total commodity derivatives	(870		)	(832		)	(38		)
Total liabilities	$	(967	)	$	(832	)	$	(135	)



				Fair Value Measurements at December 31, 2017
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	11		$	11		$	—
Swing Swaps IFERC	13			—			13
Fixed Swaps/Futures	70			70			—
Forward Physical Contracts	8			—			8
Power – Forwards	23			—			23
NGLs – Forwards/Swaps	191			191			—
Crude:
Forwards/Swaps	2			2			—
Futures	2			2			—
Total commodity derivatives	320			276			44
Other non-current assets	21			14			7
Total assets	$	341		$	290		$	51
Liabilities:
Interest rate derivatives	$	(219	)	$	—		$	(219	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(24		)	(24		)	—
Swing Swaps IFERC	(15		)	(1		)	(14		)
Fixed Swaps/Futures	(57		)	(57		)	—
Forward Physical Contracts	(2		)	—			(2		)
Power – Forwards	(22		)	—			(22		)
NGLs – Forwards/Swaps	(186		)	(186		)	—
Refined Products – Futures	(25		)	(25		)	—
Crude:
Forwards/Swaps	(6		)	(6		)	—
Futures	(1		)	(1		)	—
Total commodity derivatives	(338		)	(300		)	(38		)
Total liabilities	$	(557	)	$	(300	)	$	(257	)

- Definition

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

+ References + Details

Debt Obligations	9 Months Ended
Debt Obligations	Sep. 30, 2018
Debt Disclosure [Abstract]
Debt Obligations	DEBT OBLIGATIONS ETP Senior Notes Offering and Redemption In June 2018, ETP issued the following senior notes: •$500 million aggregate principal amount of 4.20% senior notes due 2023; •$1.00 billion aggregate principal amount of 4.95% senior notes due 2028; •$500 million aggregate principal amount of 5.80% senior notes due 2038; and •$1.00 billion aggregate principal amount of 6.00% senior notes due 2048. The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal on the senior notes is payable upon maturity and interest is paid semi-annually. The senior notes rank equally in right of payment with ETP’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETP may incur. The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes. The $2.96 billion net proceeds from the offering were used to repay borrowings outstanding under ETP’s revolving credit facility, for general partnership purposes and to redeem all of the following senior notes: •ETP’s $650 million aggregate principal amount of 2.50% senior notes due June 15, 2018; •Panhandle’s $400 million aggregate principal amount of 7.00% senior notes due June 15, 2018; and •ETP’s $600 million aggregate principal amount of 6.70% senior notes due July 1, 2018. The aggregate amount paid to redeem these notes was approximately $1.65 billion. Credit Facilities and Commercial Paper ETP Five-Year Credit Facility ETP’s revolving credit facility (the “ETP Five-Year Credit Facility”) previously allowed for unsecured borrowings up to $4.00 billion and matured in December 2022. On October 19, 2018, the ETP Five-Year Credit Facility was amended to increase the borrowing capacity by $1.00 billion, to $5.00 billion, and to extend the maturity date to December 1, 2023. The ETP Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions. As of September 30, 2018, the ETP Five-Year Credit Facility had $1.78 billion outstanding, of which $1.57 billion was commercial paper. The amount available for future borrowings was $2.06 billion after taking into account letters of credit of $163 million, but before taking into account the additional capacity from the October 19, 2018 amendment. The weighted average interest rate on the total amount outstanding as of September 30, 2018 was 3.00%. ETP 364-Day Facility ETP’s 364-day revolving credit facility (the “ETP 364-Day Facility”) previously allowed for unsecured borrowings up to $1.00 billion and matured on November 30, 2018. On October 19, 2018, the ETP 364-Day Facility was amended to extend the maturity date to November 29, 2019. As of September 30, 2018, the ETP 364-Day Facility had no outstanding borrowings. Bakken Credit Facility In August 2016, ETP and Phillips 66 completed project-level financing of the Bakken pipeline. The $2.50 billion credit facility matures in August 2019 (the “Bakken Credit Facility”). As of September 30, 2018, the Bakken Credit Facility had $2.50 billion of outstanding borrowings, all of which has been reflected in current maturities of long-term debt on the Partnership’s consolidated balance sheet. The weighted average interest rate on the total amount outstanding as of September 30, 2018 was 3.85%. Compliance with Our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of September 30, 2018.

Equity

9 Months Ended

Sep. 30, 2018

Partners' Capital Notes [Abstract]

Equity

EQUITY

The changes in outstanding common units during the nine months ended September 30, 2018 were as follows:



	Number of Units
Number of common units at December 31, 2017	1,164.1
Common units issued in connection with the distribution reinvestment plan	2.9
Common units issued in connection with certain transactions	1.3
Issuance of common units under equity incentive plans	0.1
Repurchases of common units in open-market transactions	(1.2	)
Number of common units at September 30, 2018	1,167.2

Subsequent to the ETE-ETP Merger in October 2018, all of the outstanding ETP common units are held directly or indirectly by ETE, including the ETP common units issued in connection with the conversion of the general partner interest to a non-economic interest and the cancellation of the IDRs, as discussed in Note 1, and the contributions of the investments in ETE’s other subsidiaries, as discussed in Note 2. In addition, the ETP Class I units and Class J units were also cancelled in connection with the ETE-ETP Merger.

Equity Distribution Program

During the nine months ended September 30, 2018, there were no units issued under the Partnership’s equity distribution agreement. In connection with the ETE-ETP Merger, the equity distribution program was terminated in October 2018.

Distribution Reinvestment Program

During the nine months ended September 30, 2018, distributions of $57 million were reinvested under the Partnership’s distribution reinvestment plan. In connection with the ETE-ETP Merger, the distribution reinvestment program was terminated in October 2018.

Preferred Units

ETP issued 950,000 Series A Preferred Units and 550,000 Series B Preferred Units in November 2017 and has issued additional preferred units in 2018, as discussed below. Subsequent to the ETE-ETP Merger, all of ETP’s Series A, Series B, Series C and Series D Preferred Units remain outstanding.

Series C Preferred Units Issuance

In April 2018, ETP issued 18 million of its 7.375% Series C Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $450 million. The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes.

Distributions on the Series C Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.530% per annum. The Series C Preferred Units are redeemable at ETP’s option on or after May 15, 2023 at a redemption price of $25 per Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Series D Preferred Units Issuance

In July 2018, ETP issued 17.8 million of its 7.625% Series D Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $445 million. The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes.

Distributions on the Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.378% per annum. The Series D Preferred Units are redeemable at ETP’s option on or after August 15, 2023 at a redemption price of $25 per Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Cash Distributions

Distributions on common units declared and paid by the Partnership subsequent to December 31, 2017 but prior to the closing of the ETE-ETP Merger as discussed in Note 1 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2017	February 8, 2018	February 14, 2018	$	0.5650
March 31, 2018	May 7, 2018	May 15, 2018	0.5650
June 30, 2018	August 6, 2018	August 14, 2018	0.5650

Distributions on ETP’s preferred units declared and/or paid by the Partnership subsequent to December 31, 2017 were as follows:



Period Ended	Record Date	Payment Date	Rate
Series A Preferred Units
December 31, 2017	February 1, 2018	February 15, 2018	$	15.451
June 30, 2018	August 1, 2018	August 15, 2018	31.250
Series B Preferred Units
December 31, 2017	February 1, 2018	February 15, 2018	$	16.378
June 30, 2018	August 1, 2018	August 15, 2018	33.125
Series C Preferred Units
June 30, 2018	August 1, 2018	August 15, 2018	$	0.5634
September 30, 2018	November 1, 2018	November 15, 2018	0.4609
Series D Preferred Units
September 30, 2018	November 1, 2018	November 15, 2018	$	0.5931

Accumulated Other Comprehensive Income

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



	September 30, 2018			December 31, 2017
Available-for-sale securities ⁽¹⁾	$	6		$	8
Foreign currency translation adjustment	(5		)	(5		)
Actuarial loss related to pensions and other postretirement benefits	(7		)	(5		)
Investments in unconsolidated affiliates, net	14			5
Total AOCI, net of tax	$	8		$	3


⁽¹⁾	Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which resulted in the reclassification of $2 million from accumulated other comprehensive income related to available-for-sale securities to common unitholders.

Income Taxes (Notes)	9 Months Ended
Income Taxes (Notes)	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES The Partnership’s effective tax rate differs from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. For the three and nine months ended September 30, 2018, the Partnership’s income tax benefit also reflected $109 million and $179 million, respectively, of deferred benefit adjustments as the result of a state statutory rate reduction. Sunoco, Inc. historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the Internal Revenue Service (“IRS”) excluding these government incentive payments from federal taxable income. The IRS denied the amended returns and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and the Federal Circuit affirmed the CFC’s ruling on November 1, 2018. Sunoco, Inc. is considering seeking further review of this decision. Due to the uncertainty surrounding the litigation, a reserve of $530 million was previously established for the full amount of the pending refund claims.

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

9 Months Ended

Sep. 30, 2018

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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

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 certain of Sunoco LP’s senior notes and $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 (“ETC M-A”).

On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes, repaid and terminated the term loan and issued the following notes (the “Sunoco LP Notes”) for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:


•	$1.00 billion aggregate principal amount of 4.875% senior notes due 2023;


•	$800 million aggregate principal amount of 5.50% senior notes due 2026; and


•	$400 million aggregate principal amount of 5.875% senior notes due 2028.

Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.

In connection with the issuance of the Sunoco LP Notes, Sunoco LP entered into a registration rights agreement with the initial purchasers pursuant to which Sunoco LP agreed to complete an offer to exchange the Sunoco LP Notes for an issue of registered notes with terms substantively identical to each series of Sunoco LP Notes and evidencing the same indebtedness as the Sunoco LP Notes on or before January 23, 2019.

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 FERC approved an audit report in October 2018. In response to the findings in the audit report, the Company expects to make certain changes to its processes, policies and procedures; however, the Company does not expect the findings to result in any changes to its financial statements.

Commitments

In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETP believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

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.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Rental expense	$	21	$	29	$	60	$	68

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 United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access, LLC (“Dakota Access”) to make two crossings of the Missouri River in North Dakota. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River. On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“the Court”) against the USACE and challenged the legality of these permits 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 was pending, which the court denied on September 9, 2016. Dakota Access intervened in the case. The Cheyenne River Sioux Tribe (“CRST”) also intervened. The SRST filed an amended complaint and added claims based on treaties between the SRST and the CRST and the United States and statutes governing the use of government property.

In February 2017, in response to a presidential memorandum, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. The CRST moved for a preliminary injunction and temporary restraining order (“TRO”) to block operation of the pipeline, which was denied, and raised claims based on the religious rights of the CRST.

The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “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 concluded that the USACE had not violated 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 determinations under certain of these statutes. On May 3, 2018, the District Court ordered the USACE to file a status report by June 8, 2018 informing the Court when the USACE expects the remand process to be complete. On June 8, 2018, the USACE filed a status report stating that they will conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they will need until August 31, 2018 to finish the remand process. On August 31, 2018, the USACE informed the Court that it had completed the remand process and that it had determined that the three issues remanded by the Court had been correctly decided. The USACE indicated that a document detailing its remand analysis would be filed after a “confidentiality review.” Following the submission by USACE of its detailed remand analysis, it is expected that the Court will make a determination regarding the three discrete issues covered by the remand order.

On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent third-party to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The assessment report was filed with the Court. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access filed the revised plan with the Court. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first and second reports were filed with the court on December 29, 2017 and February 28, 2018, respectfully.

In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline.

On March 19, 2018, the District Court denied YST’s motion for partial summary judgment and instead granted judgment in favor of Dakota Access pipeline and the USACE on the claims raised in YST’s motion. The Court concluded that YST’s NHPA claims are moot because construction of the pipeline is complete and that the government’s review process did not violate NEPA or the various treaties cited by the YST.

On February 8, 2018, the Court docketed a motion by CRST to “compel meaningful consultation on remand.” SRST then made a similar motion for “clarification re remand process and remand conditions.” The motions seek an order from the Court directing the USACE as to how it should conduct its additional review on remand. Dakota Access pipeline and the USACE opposed both motions. On April 16, 2018, the Court denied both motions.

While ETP believes that the pending lawsuits are unlikely to halt or suspend operation of the pipeline, we cannot assure this outcome. ETP 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 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) (now known as Sunoco (R&M), LLC) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. 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, 2018, Sunoco, Inc. is a defendant in six cases, including one case each initiated by the States of Maryland, Vermont and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P.

In late July 2018, the Court in the Vermont matter denied Plaintiff’s motion to amend its complaint to add specific allegations regarding some of the sites the court previously dismissed. In early September 2018, Sunoco, Inc. participated in a defense group effort to resolve the case without further litigation. A settlement in principle to resolve the remaining statewide Vermont Case was reached in September 2018.

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

Purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency-ETP merger (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 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 (“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. Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC (the “Regency Defendants”). On March 6, 2018, the Regency Defendants filed their Answer to Plaintiff’s Verified Amended Class Action Complaint. Trial is currently set for September 23-27, 2019.

The Regency 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 Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.

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

On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. ETP’s petition for review remains under consideration by the Texas Supreme Court.

ETE-ETP Merger Litigation

On September 17, 2018, William D. Warner (“Plaintiff”), a purported ETP unitholder, filed a putative class action asserting violations of various provisions of the Securities Exchange Act of 1934 and various rules promulgated thereunder in connection with the ETE-ETP Merger against ETP, Kelcy L. Warren, Michael K. Grimm, Marshall S. McCrea, Matthew S. Ramsey, David K. Skidmore, and W. Brett Smith (“Defendants”). Plaintiff specifically alleges that the Form S-4 Registration Statement issued in connection with the ETE-ETP Merger omits and/or misrepresents material information. Defendants believe the allegations have no merit and intend to defend vigorously against them. On October 26, 2018, Plaintiff and Defendants entered into a stipulation staying Defendants’ response deadlines until the designation of a lead plaintiff/lead counsel structure in accordance with the Private Securities Litigation Reform Act.

Bayou Bridge

On January 11, 2018, environmental groups and a trade association filed suit against the USACE in the United States District Court for the Middle District of Louisiana. Plaintiffs allege that the USACE’s issuance of permits authorizing the construction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the Rivers and Harbors Act. They asked the district court to vacate these permits and to enjoin construction of the project through the Basin until the USACE corrects alleged deficiencies in its decision-making process. ETP, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened on January 26, 2018. On March 27, 2018, Bayou Bridge filed an answer to the complaint.

On January 29, 2018, Plaintiffs filed motions for a preliminary injunction and TRO. United States District Court Judge Shelly Dick denied the TRO on January 30, 2018, but subsequently granted the preliminary injunction on February 23, 2018. On February 26, 2018, Bayou Bridge filed a notice of appeal and a motion to stay the February 23, 2018 preliminary injunction order. On February 27, 2018, Judge Dick issued an opinion that clarified her February 23, 2018 preliminary injunction order and denied Bayou Bridge’s February 26, 2018 motion to stay as moot. On March 1, 2018, Bayou Bridge filed a new notice of appeal and motion to stay the February 27, 2018 preliminary injunction order in the district court. On March 5, 2018, the district court denied the March 1, 2018 motion to stay the February 27, 2018 order.

On March 2, 2018, Bayou Bridge filed a motion to stay the preliminary injunction in the Fifth Circuit. On March 15, 2018, the Fifth Circuit granted a stay of injunction pending appeal and found that Bayou Bridge “is likely to succeed on the merits of its claim that the district court abused its discretion in granting a preliminary injunction.” Oral arguments were heard on the merits of the appeal, that is, whether the district court erred in granting the preliminary injunction in the Fifth Circuit on April 30, 2018. The district court has stayed the merits case pending decision of the Fifth Circuit. On May 10, 2018, the District Court stayed the litigation pending a decision from the Fifth Circuit. On July 6, 2018, the Fifth Circuit vacated the Preliminary Injunction and remanded the case back to the District Court. Construction is ongoing.

On August 14, 2018, Plaintiffs sought leave of court to amend their complaint to add an “as applied” challenge to the USACE’s application of the Louisiana Rapid Assessment Method to Bayou Bridge’s permits. Defendants’ filed motions in opposition on September 11, 2018. On September 11, 2018, Plaintiffs filed a motion for partial summary judgment on the issue of the USACE’s analysis of the risks of an oil spill once the pipeline is in operation.

At an October 2, 2018 scheduling conference, the USACE agreed to lodge the administrative record for Plaintiff’s original complaint, which it has done. Summary judgment briefing will be concluded by the Spring of 2019.

Rover

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and Pretec Directional Drilling, LLC (“Pretec”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. Laney Directional Drilling Co., Atlas Trenchless, LLC, Mears Group, Inc., D&G Directional Drilling, Inc. d/b/a D&G Directional Drilling, LLC, and B&T Directional Drilling, Inc. (collectively, with Rover and Pretec, “Defendants”) were added as defendants on April 17, 2018 and July 18, 2018.

Ohio EPA alleges that the Defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, and that the Defendants harmed pristine wetlands in Stark County. Ohio EPA further alleges that the Defendants caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Rover and other Defendants filed several motions to dismiss and Ohio EPA filed a motion in opposition.

In January 2018, Ohio EPA sent a letter to the FERC to express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the Rover Pipeline construction. Rover sent a January 24 response to the FERC and stated, among other things, that as Ohio EPA conceded, Rover was conducting its drilling operations in accordance with specified procedures that had been approved by the FERC and reviewed by the Ohio EPA. In addition, although the HDD operations were crossing the same resource as that which led to an inadvertent release of drilling fluids in April 2017, the drill in 2018 had been redesigned since the original crossing. Ohio EPA expressed concern that the drilling fluids could deprive organisms in the wetland of oxygen. Rover, however, has now fully remediated the site, a fact with which Ohio EPA concurs.

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, 2018 and December 31, 2017, accruals of approximately $55 million and $53 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.

On April 25, 2018, and as amended on April 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“Complaint”) against Sunoco Pipeline L.P. (“SPLP”) before the Pennsylvania Public Utility Commission (“PUC”). Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“ME1,” “ME2” or “ME2x”) in West Whiteland Township (“the Township”) are unreasonable, unsafe, inadequate, and insufficient for, among other reasons, selecting an improper and unsafe route through densely populated portions of the Township with homes, schools, and infrastructure and causing inadvertent returns and sinkholes during construction because of unstable geology in the Township; (ii) SPLP failed to warn the public of the dangers of the pipeline; (iii) the construction of ME2 and ME2x increases the risk of damage to the existing co-located ME1 pipeline; and (iv) ME1, ME2 and ME2x are not public utility facilities. Based on these allegations, Senator Dinniman’s Complaint seeks emergency relief by way of an order (i) prohibiting construction of ME2 and ME2x in the Township; (ii) prohibiting operation of ME1; (iii) in the alternative to (i) and (ii) prohibiting the construction of ME2 and ME2x and the operation of ME1 until SPLP fully assesses and the PUC approves the condition, adequacy, efficiency, safety, and reasonableness of those pipelines and the geology in which they sit; (iv) requiring SPLP to release to the public its written integrity management plan and risk analysis for these pipelines; and (v) finding that these pipelines are not public utility facilities. In short, the relief, if granted, would continue the suspension of operation of ME1 and suspend further construction of ME2 and ME2x in the Township.

Following a hearing on May 7, 2018 and 10, 2018, Administrative Law Judge Elizabeth H. Barnes (“ALJ”) issued an Order on May 24, 2018 that granted Senator Dinniman’s petition for interim emergency relief and required SPLP to shut down ME1, to discontinue construction of ME2 and ME2x within the Township, and required SPLP to provide various types of information and perform various geotechnical and geophysical studies within the Township. The ALJ’s Order was immediately effective, and SPLP complied by shutting down service on ME1 and discontinuing all construction in the Township on ME2 and ME2x. The ALJ’s Order was automatically certified as a material question to the PUC, which issued an Opinion and Order on June 15, 2018 (following a public meeting on June 14, 2018) that reversed in part and affirmed in part the ALJ’s Order. PUC’s Opinion and Order permitted SPLP to resume service on ME1, but continued the shutdown of construction on ME2 and ME2x pending the submission of the following three types of information to PUC: (i) inspection and testing protocols; (ii) comprehensive emergency response plan; and (iii) safety training curriculum for employees and contractors. SPLP submitted the required information on June 22, 2018. On July 2, 2018, Senator Dinniman and intervenors responded to the submission. SPLP is also required to provide an affidavit that the Pennsylvania Department of Environmental Protection (“PADEP”) has issued appropriate approvals for construction of ME2 and ME2x in the Township before recommencing construction of ME2 and ME2x locations within the Township. SPLP submitted all necessary affidavits. On August 2, 2018 the PUC entered an Order lifting the stay of construction on ME2 and ME2x in the Township with respect to four of the eight areas within the Township where the necessary environmental permits had been issued. Subsequently, after PADEP’s issuance of permit modifications for two of the four remaining construction sites, the PUC lifted the construction stay on those two sites as well.

Also on August 2, 2018, the PUC ratified its prior action by notational voting of certifying for interlocutory appeal to the Pennsylvania Commonwealth Court the legal issue of whether Senator Dinniman has standing to pursue the action. SPLP submitted a petition for permission to appeal on this issue of standing. Senator Dinniman and intervenors opposed that petition. On September 27, 2018, the Commonwealth Court issued an Order that certified for appeal the issue of Senator Dinniman’s standing. The Order stays all proceedings in the PUC.

On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project. On August 1, 2017 the EHB lifted the order as to two drill locations. On August 3, 2017, the EHB lifted the order as to 14 additional locations. The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the PADEP. The EHB Judge encouraged the parties to pursue a settlement with respect to the remaining HDD locations and facilitated a settlement meeting. On August 7, 2017 a final settlement was reached. A stipulated order has been submitted to the EHB Judge with respect to the settlement. The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project. The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation. Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits. Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company. On July 31, 2018 the underlying permit appeals in which the above settlements occurred were withdrawn in a settlement between the appellants and PADEP. That settlement did not involve SPLP.

In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project. Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval. SPLP has fulfilled the requirements of those agreements and has been authorized by PADEP to resume drilling the locations.

No amounts have been recorded in our September 30, 2018 or December 31, 2017 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, natural resource damages, 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 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 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 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January 2015. In July 2017, we had a meeting with the DOJ, EPA and Louisiana Department of Environmental Quality (“LDEQ”) during which the agencies presented their initial demand for civil penalties and injunctive relief. Since then, the parties have reached an agreement in principal to resolve all penalties with DOJ and LDEQ along with injunctive relief requirements to be completed within three years all of which is being formalized in a Consent Decree. In addition to resolution of the civil penalty, we continue to discuss national resource damages with the Louisiana trustees.

On January 3, 2018, PADEP issued an Administrative Order to SPLP directing that work on the Mariner East 2 and 2X pipelines be stopped. The Administrative Order detailed alleged violations of the permits issued by PADEP in February 2017, during the construction of the project. SPLP began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues. Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so SPLP took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, SPLP entered into a Consent Order and Agreement with PADEP that (i) withdraws the Administrative Order; (ii) establishes requirements for compliance with permits on a going forward basis; (iii) resolves the non-compliance alleged in the Administrative Order; and (iv) conditions restart of work on an agreement by SPLP to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, SPLP admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP. PADEP also found in the Consent Order and Agreement that SPLP had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. SPLP concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order. That request was granted on February 8, 2018.

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 polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.


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


•	legacy sites related to Sunoco, Inc. that are subject to environmental assessments, 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, 2018, Sunoco, Inc. had been named as a PRP at approximately 41 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, 2018		December 31, 2017
Current	$	36	$	36
Non-current	281		314
Total environmental liabilities	$	317	$	350

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, 2018 and 2017, the Partnership recorded $17 million and $5 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2018 and 2017, the Partnership recorded $28 million and $18 million, respectively, of expenditures related to environmental programs.

Our pipeline operations are subject to regulation by the United States Department of Transportation under the Pipeline Hazardous Materials Safety Administration (“PHMSA”), pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

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, the Occupational Health and Safety Administration’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.

Revenue (Notes)

9 Months Ended

Sep. 30, 2018

Revenue [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE

The following disclosures discuss the Partnership’s revised revenue recognition policies upon the adoption of ASU 2014-09 on January 1, 2018, as discussed in Note 1. These policies were applied to the current period only, and the amounts reflected in the Partnership’s consolidated financial statements for the three and nine months ended September 30, 2017 were recorded under the Partnership’s previous accounting policies.

Disaggregation of revenue

The Partnership’s consolidated financial statements reflect the following six reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes:


•	intrastate transportation and storage;


•	interstate transportation and storage;


•	midstream;


•	NGL and refined products transportation and services;


•	crude oil transportation and services; and


•	all other.

Note 14 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.

Intrastate transportation and storage revenue

Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Interstate transportation and storage revenue

Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Midstream revenue

Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported for our customers. The various types of revenue contracts our midstream segment enters into include:

Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed.

Keepwhole: Contracts under which we gather raw natural gas from a third party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed.

Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:


•	In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.

•

Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received.

Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition.

Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints.

NGL and refined products transportation and services revenue

Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGL’s and other related hydrocarbons at market rates. These contracts were not affected by ASC 606.

Crude oil transportation and services revenue

Our crude oil transportation and service segment are primarily derived from provide transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed.

Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606.

All other revenue

Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard.

Contract Balances with Customers

The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.

The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services. As of September 30, 2018 and January 1, 2018, no contract assets have been recognized.

The Partnership recognizes a contract liability if the customer's payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed fee for a right to use our assets, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. As of September 30, 2018, the Partnership had $349 million in deferred revenues representing the current value of our future performance obligations.

The amount of revenue recognized for the three and nine months ended September 30, 2018 that was included in the deferred revenue liability balance as of January 1, 2018 was $12 million and $75 million, respectively.

Performance Obligations

At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contacts, only the fixed component of the contracts are included in the table below.

As of September 30, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $40.13 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:



	Years Ending December 31,
	2018 (remainder)		2019		2020		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2018	$	1,426	$	5,066	$	4,568	$	29,069	$	40,129

Practical Expedients Utilized by the Partnership

The Partnership elected the following practical expedients in accordance with Topic 606:

•

Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers.


•	Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.


•	Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.

Derivative Assets And Liabilities

9 Months Ended

Sep. 30, 2018

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 utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. 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, 2018			December 31, 2017
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	358		2018-2019	1,078		2018
Basis Swaps IFERC/NYMEX ⁽¹⁾	69,685		2018-2020	48,510		2018-2020
Options – Puts	(17,273	)	2019	13,000		2018
Power (Megawatt):
Forwards	429,720		2018-2019	435,960		2018-2019
Futures	309,123		2018-2019	(25,760	)	2018
Options – Puts	157,435		2018-2019	(153,600	)	2018
Options – Calls	321,240		2018-2019	137,600		2018
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(7,705	)	2018-2021	4,650		2018-2020
Swing Swaps IFERC	69,145		2018-2019	87,253		2018-2019
Fixed Swaps/Futures	(1,784	)	2018-2020	(4,700	)	2018-2019
Forward Physical Contracts	(54,151	)	2018-2020	(145,105	)	2018-2020
NGL (MBbls) – Forwards/Swaps	(4,997	)	2018-2019	(2,493	)	2018-2019
Crude (MBbls) – Forwards/Swaps	35,280		2018-2019	9,172		2018-2019
Refined Products (MBbls) – Futures	(1,521	)	2018-2019	(3,783	)	2018-2019
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(21,475	)	2018-2019	(39,770	)	2018
Fixed Swaps/Futures	(21,475	)	2018-2019	(39,770	)	2018
Hedged Item – Inventory	21,475		2018-2019	39,770		2018


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

Interest Rate Risk

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

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



Term	Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	September 30, 2018		December 31, 2017
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	$	—	$	300
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.56% and receive a floating rate	400		300
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		400
July 2021⁽²⁾	Forward-starting to pay a fixed rate of 3.55% 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, 2018		December 31, 2017		September 30, 2018			December 31, 2017
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	14	$	(6	)	$	(2	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	477		262		(537		)	(281		)
Commodity derivatives	122		44		(327		)	(55		)
Interest rate derivatives	—		—		(97		)	(219		)
	599		306		(961		)	(555		)
Total derivatives	$	599	$	320	$	(967	)	$	(557	)

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, 2018			December 31, 2017			September 30, 2018			December 31, 2017
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(97	)	$	(219	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	122			44			(327		)	(55		)
Broker cleared derivative contracts	Other current assets (liabilities)	477			276			(543		)	(283		)
Total gross derivatives		599			320			(967		)	(557		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(29		)	(20		)	29			20
Counterparty netting	Other current assets (liabilities)	(477		)	(263		)	477			263
Total net derivatives		$	93		$	37		$	(461	)	$	(274	)

We disclose the non-exchange traded financial derivative instruments as derivative 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 in income with respect to our derivative financial instruments:



	Location of Gain Recognized in Income on Derivatives	Amount of Gain Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended September 30,				Nine Months Ended September 30,
		2018		2017		2018		2017
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	—	$	2	$	9	$	4



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,					Nine Months Ended September 30,
		2018		2017			2018			2017
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	3	$	(5	)	$	36		$	21
Commodity derivatives – Non-trading	Cost of products sold	21		(12		)	(352		)	(15		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	45		(8		)	117			(28		)
Embedded derivatives	Other, net	—		—			—			1
Total		$	69	$	(25	)	$	(199	)	$	(21	)

Related Party Transactions

9 Months Ended

Sep. 30, 2018

Related Party Transactions

RELATED PARTY TRANSACTIONS

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

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Affiliated revenues	$	192	$	190	$	700	$	441

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



	September 30, 2018		December 31, 2017
Accounts receivable from related companies:
ETE	$	42	$	—
FGT	15		11
Phillips 66	30		20
Sunoco LP	207		219
Trans-Pecos Pipeline, LLC	10		1
Other	29		67
Total accounts receivable from related companies:	$	333	$	318

Accounts payable to related companies:
Sunoco LP	$	178	$	195
USAC	45		—
Other	64		14
Total accounts payable to related companies:	$	287	$	209



	September 30, 2018		December 31, 2017
Long-term notes receivable from related company:
Sunoco LP	$	85	$	85

Reportable Segments

9 Months Ended

Sep. 30, 2018

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS

Our consolidated financial statements reflect the following reportable segments, which conduct their business in the United States, as follows:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services; and

•all other.

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

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

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

The following tables present financial information by segment:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	846		$	729		$	2,424		$	2,196
Intersegment revenues	76			44			186			146
	922			773			2,610			2,342
Interstate transportation and storage:
Revenues from external customers	390			220			1,026			652
Intersegment revenues	5			4			13			14
	395			224			1,039			666
Midstream:
Revenues from external customers	537			665			1,571			1,863
Intersegment revenues	1,716			1,100			4,170			3,154
	2,253			1,765			5,741			5,017
NGL and refined products transportation and services:
Revenues from external customers	2,948			1,989			7,878			5,874
Intersegment revenues	115			81			299			241
	3,063			2,070			8,177			6,115
Crude oil transportation and services:
Revenues from external customers	4,422			2,714			12,942			7,749
Intersegment revenues	16			11			44			16
	4,438			2,725			12,986			7,765
All other:
Revenues from external customers	498			656			1,490			2,110
Intersegment revenues	27			27			108			139
	525			683			1,598			2,249
Eliminations	(1,955		)	(1,267		)	(4,820		)	(3,710		)
Total revenues	$	9,641		$	6,973		$	27,331		$	20,444



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017*			2018			2017*
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	221		$	163		$	621		$	480
Interstate transportation and storage	416			273			1,069			800
Midstream	434			356			1,225			1,088
NGL and refined products transportation and services	498			439			1,410			1,208
Crude oil transportation and services	682			420			1,694			835
All other	78			133			242			363
Total	2,329			1,784			6,261			4,774
Depreciation, depletion and amortization	(636		)	(596		)	(1,827		)	(1,713		)
Interest expense, net	(387		)	(352		)	(1,091		)	(1,020		)
Gain on Sunoco LP common unit repurchase	—			—			172			—
Loss on deconsolidation of CDM	—			—			(86		)	—
Gains (losses) on interest rate derivatives	45			(8		)	117			(28		)
Non-cash compensation expense	(20		)	(19		)	(61		)	(57		)
Unrealized gains (losses) on commodity risk management activities	97			(81		)	(255		)	17
Adjusted EBITDA related to unconsolidated affiliates	(257		)	(279		)	(670		)	(765		)
Equity in earnings of unconsolidated affiliates	113			127			147			139
Other, net	13			27			100			79
Income before income tax (expense) benefit	$	1,297		$	603		$	2,807		$	1,426

* As adjusted. See Note 1.



	September 30, 2018		December 31, 2017
Assets:
Intrastate transportation and storage	$	5,874	$	5,020
Interstate transportation and storage	14,143		13,518
Midstream	20,175		20,004
NGL and refined products transportation and services	18,438		17,600
Crude oil transportation and services	17,458		17,736
All other	3,068		4,087
Total assets	$	79,156	$	77,965

Guarantor Financial Information (Notes)

9 Months Ended

Sep. 30, 2018

Guarantor Financial Information [Abstract]

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

CONSOLIDATING GUARANTOR FINANCIAL INFORMATION

Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, is the issuer of multiple series of senior notes that are guaranteed by ETP. These guarantees are full and unconditional. For the purposes of this footnote, Energy Transfer Operating, L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.”

The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting.

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



	September 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	—		$	379	$	—		$	379
All other current assets	4			56			6,806		(892		)	5,974
Property, plant and equipment, net	—			—			60,550		—			60,550
Investments in unconsolidated affiliates	49,614			12,435			3,599		(62,049		)	3,599
All other assets	8			75			8,571		—			8,654
Total assets	$	49,626		$	12,566		$	79,905	$	(62,941	)	$	79,156

Current liabilities	$	(1,118	)	$	(3,407	)	$	14,675	$	(892	)	$	9,258
Non-current liabilities	22,823			7,605			4,794		—			35,222
Noncontrolling interest	—			—			6,334		—			6,334
Total partners’ capital	27,921			8,368			54,102		(62,049		)	28,342
Total liabilities and equity	$	49,626		$	12,566		$	79,905	$	(62,941	)	$	79,156



	December 31, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	(3	)	$	309	$	—		$	306
All other current assets	—			159			6,063		—			6,222
Property, plant and equipment, net	—			—			58,437		—			58,437
Investments in unconsolidated affiliates	48,378			11,648			3,816		(60,026		)	3,816
All other assets	—			—			9,184		—			9,184
Total assets	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965

Current liabilities	$	(1,496	)	$	(3,660	)	$	12,150	$	—		$	6,994
Non-current liabilities	21,604			7,607			7,609		—			36,820
Noncontrolling interest	—			—			5,882		—			5,882
Total partners’ capital	28,270			7,857			52,168		(60,026		)	28,269
Total liabilities and equity	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965



	Three Months Ended September 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	9,641		$	—		$	9,641
Operating costs, expenses, and other	—			—			8,136			—			8,136
Operating income	—			—			1,505			—			1,505
Interest expense, net	(303		)	(55		)	(29		)	—			(387		)
Equity in earnings of unconsolidated affiliates	1,394			501			113			(1,895		)	113
Gains on interest rate derivatives	45			—			—			—			45
Other, net	—			—			21			—			21
Income before income tax benefit	1,136			446			1,610			(1,895		)	1,297
Income tax benefit	—			—			(61		)	—			(61		)
Net income	1,136			446			1,671			(1,895		)	1,358
Less: Net income attributable to noncontrolling interest	—			—			223			—			223
Net income attributable to partners	$	1,136		$	446		$	1,448		$	(1,895	)	$	1,135

Other comprehensive income	$	—		$	—		$	4		$	—		$	4
Comprehensive income	1,136			446			1,675			(1,895		)	1,362
Comprehensive income attributable to noncontrolling interest	—			—			223			—			223
Comprehensive income attributable to partners	$	1,136		$	446		$	1,452		$	(1,895	)	$	1,139



	Three Months Ended September 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	6,973		$	—		$	6,973
Operating costs, expenses, and other	—		—			6,194			—			6,194
Operating income	—		—			779			—			779
Interest expense, net	—		(32		)	(320		)	—			(352		)
Equity in earnings of unconsolidated affiliates	647		236			127			(883		)	127
Losses on interest rate derivatives	—		—			(8		)	—			(8		)
Other, net	—		1			56			—			57
Income before income tax benefit	647		205			634			(883		)	603
Income tax benefit	—		—			(112		)	—			(112		)
Net income	647		205			746			(883		)	715
Less: Net income attributable to noncontrolling interest	—		—			110			—			110
Net income attributable to partners	$	647	$	205		$	636		$	(883	)	$	605

Other comprehensive income	$	—	$	—		$	7		$	—		$	7
Comprehensive income	647		205			753			(883		)	722
Comprehensive income attributable to noncontrolling interest	—		—			110			—			110
Comprehensive income attributable to partners	$	647	$	205		$	643		$	(883	)	$	612

* As adjusted. See Note 1.



	Nine Months Ended September 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	27,331		$	—		$	27,331
Operating costs, expenses, and other	—			—			23,910			—			23,910
Operating income	—			—			3,421			—			3,421
Interest expense, net	(870		)	(137		)	(84		)	—			(1,091		)
Equity in earnings of unconsolidated affiliates	3,036			827			147			(3,863		)	147
Gain on Sunoco LP unit repurchase	—			—			172			—			172
Loss on deconsolidation of CDM	—			—			(86		)	—			(86		)
Gains on interest rate derivatives	117			—			—			—			117
Other, net	—			—			127			—			127
Income before income tax benefit	2,283			690			3,697			(3,863		)	2,807
Income tax benefit	—			—			(32		)	—			(32		)
Net income	2,283			690			3,729			(3,863		)	2,839
Less: Net income attributable to noncontrolling interest	—			—			557			—			557
Net income attributable to partners	$	2,283		$	690		$	3,172		$	(3,863	)	$	2,282

Other comprehensive income	$	—		$	—		$	7		$	—		$	7
Comprehensive income	2,283			690			3,736			(3,863		)	2,846
Comprehensive income attributable to noncontrolling interest	—			—			557			—			557
Comprehensive income attributable to partners	$	2,283		$	690		$	3,179		$	(3,863	)	$	2,289



	Nine Months Ended September 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	20,444		$	—		$	20,444
Operating costs, expenses, and other	—		1			18,245			—			18,246
Operating income (loss)	—		(1		)	2,199			—			2,198
Interest expense, net	—		(113		)	(907		)	—			(1,020		)
Equity in earnings of unconsolidated affiliates	1,657		1,001			139			(2,658		)	139
Losses on interest rate derivatives	—		—			(28		)	—			(28		)
Other, net	—		4			134			(1		)	137
Income before income tax expense	1,657		891			1,537			(2,659		)	1,426
Income tax expense	—		—			22			—			22
Net income	1,657		891			1,515			(2,659		)	1,404
Less: Net income attributable to noncontrolling interest	—		—			266			—			266
Net income attributable to partners	$	1,657	$	891		$	1,249		$	(2,659	)	$	1,138

Other comprehensive income	$	—	$	—		$	6		$	—		$	6
Comprehensive income	1,657		891			1,521			(2,659		)	1,410
Comprehensive income attributable to noncontrolling interest	—		—			266			—			266
Comprehensive income attributable to partners	$	1,657	$	891		$	1,255		$	(2,659	)	$	1,144

* As adjusted. See Note 1.



	Nine Months Ended September 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	2,753		$	582		$	3,843		$	(2,078	)	$	5,100
Cash flows used in investing activities	(834		)	(579		)	(3,732		)	2,078			(3,067		)
Cash flows used in financing activities	(1,919		)	—			(41		)	—			(1,960		)
Change in cash	—			3			70			—			73
Cash at beginning of period	—			(3		)	309			—			306
Cash at end of period	$	—		$	—		$	379		$	—		$	379



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

Operations And Basis of Presentation Accounting Policy (Policies)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

Basis of Presentation

Accounting Changes [Policy Text Block]

Change in Accounting Policy

Inventory Accounting Change

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition Standard



	Three Months Ended September 30, 2018							Nine Months Ended September 30, 2018
	As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)			As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)
Revenues:
Natural gas sales	$	1,026	$	1,026	$	—		$	3,112	$	3,112	$	—
NGL sales	2,695		2,686		9			6,866		6,839		27
Crude sales	3,841		3,838		3			11,336		11,326		10
Gathering, transportation and other fees	1,579		1,783		(204		)	4,440		4,977		(537		)
Refined product sales	382		381		1			1,234		1,233		1
Other	118		118		—			343		343		—

Costs and expenses:
Cost of products sold	$	6,745	$	6,949	$	(204	)	$	19,873	$	20,410	$	(537	)
Operating expenses	632		619		13			1,863		1,825		38

Additional disclosures related to revenue are included in Note 11.

Disaggregation of revenue


•	intrastate transportation and storage;


•	interstate transportation and storage;


•	midstream;


•	NGL and refined products transportation and services;


•	crude oil transportation and services; and


•	all other.

Note 14 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.

Intrastate transportation and storage revenue

Interstate transportation and storage revenue

Midstream revenue


•	In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.

•

Payment for services under these contracts are typically due the month after the services have been performed.

NGL and refined products transportation and services revenue

Crude oil transportation and services revenue

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606.

All other revenue

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

New Accounting Pronouncements, Policy [Policy Text Block]

Recent Accounting Pronouncements

ASU 2016-02

ASU 2017-12

ASU 2018-02

Cash And Cash Equivalents Cash and Cash Equivalents (Policies)	9 Months Ended
	Sep. 30, 2018
Cash and Cash Equivalents [Abstract]
Cash and Cash Equivalents, Unrestricted Cash and Cash Equivalents, Policy [Policy Text Block]	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.

Inventories Inventories (Policies)	9 Months Ended
Inventories Inventories (Policies)	Sep. 30, 2018
Inventory Disclosure [Abstract]
Inventory, Policy [Policy Text Block]	We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.

Fair Value Measurements Fair Value Measurements (Policies)	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurement, Policy [Policy Text Block]	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, 2018 was $34.39 billion and $33.85 billion, respectively. As of December 31, 2017, the aggregate fair value and carrying amount of our consolidated debt obligations was $34.28 billion and $33.09 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, 2018, no transfers were made between any levels within the fair value hierarchy.

Revenue (Policies)

9 Months Ended

Sep. 30, 2018

Revenue [Abstract]

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition Standard



	Three Months Ended September 30, 2018							Nine Months Ended September 30, 2018
	As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)			As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)
Revenues:
Natural gas sales	$	1,026	$	1,026	$	—		$	3,112	$	3,112	$	—
NGL sales	2,695		2,686		9			6,866		6,839		27
Crude sales	3,841		3,838		3			11,336		11,326		10
Gathering, transportation and other fees	1,579		1,783		(204		)	4,440		4,977		(537		)
Refined product sales	382		381		1			1,234		1,233		1
Other	118		118		—			343		343		—

Costs and expenses:
Cost of products sold	$	6,745	$	6,949	$	(204	)	$	19,873	$	20,410	$	(537	)
Operating expenses	632		619		13			1,863		1,825		38

Additional disclosures related to revenue are included in Note 11.

Disaggregation of revenue


•	intrastate transportation and storage;


•	interstate transportation and storage;


•	midstream;


•	NGL and refined products transportation and services;


•	crude oil transportation and services; and


•	all other.

Note 14 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.

Intrastate transportation and storage revenue

Interstate transportation and storage revenue

Midstream revenue


•	In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.

•

Payment for services under these contracts are typically due the month after the services have been performed.

NGL and refined products transportation and services revenue

Crude oil transportation and services revenue

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606.

All other revenue

Revenue Recognition, Deferred Revenue [Policy Text Block]

Contract Balances with Customers

Derivative Assets And Liabilities Derivative Assets and Liabilities (Policies)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Concentration Risk, Credit Risk, Policy [Policy Text Block]	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.
Derivatives, Policy [Policy Text Block]	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 utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. 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.

Operations And Basis of Presentation Operations and Basis of Presentation (Tables)

9 Months Ended

Sep. 30, 2018

Operations and Basis of Presentation [Abstract]

Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]

As a result of this change in accounting policy, the consolidated statement of operations and comprehensive income in prior periods have been retrospectively adjusted, as follows:



	Three Months Ended September 30, 2017							Nine Months Ended September 30, 2017
	As Originally Reported		Effect of Change			As Adjusted		As Originally Reported		Effect of Change			As Adjusted
Cost of products sold	$	4,876	$	46		$	4,922	$	14,582	$	13		$	14,595
Operating income	825		(46		)	779		2,211		(13		)	2,198
Income before income tax expense (benefit)	649		(46		)	603		1,439		(13		)	1,426
Net income	761		(46		)	715		1,417		(13		)	1,404
Net income attributable to partners	651		(46		)	605		1,174		(36		)	1,138
Comprehensive income	768		(46		)	722		1,423		(13		)	1,410
Comprehensive income attributable to partners	658		(46		)	612		1,180		(36		)	1,144

As a result of this change in accounting policy, the consolidated statement of cash flows in prior periods have been retrospectively adjusted, as follows:



	Nine Months Ended September 30, 2017
	As Originally Reported			Effect of Change			As Adjusted
Net income	$	1,417		$	(13	)	$	1,404
Inventory valuation adjustments	(30		)	30			—
Net change in operating assets and liabilities, net of effects from acquisitions (change in inventories)	185			(17		)	168



	Three Months Ended September 30, 2018							Nine Months Ended September 30, 2018
	As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)			As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)
Revenues:
Natural gas sales	$	1,026	$	1,026	$	—		$	3,112	$	3,112	$	—
NGL sales	2,695		2,686		9			6,866		6,839		27
Crude sales	3,841		3,838		3			11,336		11,326		10
Gathering, transportation and other fees	1,579		1,783		(204		)	4,440		4,977		(537		)
Refined product sales	382		381		1			1,234		1,233		1
Other	118		118		—			343		343		—

Costs and expenses:
Cost of products sold	$	6,745	$	6,949	$	(204	)	$	19,873	$	20,410	$	(537	)
Operating expenses	632		619		13			1,863		1,825		38

Additional disclosures related to revenue are included in Note 11.

Acquisitions and Other Transactions Dropdown Transaction (Tables)

9 Months Ended

Sep. 30, 2018

Dropdown Transaction [Abstract]

Business Combination, Separately Recognized Transactions [Table Text Block]



	Sunoco LP		USAC		Lake Charles LNG and Other
Current assets	$	1,331	$	230	$	28
Property, plant and equipment, net	1,494		2,541		746
Goodwill	1,534		619		184
Intangible assets	655		399		35
Other non-current assets	134		25		909
Total assets	$	5,148	$	3,814	$	1,902

Current liabilities	$	1,086	$	173	$	107
Long-term debt, less current maturities	2,774		1,731		—
Other non-current liabilities	343		6		8
Preferred Units	—		477		—
Net assets	$	945	$	1,427	$	1,787



	Unaudited Pro Forma
	Nine Months Ended September 30,
	2018		2017
Revenues	$	40,514	$	29,072
Net income attributable to partners	$	2,282	$	1,138

Cash And Cash Equivalents (Tables)

9 Months Ended

Sep. 30, 2018

Cash and Cash Equivalents [Abstract]

Net Cash Provided By Operating Activities

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 September 30,
	2018			2017*
Accounts receivable	$	251		$	(77	)
Accounts receivable from related companies	206			46
Inventories	48			133
Other current assets	(23		)	37
Other non-current assets, net	(99		)	(89		)
Accounts payable	(177		)	96
Accounts payable to related companies	(199		)	(11		)
Accrued and other current liabilities	351			(26		)
Other non-current liabilities	21			57
Derivative assets and liabilities, net	72			2
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	451		$	168

* As adjusted. See Note 1.

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

Non-cash investing and financing activities are as follows:



	Nine Months Ended September 30,
	2018		2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,026	$	1,236
USAC limited partner interests received in the CDM Contribution (see Note 2)	411		—
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	—	$	988

Inventories (Tables)

9 Months Ended

Sep. 30, 2018

Inventory, Gross [Abstract]

Schedule Of Inventories

Inventories consisted of the following:



	September 30, 2018		December 31, 2017
Natural gas, NGLs and refined products	$	615	$	733
Crude oil	643		551
Spare parts and other	249		305
Total inventories	$	1,507	$	1,589

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2018

Fair Value Measurements [Abstract]

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



				Fair Value Measurements at September 30, 2018
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	48		$	48		$	—
Swing Swaps IFERC	1			—			1
Fixed Swaps/Futures	25			25			—
Forward Physical Contracts	12			—			12
Power:
Forwards	36			—			36
Options – Puts	1			1			—
NGLs – Forwards/Swaps	476			476			—
Total commodity derivatives	599			550			49
Other non-current assets	28			18			10
Total assets	$	627		$	568		$	59
Liabilities:
Interest rate derivatives	$	(97	)	$	—		$	(97	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(89		)	(89		)	—
Swing Swaps IFERC	(1		)	—			(1		)
Fixed Swaps/Futures	(26		)	(26		)	—
Forward Physical Contracts	(7		)	—			(7		)
Power:
Forwards	(30		)	—			(30		)
Futures	(1		)	(1		)	—
NGLs – Forwards/Swaps	(521		)	(521		)	—
Refined Products – Futures	(5		)	(5		)	—
Crude – Forwards/Swaps	(190		)	(190		)	—
Total commodity derivatives	(870		)	(832		)	(38		)
Total liabilities	$	(967	)	$	(832	)	$	(135	)



				Fair Value Measurements at December 31, 2017
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	11		$	11		$	—
Swing Swaps IFERC	13			—			13
Fixed Swaps/Futures	70			70			—
Forward Physical Contracts	8			—			8
Power – Forwards	23			—			23
NGLs – Forwards/Swaps	191			191			—
Crude:
Forwards/Swaps	2			2			—
Futures	2			2			—
Total commodity derivatives	320			276			44
Other non-current assets	21			14			7
Total assets	$	341		$	290		$	51
Liabilities:
Interest rate derivatives	$	(219	)	$	—		$	(219	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(24		)	(24		)	—
Swing Swaps IFERC	(15		)	(1		)	(14		)
Fixed Swaps/Futures	(57		)	(57		)	—
Forward Physical Contracts	(2		)	—			(2		)
Power – Forwards	(22		)	—			(22		)
NGLs – Forwards/Swaps	(186		)	(186		)	—
Refined Products – Futures	(25		)	(25		)	—
Crude:
Forwards/Swaps	(6		)	(6		)	—
Futures	(1		)	(1		)	—
Total commodity derivatives	(338		)	(300		)	(38		)
Total liabilities	$	(557	)	$	(300	)	$	(257	)

Equity (Tables)

9 Months Ended

Sep. 30, 2018

Change In Common Units

The changes in outstanding common units during the nine months ended September 30, 2018 were as follows:



	Number of Units
Number of common units at December 31, 2017	1,164.1
Common units issued in connection with the distribution reinvestment plan	2.9
Common units issued in connection with certain transactions	1.3
Issuance of common units under equity incentive plans	0.1
Repurchases of common units in open-market transactions	(1.2	)
Number of common units at September 30, 2018	1,167.2

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

Distributions on common units declared and paid by the Partnership subsequent to December 31, 2017 but prior to the closing of the ETE-ETP Merger as discussed in Note 1 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2017	February 8, 2018	February 14, 2018	$	0.5650
March 31, 2018	May 7, 2018	May 15, 2018	0.5650
June 30, 2018	August 6, 2018	August 14, 2018	0.5650

Schedule of Preferred Units [Table Text Block]

Distributions on ETP’s preferred units declared and/or paid by the Partnership subsequent to December 31, 2017 were as follows:



Period Ended	Record Date	Payment Date	Rate
Series A Preferred Units
December 31, 2017	February 1, 2018	February 15, 2018	$	15.451
June 30, 2018	August 1, 2018	August 15, 2018	31.250
Series B Preferred Units
December 31, 2017	February 1, 2018	February 15, 2018	$	16.378
June 30, 2018	August 1, 2018	August 15, 2018	33.125
Series C Preferred Units
June 30, 2018	August 1, 2018	August 15, 2018	$	0.5634
September 30, 2018	November 1, 2018	November 15, 2018	0.4609
Series D Preferred Units
September 30, 2018	November 1, 2018	November 15, 2018	$	0.5931

Accumulated Other Comprehensive Income

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



	September 30, 2018			December 31, 2017
Available-for-sale securities ⁽¹⁾	$	6		$	8
Foreign currency translation adjustment	(5		)	(5		)
Actuarial loss related to pensions and other postretirement benefits	(7		)	(5		)
Investments in unconsolidated affiliates, net	14			5
Total AOCI, net of tax	$	8		$	3


⁽¹⁾	Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which resulted in the reclassification of $2 million from accumulated other comprehensive income related to available-for-sale securities to common unitholders.

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

9 Months Ended

Sep. 30, 2018

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

Schedule of Rent Expense [Table Text Block]



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Rental expense	$	21	$	29	$	60	$	68

Environmental Exit Costs by Cost [Table Text Block]



	September 30, 2018		December 31, 2017
Current	$	36	$	36
Non-current	281		314
Total environmental liabilities	$	317	$	350

Revenue (Tables)

9 Months Ended

Sep. 30, 2018

Revenue [Abstract]

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]



	Years Ending December 31,
	2018 (remainder)		2019		2020		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2018	$	1,426	$	5,066	$	4,568	$	29,069	$	40,129

Derivative Assets And Liabilities (Tables)

9 Months Ended

Sep. 30, 2018

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:



	September 30, 2018			December 31, 2017
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	358		2018-2019	1,078		2018
Basis Swaps IFERC/NYMEX ⁽¹⁾	69,685		2018-2020	48,510		2018-2020
Options – Puts	(17,273	)	2019	13,000		2018
Power (Megawatt):
Forwards	429,720		2018-2019	435,960		2018-2019
Futures	309,123		2018-2019	(25,760	)	2018
Options – Puts	157,435		2018-2019	(153,600	)	2018
Options – Calls	321,240		2018-2019	137,600		2018
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(7,705	)	2018-2021	4,650		2018-2020
Swing Swaps IFERC	69,145		2018-2019	87,253		2018-2019
Fixed Swaps/Futures	(1,784	)	2018-2020	(4,700	)	2018-2019
Forward Physical Contracts	(54,151	)	2018-2020	(145,105	)	2018-2020
NGL (MBbls) – Forwards/Swaps	(4,997	)	2018-2019	(2,493	)	2018-2019
Crude (MBbls) – Forwards/Swaps	35,280		2018-2019	9,172		2018-2019
Refined Products (MBbls) – Futures	(1,521	)	2018-2019	(3,783	)	2018-2019
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(21,475	)	2018-2019	(39,770	)	2018
Fixed Swaps/Futures	(21,475	)	2018-2019	(39,770	)	2018
Hedged Item – Inventory	21,475		2018-2019	39,770		2018


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

Interest Rate Swaps Outstanding

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



Term	Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	September 30, 2018		December 31, 2017
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	$	—	$	300
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.56% and receive a floating rate	400		300
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		400
July 2021⁽²⁾	Forward-starting to pay a fixed rate of 3.55% 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, 2018		December 31, 2017		September 30, 2018			December 31, 2017
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	14	$	(6	)	$	(2	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	477		262		(537		)	(281		)
Commodity derivatives	122		44		(327		)	(55		)
Interest rate derivatives	—		—		(97		)	(219		)
	599		306		(961		)	(555		)
Total derivatives	$	599	$	320	$	(967	)	$	(557	)

Derivatives, Offsetting Fair Value Amounts [Table Text Block]



		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	September 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(97	)	$	(219	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	122			44			(327		)	(55		)
Broker cleared derivative contracts	Other current assets (liabilities)	477			276			(543		)	(283		)
Total gross derivatives		599			320			(967		)	(557		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(29		)	(20		)	29			20
Counterparty netting	Other current assets (liabilities)	(477		)	(263		)	477			263
Total net derivatives		$	93		$	37		$	(461	)	$	(274	)

Derivatives Not Designated as Hedging Instruments [Table Text Block]

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



	Location of Gain Recognized in Income on Derivatives	Amount of Gain Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended September 30,				Nine Months Ended September 30,
		2018		2017		2018		2017
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	—	$	2	$	9	$	4



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,					Nine Months Ended September 30,
		2018		2017			2018			2017
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	3	$	(5	)	$	36		$	21
Commodity derivatives – Non-trading	Cost of products sold	21		(12		)	(352		)	(15		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	45		(8		)	117			(28		)
Embedded derivatives	Other, net	—		—			—			1
Total		$	69	$	(25	)	$	(199	)	$	(21	)

- Definition

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

+ References

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+ Details

Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2018

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Affiliated revenues	$	192	$	190	$	700	$	441



	September 30, 2018		December 31, 2017
Accounts receivable from related companies:
ETE	$	42	$	—
FGT	15		11
Phillips 66	30		20
Sunoco LP	207		219
Trans-Pecos Pipeline, LLC	10		1
Other	29		67
Total accounts receivable from related companies:	$	333	$	318

Accounts payable to related companies:
Sunoco LP	$	178	$	195
USAC	45		—
Other	64		14
Total accounts payable to related companies:	$	287	$	209



	September 30, 2018		December 31, 2017
Long-term notes receivable from related company:
Sunoco LP	$	85	$	85

Reportable Segments (Tables)

9 Months Ended

Sep. 30, 2018

Sales Revenue, Segment [Member]

Segment Reporting Information [Line Items]

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

The following tables present financial information by segment:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	846		$	729		$	2,424		$	2,196
Intersegment revenues	76			44			186			146
	922			773			2,610			2,342
Interstate transportation and storage:
Revenues from external customers	390			220			1,026			652
Intersegment revenues	5			4			13			14
	395			224			1,039			666
Midstream:
Revenues from external customers	537			665			1,571			1,863
Intersegment revenues	1,716			1,100			4,170			3,154
	2,253			1,765			5,741			5,017
NGL and refined products transportation and services:
Revenues from external customers	2,948			1,989			7,878			5,874
Intersegment revenues	115			81			299			241
	3,063			2,070			8,177			6,115
Crude oil transportation and services:
Revenues from external customers	4,422			2,714			12,942			7,749
Intersegment revenues	16			11			44			16
	4,438			2,725			12,986			7,765
All other:
Revenues from external customers	498			656			1,490			2,110
Intersegment revenues	27			27			108			139
	525			683			1,598			2,249
Eliminations	(1,955		)	(1,267		)	(4,820		)	(3,710		)
Total revenues	$	9,641		$	6,973		$	27,331		$	20,444

Operating Segments [Member]

Segment Reporting Information [Line Items]

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017*			2018			2017*
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	221		$	163		$	621		$	480
Interstate transportation and storage	416			273			1,069			800
Midstream	434			356			1,225			1,088
NGL and refined products transportation and services	498			439			1,410			1,208
Crude oil transportation and services	682			420			1,694			835
All other	78			133			242			363
Total	2,329			1,784			6,261			4,774
Depreciation, depletion and amortization	(636		)	(596		)	(1,827		)	(1,713		)
Interest expense, net	(387		)	(352		)	(1,091		)	(1,020		)
Gain on Sunoco LP common unit repurchase	—			—			172			—
Loss on deconsolidation of CDM	—			—			(86		)	—
Gains (losses) on interest rate derivatives	45			(8		)	117			(28		)
Non-cash compensation expense	(20		)	(19		)	(61		)	(57		)
Unrealized gains (losses) on commodity risk management activities	97			(81		)	(255		)	17
Adjusted EBITDA related to unconsolidated affiliates	(257		)	(279		)	(670		)	(765		)
Equity in earnings of unconsolidated affiliates	113			127			147			139
Other, net	13			27			100			79
Income before income tax (expense) benefit	$	1,297		$	603		$	2,807		$	1,426

Assets Segments [Member]

Segment Reporting Information [Line Items]

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



	September 30, 2018		December 31, 2017
Assets:
Intrastate transportation and storage	$	5,874	$	5,020
Interstate transportation and storage	14,143		13,518
Midstream	20,175		20,004
NGL and refined products transportation and services	18,438		17,600
Crude oil transportation and services	17,458		17,736
All other	3,068		4,087
Total assets	$	79,156	$	77,965

Guarantor Financial Information (Tables)

9 Months Ended

Sep. 30, 2018

Guarantor Financial Information [Abstract]

Condensed Income Statement [Table Text Block]

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



	September 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	—		$	379	$	—		$	379
All other current assets	4			56			6,806		(892		)	5,974
Property, plant and equipment, net	—			—			60,550		—			60,550
Investments in unconsolidated affiliates	49,614			12,435			3,599		(62,049		)	3,599
All other assets	8			75			8,571		—			8,654
Total assets	$	49,626		$	12,566		$	79,905	$	(62,941	)	$	79,156

Current liabilities	$	(1,118	)	$	(3,407	)	$	14,675	$	(892	)	$	9,258
Non-current liabilities	22,823			7,605			4,794		—			35,222
Noncontrolling interest	—			—			6,334		—			6,334
Total partners’ capital	27,921			8,368			54,102		(62,049		)	28,342
Total liabilities and equity	$	49,626		$	12,566		$	79,905	$	(62,941	)	$	79,156



	December 31, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	(3	)	$	309	$	—		$	306
All other current assets	—			159			6,063		—			6,222
Property, plant and equipment, net	—			—			58,437		—			58,437
Investments in unconsolidated affiliates	48,378			11,648			3,816		(60,026		)	3,816
All other assets	—			—			9,184		—			9,184
Total assets	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965

Current liabilities	$	(1,496	)	$	(3,660	)	$	12,150	$	—		$	6,994
Non-current liabilities	21,604			7,607			7,609		—			36,820
Noncontrolling interest	—			—			5,882		—			5,882
Total partners’ capital	28,270			7,857			52,168		(60,026		)	28,269
Total liabilities and equity	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965



	Three Months Ended September 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	9,641		$	—		$	9,641
Operating costs, expenses, and other	—			—			8,136			—			8,136
Operating income	—			—			1,505			—			1,505
Interest expense, net	(303		)	(55		)	(29		)	—			(387		)
Equity in earnings of unconsolidated affiliates	1,394			501			113			(1,895		)	113
Gains on interest rate derivatives	45			—			—			—			45
Other, net	—			—			21			—			21
Income before income tax benefit	1,136			446			1,610			(1,895		)	1,297
Income tax benefit	—			—			(61		)	—			(61		)
Net income	1,136			446			1,671			(1,895		)	1,358
Less: Net income attributable to noncontrolling interest	—			—			223			—			223
Net income attributable to partners	$	1,136		$	446		$	1,448		$	(1,895	)	$	1,135

Other comprehensive income	$	—		$	—		$	4		$	—		$	4
Comprehensive income	1,136			446			1,675			(1,895		)	1,362
Comprehensive income attributable to noncontrolling interest	—			—			223			—			223
Comprehensive income attributable to partners	$	1,136		$	446		$	1,452		$	(1,895	)	$	1,139



	Three Months Ended September 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	6,973		$	—		$	6,973
Operating costs, expenses, and other	—		—			6,194			—			6,194
Operating income	—		—			779			—			779
Interest expense, net	—		(32		)	(320		)	—			(352		)
Equity in earnings of unconsolidated affiliates	647		236			127			(883		)	127
Losses on interest rate derivatives	—		—			(8		)	—			(8		)
Other, net	—		1			56			—			57
Income before income tax benefit	647		205			634			(883		)	603
Income tax benefit	—		—			(112		)	—			(112		)
Net income	647		205			746			(883		)	715
Less: Net income attributable to noncontrolling interest	—		—			110			—			110
Net income attributable to partners	$	647	$	205		$	636		$	(883	)	$	605

Other comprehensive income	$	—	$	—		$	7		$	—		$	7
Comprehensive income	647		205			753			(883		)	722
Comprehensive income attributable to noncontrolling interest	—		—			110			—			110
Comprehensive income attributable to partners	$	647	$	205		$	643		$	(883	)	$	612

* As adjusted. See Note 1.



	Nine Months Ended September 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	27,331		$	—		$	27,331
Operating costs, expenses, and other	—			—			23,910			—			23,910
Operating income	—			—			3,421			—			3,421
Interest expense, net	(870		)	(137		)	(84		)	—			(1,091		)
Equity in earnings of unconsolidated affiliates	3,036			827			147			(3,863		)	147
Gain on Sunoco LP unit repurchase	—			—			172			—			172
Loss on deconsolidation of CDM	—			—			(86		)	—			(86		)
Gains on interest rate derivatives	117			—			—			—			117
Other, net	—			—			127			—			127
Income before income tax benefit	2,283			690			3,697			(3,863		)	2,807
Income tax benefit	—			—			(32		)	—			(32		)
Net income	2,283			690			3,729			(3,863		)	2,839
Less: Net income attributable to noncontrolling interest	—			—			557			—			557
Net income attributable to partners	$	2,283		$	690		$	3,172		$	(3,863	)	$	2,282

Other comprehensive income	$	—		$	—		$	7		$	—		$	7
Comprehensive income	2,283			690			3,736			(3,863		)	2,846
Comprehensive income attributable to noncontrolling interest	—			—			557			—			557
Comprehensive income attributable to partners	$	2,283		$	690		$	3,179		$	(3,863	)	$	2,289



	Nine Months Ended September 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	20,444		$	—		$	20,444
Operating costs, expenses, and other	—		1			18,245			—			18,246
Operating income (loss)	—		(1		)	2,199			—			2,198
Interest expense, net	—		(113		)	(907		)	—			(1,020		)
Equity in earnings of unconsolidated affiliates	1,657		1,001			139			(2,658		)	139
Losses on interest rate derivatives	—		—			(28		)	—			(28		)
Other, net	—		4			134			(1		)	137
Income before income tax expense	1,657		891			1,537			(2,659		)	1,426
Income tax expense	—		—			22			—			22
Net income	1,657		891			1,515			(2,659		)	1,404
Less: Net income attributable to noncontrolling interest	—		—			266			—			266
Net income attributable to partners	$	1,657	$	891		$	1,249		$	(2,659	)	$	1,138

Other comprehensive income	$	—	$	—		$	6		$	—		$	6
Comprehensive income	1,657		891			1,521			(2,659		)	1,410
Comprehensive income attributable to noncontrolling interest	—		—			266			—			266
Comprehensive income attributable to partners	$	1,657	$	891		$	1,255		$	(2,659	)	$	1,144

* As adjusted. See Note 1.



	Nine Months Ended September 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	2,753		$	582		$	3,843		$	(2,078	)	$	5,100
Cash flows used in investing activities	(834		)	(579		)	(3,732		)	2,078			(3,067		)
Cash flows used in financing activities	(1,919		)	—			(41		)	—			(1,960		)
Change in cash	—			3			70			—			73
Cash at beginning of period	—			(3		)	309			—			306
Cash at end of period	$	—		$	—		$	379		$	—		$	379



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

Operations And Basis of Presentation Operations And Organization Narrative (Details)	1 Months Ended	3 Months Ended	9 Months Ended
	Apr. 30, 2017	Dec. 31, 2018 shares	Sep. 30, 2018
SXL and ETP Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.5
FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%
Citrus [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%
ET Rover Pipeline, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.10%
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] \| Trans-Pecos Pipeline, LLC
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Subsequent Event [Member] \| ETE Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio		1.28
IDRs [Member] \| Subsequent Event [Member] \| ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction		1,168,205,710
General Partner \| Subsequent Event [Member] \| ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction		18,448,341

Operations And Basis of Presentation Schedule of Change in Accounting Policy (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Cost of products sold	$ 6,745	$ 4,922	$ 19,873	$ 14,595
OPERATING INCOME	1,505	779	3,421	2,198
Income before income tax expense (benefit)	1,297	603	2,807	1,426
Net income	1,358	715	2,839	1,404
Net income attributable to partners	1,135	605	2,282	1,138
Comprehensive income	1,362	722	2,846	1,410
Comprehensive income attributable to partners	1,139	612	2,289	1,144
Inventory, LIFO Reserve, Period Charge				0
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations			451	168
Previously Reported [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Cost of products sold		4,876		14,582
OPERATING INCOME		825		2,211
Income before income tax expense (benefit)		649		1,439
Net income		761		1,417
Net income attributable to partners		651		1,174
Comprehensive income		768		1,423
Comprehensive income attributable to partners		658		1,180
Inventory, LIFO Reserve, Period Charge				(30)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations				(185)
Restatement Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Cost of products sold	$ (204)	46	$ (537)	13
OPERATING INCOME		(46)		(13)
Income before income tax expense (benefit)		(46)		(13)
Net income		(46)		(13)
Net income attributable to partners		(46)		(36)
Comprehensive income		(46)		(13)
Comprehensive income attributable to partners		$ (46)		(36)
Inventory, LIFO Reserve, Period Charge				30
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations				$ 17

Operations And Basis of Presentation Schedule of Impact of Accounting Standard (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Cost of products sold	$ 6,745	$ 4,922	$ 19,873	$ 14,595
Operating expenses	632	571	1,863	1,603
Accounting Standards Update 2014-09 [Member]
Cost of products sold	6,949		20,410
Operating expenses	619		1,825
Natural gas sales [Member]
Revenue from Contract with Customer, Including Assessed Tax	1,026	1,098	3,112	3,132
Natural gas sales [Member] \| Accounting Standards Update 2014-09 [Member]
Revenue from Contract with Customer, Including Assessed Tax	1,026		3,112
NGL sales [Member]
Revenue from Contract with Customer, Including Assessed Tax	2,695	1,750	6,866	4,782
NGL sales [Member] \| Accounting Standards Update 2014-09 [Member]
Revenue from Contract with Customer, Including Assessed Tax	2,686		6,839
Oil and Gas [Member]
Revenue from Contract with Customer, Including Assessed Tax	3,841	2,381	11,336	7,268
Oil and Gas [Member] \| Accounting Standards Update 2014-09 [Member]
Revenue from Contract with Customer, Including Assessed Tax	3,838		11,326
Natural Gas, Midstream [Member]
Revenue from Contract with Customer, Including Assessed Tax	1,579	1,027	4,440	3,118
Natural Gas, Midstream [Member] \| Accounting Standards Update 2014-09 [Member]
Revenue from Contract with Customer, Including Assessed Tax	1,783		4,977
Oil and Gas, Refining and Marketing [Member]
Revenue from Contract with Customer, Including Assessed Tax	382	334	1,234	1,109
Oil and Gas, Refining and Marketing [Member] \| Accounting Standards Update 2014-09 [Member]
Revenue from Contract with Customer, Including Assessed Tax	381		1,233
Product and Service, Other [Member]
Revenue from Contract with Customer, Including Assessed Tax	118	383	343	1,035
Product and Service, Other [Member] \| Accounting Standards Update 2014-09 [Member]
Revenue from Contract with Customer, Including Assessed Tax	118		343
Restatement Adjustment [Member]
Cost of products sold	(204)	$ 46	(537)	$ 13
Operating expenses	13		38
Restatement Adjustment [Member] \| Natural gas sales [Member]
Revenue from Contract with Customer, Including Assessed Tax	0		0
Restatement Adjustment [Member] \| NGL sales [Member]
Revenue from Contract with Customer, Including Assessed Tax	9		27
Restatement Adjustment [Member] \| Oil and Gas [Member]
Revenue from Contract with Customer, Including Assessed Tax	3		10
Restatement Adjustment [Member] \| Natural Gas, Midstream [Member]
Revenue from Contract with Customer, Including Assessed Tax	(204)		(537)
Restatement Adjustment [Member] \| Oil and Gas, Refining and Marketing [Member]
Revenue from Contract with Customer, Including Assessed Tax	1		1
Restatement Adjustment [Member] \| Product and Service, Other [Member]
Revenue from Contract with Customer, Including Assessed Tax	$ 0		$ 0

Acquisitions and Other Transactions Narrative (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended			9 Months Ended
	Apr. 30, 2018	Feb. 28, 2018	Dec. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Advances to and investments in unconsolidated affiliates				$ 3,599		$ 3,599		$ 3,816
Loss on deconsolidation of CDM				0	$ 0	$ (86)	$ 0
Stock Repurchased During Period, Shares						1,200,000
Cash proceeds from Sunoco LP common unit repurchase						$ 540	0
Gain on Sunoco LP common unit repurchase				0	0	172	0
Net Income (Loss) Attributable to Parent				1,135	$ 605	2,282	1,138
Sunoco LP
Stock Repurchased During Period, Shares		17,286,859
Cash proceeds from Sunoco LP common unit repurchase		$ 540
ETE Merger [Member] \| Subsequent Event [Member] \| Sunoco LP
Sale of Stock, Number of Shares Issued in Transaction			2,263,158
ETE Merger [Member] \| Subsequent Event [Member] \| Sunoco GP [Member]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest			100.00%
ETE Merger [Member] \| Subsequent Event [Member] \| USAC [Member]
Sale of Stock, Number of Shares Issued in Transaction			12,466,912
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest			100.00%
ETE Merger [Member] \| Subsequent Event [Member] \| Lake Charles LNG [Member]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest			100.00%
ETE Merger [Member] \| Subsequent Event [Member] \| Energy Transfer LNG Export LLC, ET Crude Oil Terminals LLC, & ETC Illinois LLC [Member]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest			60.00%
USAC Transaction [Member]
Business Combination, Consideration Transferred	$ 1,700
Payments to Acquire Businesses, Gross	$ 1,230
USAC Transaction [Member] \| USA Compression Partners, LP [Member]
Sale of Stock, Number of Shares Issued in Transaction	19,191,351
Class B Units [Member] \| USAC Transaction [Member] \| USA Compression Partners, LP [Member]
Sale of Stock, Number of Shares Issued in Transaction	6,397,965
ETP [Member] \| ETE Merger [Member] \| Subsequent Event [Member] \| Sunoco LP
Sale of Stock, Number of Shares Issued in Transaction			2,874,275
ETP [Member] \| ETE Merger [Member] \| Subsequent Event [Member] \| Sunoco GP [Member]
Sale of Stock, Number of Shares Issued in Transaction			42,812,389
ETP [Member] \| ETE Merger [Member] \| Subsequent Event [Member] \| USAC [Member]
Sale of Stock, Number of Shares Issued in Transaction			16,134,903
ETP [Member] \| ETE Merger [Member] \| Subsequent Event [Member] \| Lake Charles LNG [Member]
Sale of Stock, Number of Shares Issued in Transaction			37,557,815
ETE \| USAC Transaction [Member] \| USA Compression Partners, LP [Member]
Sale of Stock, Number of Shares Issued in Transaction	12,466,912
Equity Issued in Business Combination, Fair Value Disclosure	$ 250
USA Compression Partners, LP [Member]
Advances to and investments in unconsolidated affiliates				385		385
Accrual for Taxes Other than Income Taxes, Current				$ 45		45
Intersegment [Member]
Revenues						40,514	29,072
Net Income (Loss) Attributable to Parent						$ 2,282	$ 1,138

Acquisitions and Other Transactions Balance Sheet Data (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Entity Information [Line Items]
Net Income (Loss) Attributable to Parent	$ 1,135	$ 605	$ 2,282	$ 1,138
Assets, Current	6,353		6,353		$ 6,528
Property, Plant and Equipment, Net	60,550		60,550		58,437
Goodwill	2,866		2,866		3,115
Intangible assets, net	4,925		4,925		5,311
Other Assets, Noncurrent	863		863		758
Assets	79,156		79,156		77,965
Liabilities, Current	9,258		9,258		6,994
Long-term debt, less current maturities	31,198		31,198		32,687
Other non-current liabilities	1,100		1,100		$ 1,084
Sunoco LP
Entity Information [Line Items]
Assets, Current	1,331		1,331
Property, Plant and Equipment, Net	1,494		1,494
Goodwill	1,534		1,534
Intangible assets, net	655		655
Other Assets, Noncurrent	134		134
Assets	5,148		5,148
Liabilities, Current	1,086		1,086
Long-term debt, less current maturities	2,774		2,774
Other non-current liabilities	343		343
Preferred units	0		0
Net Assets	945		945
USAC [Member]
Entity Information [Line Items]
Assets, Current	230		230
Property, Plant and Equipment, Net	2,541		2,541
Goodwill	619		619
Intangible assets, net	399		399
Other Assets, Noncurrent	25		25
Assets	3,814		3,814
Liabilities, Current	173		173
Long-term debt, less current maturities	1,731		1,731
Other non-current liabilities	6		6
Preferred units	477		477
Net Assets	1,427		1,427
Lake Charles LNG [Member]
Entity Information [Line Items]
Assets, Current	28		28
Property, Plant and Equipment, Net	746		746
Goodwill	184		184
Intangible assets, net	35		35
Other Assets, Noncurrent	909		909
Assets	1,902		1,902
Liabilities, Current	107		107
Long-term debt, less current maturities	0		0
Other non-current liabilities	8		8
Preferred units	0		0
Net Assets	$ 1,787		1,787
Intersegment [Member]
Entity Information [Line Items]
Net Income (Loss) Attributable to Parent			$ 2,282	$ 1,138

Advances to and Investments in Affiliates (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Feb. 28, 2018	Sep. 30, 2018	Sep. 30, 2017	Oct. 31, 2018	Apr. 30, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Advances to and investments in unconsolidated affiliates		$ 3,599				$ 3,816
Stock Repurchased During Period, Shares		1,200,000
Cash proceeds from Sunoco LP common unit repurchase		$ 540	$ 0
RIGS Haynesville Partnership Co. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage					50.01%	49.99%
Sunoco LP
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		31.80%
Stock Repurchased During Period, Shares	17,286,859
Cash proceeds from Sunoco LP common unit repurchase	$ 540
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		26,200,000
USAC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		26.60%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		19,200,000
USAC [Member] \| Class B Units [Member]
Schedule of Equity Method Investments [Line Items]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		6,400,000
USA Compression Partners, LP [Member]
Schedule of Equity Method Investments [Line Items]
Advances to and investments in unconsolidated affiliates		$ 385
Sunoco LP
Schedule of Equity Method Investments [Line Items]
Advances to and investments in unconsolidated affiliates		$ 542
Subsequent Event [Member] \| ETE Merger [Member] \| USAC [Member]
Schedule of Equity Method Investments [Line Items]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.				39,700,000
Subsequent Event [Member] \| ETE Merger [Member] \| Sunoco LP
Schedule of Equity Method Investments [Line Items]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.				28,500,000

Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash and Cash Equivalents [Abstract]
Accounts receivable	$ 251	$ (77)
Accounts receivable from related companies	206	46
Inventories	48	133
Other current assets	(23)	37
Other non-current assets, net	(99)	(89)
Accounts payable	(177)	96
Accounts payable to related companies	(199)	(11)
Accrued and other current liabilities	351	(26)
Other non-current liabilities	21	57
Derivative assets and liabilities, net	72	2
Net change in operating assets and liabilities, net of effects of acquisitions	$ 451	$ 168

Cash And Cash Equivalents Non-Cash Investing and Financing Activities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 1,026	$ 1,236
USAC limited partner interests received in the CDM Contribution (see Note 2)	411	0
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$ 0	$ 988

Inventories (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Inventory, Gross [Abstract]
Natural gas, NGLs and refined products	$ 615	$ 733
Crude oil	643	551
Spare parts and other	249	305
Total inventories	$ 1,507	$ 1,589

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Fair Value Measurements [Abstract]
Transfers between levels in fair value hierarchy	$ 0
Aggregate fair value of long-term debt	34,390	$ 34,280
Long-term Debt	$ 33,850	$ 33,090

Debt Obligations Narrative (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 31, 2018	Sep. 30, 2018
Early Repayment of Senior Debt		$ 1,650
Proceeds from Issuance of Senior Long-term Debt		2,960
Bakken Pipeline [Member] \| Bakken Term Note [Member]
Line of Credit Facility, Maximum Borrowing Capacity		2,500
4.20% Senior Notes due 2023 [Member] \| ETP [Member]
Senior Notes		$ 500
Debt Instrument, Interest Rate, Stated Percentage		4.20%
4.95% Senior Notes due 2028 [Member] \| ETP [Member]
Senior Notes		$ 1,000
Debt Instrument, Interest Rate, Stated Percentage		4.95%
5.80% Senior Notes due 2038 [Member] \| ETP [Member]
Senior Notes		$ 500
Debt Instrument, Interest Rate, Stated Percentage		5.80%
6.0% Senior Notes due 2048 [Member] \| ETP [Member]
Senior Notes		$ 1,000
Debt Instrument, Interest Rate, Stated Percentage		6.00%
2.50% Senior Notes due June 2018 [Member] \| ETP [Member]
Senior Notes		$ 650
Debt Instrument, Interest Rate, Stated Percentage		2.50%
7.00% Senior Notes, due June 15, 2018 [Member] \| Panhandle [Member]
Senior Notes		$ 400
Debt Instrument, Interest Rate, Stated Percentage		7.00%
6.7% Senior Notes, due July 1, 2018 [Member] \| ETP [Member]
Senior Notes		$ 600
Debt Instrument, Interest Rate, Stated Percentage		6.70%
ETP Credit Facility due December 2022 [Member] \| ETP [Member]
Line of Credit Facility, Current Borrowing Capacity		$ 2,060
Long-term Line of Credit		1,780
Long-term Commercial Paper, Noncurrent		1,570
Line of Credit Facility, Maximum Borrowing Capacity		4,000
Letters of Credit Outstanding, Amount		$ 163
Line of Credit Facility, Interest Rate at Period End		3.00%
ETP Credit Facility due December 2022 [Member] \| ETP [Member] \| Accordion feature [Member]
Long-term Line of Credit		$ 6,000
ETP $1.0 billion 364-day Credit Facility due December 2018 [Member] \| ETP [Member]
Long-term Line of Credit		0
Line of Credit Facility, Maximum Borrowing Capacity		1,000
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] \| Bakken Project [Member]
Long-term Line of Credit		$ 2,500
Line of Credit Facility, Interest Rate at Period End		3.85%
Subsequent Event [Member] \| ETP Credit Facility due December 2022 [Member] \| ETP [Member]
Line of Credit Facility, Maximum Borrowing Capacity	$ 5,000
Line of Credit Facility, Increase (Decrease), Net	$ 1,000

Equity Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended				9 Months Ended
	Jul. 31, 2018	Apr. 30, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2018	Sep. 30, 2017
Common Units Issued Inconnection With The Equity Distribution Agreement							0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI for Sale of Securities, before Tax							$ 2
Proceeds from Issuance of Preferred Limited Partners Units							867	$ 0
Proceeds from Issuance of Common Limited Partners Units							58	$ 2,162
ETP [Member]
Rate				$ 0.5650	$ 0.5650	$ 0.5650
Stock Issued During Period, Value, Dividend Reinvestment Plan							$ 57
Series A Preferred Units [Member]
Rate				31.250		15.451
Preferred Stock, Shares Issued			950,000				950,000
Series B Preferred Units [Member]
Rate				33.125		$ 16.378
Preferred Stock, Shares Issued			550,000				550,000
Series C Preferred Units [Member]
Rate			$ 0.4609	$ 0.5634
Preferred Units, Issued		18,000,000
Preferred Stock, Dividend Rate, Percentage		7.375%
Shares Issued, Price Per Share		$ 25
Preferred Units, Liquidation Spread, Percent		4.53%
Proceeds from Issuance of Preferred Limited Partners Units		$ 450
Series D Preferred Units [Member]
Rate			$ 0.5931
Preferred Units, Issued	17,800,000
Preferred Stock, Dividend Rate, Percentage	7.625%
Shares Issued, Price Per Share	$ 25
Preferred Units, Liquidation Spread, Percent	4.378%
Proceeds from Issuance of Preferred Limited Partners Units	$ 445

Equity Common Unit Activity (Details) shares in Millions	9 Months Ended
Equity Common Unit Activity (Details) shares in Millions	Sep. 30, 2018 shares
Partners' Capital Notes [Abstract]
Number of common units at December 31, 2017	1,164.1
Common units issued in connection with the distribution reinvestment plan	2.9
Common units issued in connection with certain transactions	1.3
Issuance of common units under equity incentive plans	0.1
Repurchases of common units in open-market transactions	(1.2)
Number of common units at September 30, 2018	1,167.2

Equity Quarterly Distributions Of Available Cash (Details) - $ / shares	3 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017
ETP [Member]
Distribution Made to Member or Limited Partner [Line Items]
Record Date		Aug. 06, 2018	May 07, 2018	Feb. 08, 2018
Payment Date		Aug. 14, 2018	May 15, 2018	Feb. 14, 2018
Rate		$ 0.5650	$ 0.5650	$ 0.5650
Preferred Units [Member]
Distribution Made to Member or Limited Partner [Line Items]
Record Date	Nov. 01, 2018	Aug. 01, 2018		Feb. 01, 2018
Payment Date	Nov. 15, 2018	Aug. 15, 2018		Feb. 15, 2018
Series A Preferred Units [Member]
Distribution Made to Member or Limited Partner [Line Items]
Rate		$ 31.250		$ 15.451
Series B Preferred Units [Member]
Distribution Made to Member or Limited Partner [Line Items]
Rate		33.125		$ 16.378
Series C Preferred Units [Member]
Distribution Made to Member or Limited Partner [Line Items]
Rate	$ 0.4609	$ 0.5634
Series D Preferred Units [Member]
Distribution Made to Member or Limited Partner [Line Items]
Rate	$ 0.5931

Equity AOCI (Details) - USD ($)
$ in Millions

9 Months Ended

12 Months Ended

Sep. 30, 2018

Dec. 31, 2017

Partners' Capital Notes [Abstract]

Available-for-sale securities (1)

^[1]

$ 6

$ 8

Foreign currency translation adjustment

(5)

Actuarial loss related to pensions and other postretirement benefits

(7)

(5)

Investments in unconsolidated affiliates, net

Total AOCI, net of tax

$ 8

$ 3

[1]

Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which resulted in the reclassification of $2 million from accumulated other comprehensive income related to available-for-sale securities to common unitholders.

Income Taxes (Details) $ in Millions	3 Months Ended	9 Months Ended
Income Taxes (Details) $ in Millions	Sep. 30, 2018 USD ($)	Sep. 30, 2018 USD ($)
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	$ 109	$ 179
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Reserves	$ 530	$ 530

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)	1 Months Ended	3 Months Ended		9 Months Ended
	Feb. 28, 2018 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Jan. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Maximum lease expiration year				Dec. 31, 2034
Loss contingency accrual, at carrying value		$ 55,000,000		$ 55,000,000			$ 53,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed		0		0
Accrual for Environmental Loss Contingencies		317,000,000		317,000,000			$ 350,000,000
Civil penalties	$ 12,600,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount		319,000,000		319,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount		595,000,000		595,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount		1,000,000		1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount		536,000,000		536,000,000
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		$ 17,000,000	$ 5,000,000	$ 28,000,000	$ 18,000,000
Sunoco [Member]
Sites where remediation operations are responsibility of third parties		41		41
Rover Pipeline LLC [Member]
Proposed Environmental Penalty		$ 2,600,000		$ 2,600,000
4.875% senior notes due 2023 [Member] \| Sunoco LP
Senior Notes						$ 1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage						4.875%
5.500% senior notes due 2026 [Member] \| Sunoco LP
Senior Notes						$ 800,000,000
Debt Instrument, Interest Rate, Stated Percentage						5.50%
5.875% senior notes due 2028 [Member] \| Sunoco LP
Senior Notes						$ 400,000,000
Debt Instrument, Interest Rate, Stated Percentage						5.875%

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Operating Leases, Rental Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Rental expense	$ 21	$ 29	$ 60	$ 68

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Environmental Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Environmental Exit Cost [Line Items]
Current	$ 36	$ 36
Non-current	281	314
Total environmental liabilities	$ 317	$ 350

Revenue (Details) $ in Millions	3 Months Ended	9 Months Ended
Revenue (Details) $ in Millions	Sep. 30, 2018 USD ($)	Sep. 30, 2018 USD ($)
Contract with Customer, Asset, Gross	$ 0	$ 0
Deferred Revenue	349	349
Contract with Customer, Liability, Revenue Recognized	12	75
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-12-31
Revenue, Remaining Performance Obligation, Amount	1,426	1,426
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-12-31
Revenue, Remaining Performance Obligation, Amount	5,066	5,066
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-12-31
Revenue, Remaining Performance Obligation, Amount	4,568	4,568
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-12-31
Revenue, Remaining Performance Obligation, Amount	29,069	29,069
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Amount	$ 40,129	$ 40,129

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

9 Months Ended

Sep. 30, 2018

Dec. 31, 2017

July 2018 [Member]

Notional Amount

^[1]

$ 0

$ 300

Type

^[1],[2]

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

December 2018 [Member]

Notional Amount

$ 1,200

1,200

Type

^[2]

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

July 2019 [Member]

Notional Amount

^[1]

$ 400

300

Type

^[1],[2]

Forward-starting to pay a fixed rate of 3.56% and receive a floating rate

July 2020 [Member]

Notional Amount

^[1]

$ 400

400

Type

^[1],[2]

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

July 2021 [Member]

Notional Amount

^[1]

$ 400

Type

^[1],[2]

Forward-starting to pay a fixed rate of 3.55% and receive a floating rate

March 2019 [Member]

Notional Amount

$ 300

Type

^[2]

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

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

Derivative Assets And Liabilities Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Total derivatives assets	$ 599	$ 320
Total derivatives liabilities	(967)	(557)
Designated as Hedging Instrument [Member] \| Commodity derivatives (margin deposits)
Total derivatives assets	0	14
Total derivatives liabilities	(6)	(2)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	599	306
Total derivatives liabilities	(961)	(555)
Not Designated as Hedging Instrument [Member] \| Commodity derivatives (margin deposits)
Total derivatives assets	477	262
Total derivatives liabilities	(537)	(281)
Not Designated as Hedging Instrument [Member] \| Commodity derivatives
Total derivatives assets	122	44
Total derivatives liabilities	(327)	(55)
Not Designated as Hedging Instrument [Member] \| Interest rate derivatives
Total derivatives assets	0	0
Total derivatives liabilities	$ (97)	$ (219)

Derivative Assets And Liabilities Fair Value of Derivatives, Netting Basis (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 599	$ 320
Derivative Liability, Fair Value, Gross Liability	(967)	(557)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(29)	(20)
Derivative Liability, Fair Value, Amount Offset Against Collateral	29	20
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(477)	(263)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	477	263
Derivative Asset, Fair Value, Net	93	37
Derivative Liability, Fair Value, Net	(461)	(274)
Without offsetting agreements [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(97)	(219)
OTC Contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	122	44
Derivative Liability, Fair Value, Gross Liability	(327)	(55)
Broker cleared derivative contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	477	276
Derivative Liability, Fair Value, Gross Liability	$ (543)	$ (283)

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, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Commodity Derivatives [Member]
Commodity derivatives	$ 0	$ 2	$ 9	$ 4

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, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 69	$ (25)	$ (199)	$ (21)
Gains (losses) on interest rate derivatives	45	(8)	117	(28)
Commodity Derivatives - Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	3	(5)	36	21
Commodity derivatives
Amount of Gain Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	0	2	9	4
Amount of Gain/(Loss) Recognized in Income on Derivatives	21	(12)	(352)	(15)
Other Income (Expenses) [Member] \| Embedded Derivatives in Preferred Units [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 0	$ 0	$ 0	$ 1

Related Party Transactions Affiliated Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Related Party Transactions [Abstract]
Affiliated revenues	$ 192	$ 190	$ 700	$ 441

Related Party Transactions Related Party A/R and A/P (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Total accounts receivable from related companies:	$ 333	$ 318
Total accounts payable to related companies:	287	209
USAC [Member]
Total accounts payable to related companies:	45	0
ETE
Total accounts receivable from related companies:	42	0
Sunoco LP
Notes Receivable, Related Parties, Noncurrent	85	85
Total accounts receivable from related companies:	207	219
Total accounts payable to related companies:	178	195
Trans-Pecos Pipeline, LLC [Member]
Total accounts receivable from related companies:	10	1
Trans-Pecos Pipeline, LLC
Total accounts receivable from related companies:	15	11
Phillips 66 Company [Member]
Total accounts receivable from related companies:	30	20
Other
Total accounts receivable from related companies:	29	67
Total accounts payable to related companies:	$ 64	$ 14

Reportable Segments Segment Revenues (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting Information [Line Items]
Revenues	$ 9,641	$ 6,973	$ 27,331	$ 20,444
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Revenues	922	773	2,610	2,342
Intrastate transportation and storage \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	846	729	2,424	2,196
Intrastate transportation and storage \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	76	44	186	146
Interstate transportation and storage
Segment Reporting Information [Line Items]
Revenues	395	224	1,039	666
Interstate transportation and storage \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	390	220	1,026	652
Interstate transportation and storage \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	5	4	13	14
Midstream
Segment Reporting Information [Line Items]
Revenues	2,253	1,765	5,741	5,017
Midstream \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	537	665	1,571	1,863
Midstream \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	1,716	1,100	4,170	3,154
NGL and refined products transportation and services
Segment Reporting Information [Line Items]
Revenues	3,063	2,070	8,177	6,115
NGL and refined products transportation and services \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	2,948	1,989	7,878	5,874
NGL and refined products transportation and services \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	115	81	299	241
Crude oil transportation and services
Segment Reporting Information [Line Items]
Revenues	4,438	2,725	12,986	7,765
Crude oil transportation and services \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	4,422	2,714	12,942	7,749
Crude oil transportation and services \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	16	11	44	16
All other
Segment Reporting Information [Line Items]
Revenues	525	683	1,598	2,249
All other \| Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	498	656	1,490	2,110
All other \| Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	27	27	108	139
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (1,955)	$ (1,267)	$ (4,820)	$ (3,710)

Reportable Segments Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 2,329	$ 1,784	$ 6,261	$ 4,774
Depreciation, depletion and amortization	(636)	(596)	(1,827)	(1,713)
Interest expense, net	(387)	(352)	(1,091)	(1,020)
Gain on Sunoco LP common unit repurchase	0	0	172	0
Loss on deconsolidation of CDM	0	0	(86)	0
Gains (losses) on interest rate derivatives	45	(8)	117	(28)
Non-cash compensation expense	(20)	(19)	(61)	(57)
Unrealized gains (losses) on commodity risk management activities	97	(81)	(255)	17
Adjusted EBITDA related to unconsolidated affiliates	(257)	(279)	(670)	(765)
Equity in earnings of unconsolidated affiliates	113	127	147	139
Other, net	13	27	100	79
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	1,297	603	2,807	1,426
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	221	163	621	480
Interstate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	416	273	1,069	800
Midstream
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	434	356	1,225	1,088
NGL and refined products transportation and services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	498	439	1,410	1,208
Crude oil transportation and services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	682	420	1,694	835
All other
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 78	$ 133	$ 242	$ 363

Reportable Segments Segment Assets (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Assets	$ 79,156	$ 77,965
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Assets	5,874	5,020
Interstate transportation and storage
Segment Reporting Information [Line Items]
Assets	14,143	13,518
Midstream
Segment Reporting Information [Line Items]
Assets	20,175	20,004
NGL and refined products transportation and services
Segment Reporting Information [Line Items]
Assets	18,438	17,600
Crude oil transportation and services
Segment Reporting Information [Line Items]
Assets	17,458	17,736
All other
Segment Reporting Information [Line Items]
Assets	$ 3,068	$ 4,087

Guarantor Financial Information Balance Sheet (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Cash and Cash Equivalents, at Carrying Value	$ 379	$ 306	$ 379	$ 360
Other current assets	5,974	6,222
Property, Plant and Equipment, Net	60,550	58,437
Advances to and investments in unconsolidated affiliates	3,599	3,816
Other Assets, Noncurrent	8,654	9,184
Assets	79,156	77,965
Liabilities, Current	9,258	6,994
Liabilities, Noncurrent	35,222	36,820
Noncontrolling interest	6,334	5,882
Other non-current liabilities	1,100	1,084
Partners' Capital	28,342	28,269
Liabilities and Equity	79,156	77,965
Parent Guarantor [Member]
Cash and Cash Equivalents, at Carrying Value	0	0	0	0
Other current assets	4	0
Property, Plant and Equipment, Net	0	0
Advances to and investments in unconsolidated affiliates	49,614	48,378
Other Assets, Noncurrent	8	0
Assets	49,626	48,378
Liabilities, Current	(1,118)	(1,496)
Liabilities, Noncurrent	22,823	21,604
Noncontrolling interest	0	0
Partners' Capital	27,921	28,270
Liabilities and Equity	49,626	48,378
Subsidiary Issuer [Member]
Cash and Cash Equivalents, at Carrying Value	0	(3)	49	41
Other current assets	56	159
Property, Plant and Equipment, Net	0	0
Advances to and investments in unconsolidated affiliates	12,435	11,648
Other Assets, Noncurrent	75	0
Assets	12,566	11,804
Liabilities, Current	(3,407)	(3,660)
Liabilities, Noncurrent	7,605	7,607
Noncontrolling interest	0	0
Partners' Capital	8,368	7,857
Liabilities and Equity	12,566	11,804
Non-Guarantor Subsidiaries [Member]
Cash and Cash Equivalents, at Carrying Value	379	309	330	319
Other current assets	6,806	6,063
Property, Plant and Equipment, Net	60,550	58,437
Advances to and investments in unconsolidated affiliates	3,599	3,816
Other Assets, Noncurrent	8,571	9,184
Assets	79,905	77,809
Liabilities, Current	14,675	12,150
Liabilities, Noncurrent	4,794	7,609
Noncontrolling interest	6,334	5,882
Partners' Capital	54,102	52,168
Liabilities and Equity	79,905	77,809
Adjustments And Eliminations [Member]
Cash and Cash Equivalents, at Carrying Value	0	0	$ 0	$ 0
Other current assets	(892)	0
Property, Plant and Equipment, Net	0	0
Advances to and investments in unconsolidated affiliates	(62,049)	(60,026)
Other Assets, Noncurrent	0	0
Assets	(62,941)	(60,026)
Liabilities, Current	(892)	0
Liabilities, Noncurrent	0	0
Noncontrolling interest	0	0
Partners' Capital	(62,049)	(60,026)
Liabilities and Equity	$ (62,941)	$ (60,026)

Guarantor Financial Information Statements of Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues	$ 9,641	$ 6,973	$ 27,331	$ 20,444
Costs and Expenses	8,136	6,194	23,910	18,246
OPERATING INCOME	1,505	779	3,421	2,198
Interest Expense	(387)	(352)	(1,091)	(1,020)
Equity in earnings of unconsolidated affiliates	113	127	147	139
Gains (losses) on interest rate derivatives	45	(8)	117	(28)
Deconsolidation, Gain (Loss), Amount	0	0	(86)	0
Gain on Sunoco LP common unit repurchase	0	0	172	0
Other Nonoperating Income (Expense)	21	57	127	137
Income (Loss) Attributable to Parent, before Tax	1,297	603	2,807	1,426
Income tax expense (benefit)	(61)	(112)	(32)	22
Net income	1,358	715	2,839	1,404
Less: Net income attributable to noncontrolling interest	223	110	557	266
Net income attributable to partners	1,135	605	2,282	1,138
Other comprehensive income, net of tax	4	7	7	6
Comprehensive income	1,362	722	2,846	1,410
Less: Comprehensive income attributable to noncontrolling interest	223	110	557	266
Comprehensive income attributable to partners	1,139	612	2,289	1,144
Parent Guarantor [Member]
Revenues	0	0	0	0
Costs and Expenses	0	0	0	0
OPERATING INCOME	0	0	0	0
Interest Expense	(303)	0	(870)	0
Equity in earnings of unconsolidated affiliates	1,394	647	3,036	1,657
Gains (losses) on interest rate derivatives		0	117	0
Deconsolidation, Gain (Loss), Amount	45		0
Gain on Sunoco LP common unit repurchase			0
Other Nonoperating Income (Expense)	0	0	0	0
Income (Loss) Attributable to Parent, before Tax	1,136	647	2,283	1,657
Income tax expense (benefit)	0	0	0	0
Net income	1,136	647	2,283	1,657
Less: Net income attributable to noncontrolling interest	0	0	0	0
Net income attributable to partners	1,136	647	2,283	1,657
Other comprehensive income, net of tax	0	0	0	0
Comprehensive income	1,136	647	2,283	1,657
Less: Comprehensive income attributable to noncontrolling interest	0	0	0	0
Comprehensive income attributable to partners	1,136	647	2,283	1,657
Subsidiary Issuer [Member]
Revenues	0	0	0	0
Costs and Expenses	0	0	0	1
OPERATING INCOME	0	0	0	(1)
Interest Expense	(55)	(32)	(137)	(113)
Equity in earnings of unconsolidated affiliates	501	236	827	1,001
Gains (losses) on interest rate derivatives		0	0	0
Deconsolidation, Gain (Loss), Amount	0		0
Gain on Sunoco LP common unit repurchase			0
Other Nonoperating Income (Expense)	0	1	0	4
Income (Loss) Attributable to Parent, before Tax	446	205	690	891
Income tax expense (benefit)	0	0	0	0
Net income	446	205	690	891
Less: Net income attributable to noncontrolling interest	0	0	0	0
Net income attributable to partners	446	205	690	891
Other comprehensive income, net of tax	0	0	0	0
Comprehensive income	446	205	690	891
Less: Comprehensive income attributable to noncontrolling interest	0	0	0	0
Comprehensive income attributable to partners	446	205	690	891
Non-Guarantor Subsidiaries [Member]
Revenues	9,641	6,973	27,331	20,444
Costs and Expenses	8,136	6,194	23,910	18,245
OPERATING INCOME	1,505	779	3,421	2,199
Interest Expense	(29)	(320)	(84)	(907)
Equity in earnings of unconsolidated affiliates	113	127	147	139
Gains (losses) on interest rate derivatives		(8)	0	(28)
Deconsolidation, Gain (Loss), Amount	0		(86)
Gain on Sunoco LP common unit repurchase			172
Other Nonoperating Income (Expense)	21	56	127	134
Income (Loss) Attributable to Parent, before Tax	1,610	634	3,697	1,537
Income tax expense (benefit)	(61)	(112)	(32)	22
Net income	1,671	746	3,729	1,515
Less: Net income attributable to noncontrolling interest	223	110	557	266
Net income attributable to partners	1,448	636	3,172	1,249
Other comprehensive income, net of tax	4	7	7	6
Comprehensive income	1,675	753	3,736	1,521
Less: Comprehensive income attributable to noncontrolling interest	223	110	557	266
Comprehensive income attributable to partners	1,452	643	3,179	1,255
Adjustments And Eliminations [Member]
Revenues	0	0	0	0
Costs and Expenses	0	0	0	0
OPERATING INCOME	0	0	0	0
Interest Expense	0	0	0	0
Equity in earnings of unconsolidated affiliates	(1,895)	(883)	(3,863)	(2,658)
Gains (losses) on interest rate derivatives		0	0	0
Deconsolidation, Gain (Loss), Amount	0		0
Gain on Sunoco LP common unit repurchase			0
Other Nonoperating Income (Expense)	0	0	0	(1)
Income (Loss) Attributable to Parent, before Tax	(1,895)	(883)	(3,863)	(2,659)
Income tax expense (benefit)	0	0	0	0
Net income	(1,895)	(883)	(3,863)	(2,659)
Less: Net income attributable to noncontrolling interest	0	0	0	0
Net income attributable to partners	(1,895)	(883)	(3,863)	(2,659)
Other comprehensive income, net of tax	0	0	0	0
Comprehensive income	(1,895)	(883)	(3,863)	(2,659)
Less: Comprehensive income attributable to noncontrolling interest	0	0	0	0
Comprehensive income attributable to partners	$ (1,895)	$ (883)	$ (3,863)	$ (2,659)

Guarantor Financial Information Cash Flows (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Net Cash Provided by (Used in) Operating Activities	$ 5,100	$ 3,337
Net Cash Provided by (Used in) Investing Activities	(3,067)	(4,687)
Net Cash Provided by (Used in) Financing Activities	(1,960)	1,369
Cash and Cash Equivalents, Period Increase (Decrease)	73	19
Cash and Cash Equivalents, at Carrying Value	379	379	$ 306	$ 360
Parent Guarantor [Member]
Net Cash Provided by (Used in) Operating Activities	2,753	1,657
Net Cash Provided by (Used in) Investing Activities	(834)	(1,348)
Net Cash Provided by (Used in) Financing Activities	(1,919)	(309)
Cash and Cash Equivalents, Period Increase (Decrease)	0	0
Cash and Cash Equivalents, at Carrying Value	0	0	0	0
Subsidiary Issuer [Member]
Net Cash Provided by (Used in) Operating Activities	582	802
Net Cash Provided by (Used in) Investing Activities	(579)	(1,127)
Net Cash Provided by (Used in) Financing Activities	0	333
Cash and Cash Equivalents, Period Increase (Decrease)	3	8
Cash and Cash Equivalents, at Carrying Value	0	49	(3)	41
Non-Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities	3,843	3,538
Net Cash Provided by (Used in) Investing Activities	(3,732)	(4,872)
Net Cash Provided by (Used in) Financing Activities	(41)	1,345
Cash and Cash Equivalents, Period Increase (Decrease)	70	11
Cash and Cash Equivalents, at Carrying Value	379	330	309	319
Adjustments And Eliminations [Member]
Net Cash Provided by (Used in) Operating Activities	(2,078)	(2,660)
Net Cash Provided by (Used in) Investing Activities	2,078	2,660
Net Cash Provided by (Used in) Financing Activities	0	0
Cash and Cash Equivalents, Period Increase (Decrease)	0	0
Cash and Cash Equivalents, at Carrying Value	$ 0	$ 0	$ 0	$ 0

Fair Value Measurements Fair Value Heigharchy (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Price Risk Derivative Assets, at Fair Value	$ 599	$ 320
Other Assets, Fair Value Disclosure	28	21
Assets, Fair Value Disclosure	627	341
Interest rate derivatives, Liabilities	(97)	(219)
Price Risk Derivative Liabilities, at Fair Value	(870)	(338)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(967)	(557)
Level 1
Price Risk Derivative Assets, at Fair Value	550	276
Other Assets, Fair Value Disclosure	18	14
Assets, Fair Value Disclosure	568	290
Interest rate derivatives, Liabilities	0	0
Price Risk Derivative Liabilities, at Fair Value	(832)	(300)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(832)	(300)
Level 2
Price Risk Derivative Assets, at Fair Value	49	44
Other Assets, Fair Value Disclosure	10	7
Assets, Fair Value Disclosure	59	51
Interest rate derivatives, Liabilities	(97)	(219)
Price Risk Derivative Liabilities, at Fair Value	(38)	(38)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(135)	(257)
Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	48	11
Price Risk Derivative Liabilities, at Fair Value	(89)	(24)
Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC/NYMEX [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	48	11
Price Risk Derivative Liabilities, at Fair Value	(89)	(24)
Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC/NYMEX [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] \| Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	1	13
Price Risk Derivative Liabilities, at Fair Value	(1)	(15)
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	(1)
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	1	13
Price Risk Derivative Liabilities, at Fair Value	(1)	(14)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	25	70
Price Risk Derivative Liabilities, at Fair Value	(26)	(57)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	25	70
Price Risk Derivative Liabilities, at Fair Value	(26)	(57)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [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] \| Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	12	8
Price Risk Derivative Liabilities, at Fair Value	(7)	(2)
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Swaps [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Swaps [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	12	8
Price Risk Derivative Liabilities, at Fair Value	(7)	(2)
Commodity Derivatives - Power [Member] \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	36	23
Price Risk Derivative Liabilities, at Fair Value	(30)	(22)
Commodity Derivatives - Power [Member] \| Forward Swaps [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] \| Level 2
Price Risk Derivative Assets, at Fair Value	36	23
Price Risk Derivative Liabilities, at Fair Value	(30)	(22)
Commodity Derivatives - Power [Member] \| Future [Member]
Price Risk Derivative Liabilities, at Fair Value	(1)
Commodity Derivatives - Power [Member] \| Future [Member] \| Level 1
Price Risk Derivative Liabilities, at Fair Value	(1)
Commodity Derivatives - Power [Member] \| Future [Member] \| Level 2
Price Risk Derivative Liabilities, at Fair Value	0
Commodity Derivatives - Power [Member] \| Put Option [Member]
Price Risk Derivative Assets, at Fair Value	1
Commodity Derivatives - Power [Member] \| Put Option [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	1
Commodity Derivatives - Power [Member] \| Put Option [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	0
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	476	191
Price Risk Derivative Liabilities, at Fair Value	(521)	(186)
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	476	191
Price Risk Derivative Liabilities, at Fair Value	(521)	(186)
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Refined Products [Member] \| Future [Member]
Price Risk Derivative Liabilities, at Fair Value	(5)	(25)
Commodity Derivatives - Refined Products [Member] \| Future [Member] \| Level 1
Price Risk Derivative Liabilities, at Fair Value	(5)	(25)
Commodity Derivatives - Refined Products [Member] \| Future [Member] \| Level 2
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Crude [Member] \| Future [Member]
Price Risk Derivative Assets, at Fair Value		2
Price Risk Derivative Liabilities, at Fair Value	(190)	(1)
Commodity Derivatives - Crude [Member] \| Future [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value		2
Price Risk Derivative Liabilities, at Fair Value	(190)	(1)
Commodity Derivatives - Crude [Member] \| Future [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value	$ 0	0
Commodity Derivatives - Crude [Member] \| Forwards Swaps [Member]
Price Risk Derivative Assets, at Fair Value		2
Price Risk Derivative Liabilities, at Fair Value		(6)
Commodity Derivatives - Crude [Member] \| Forwards Swaps [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value		2
Price Risk Derivative Liabilities, at Fair Value		(6)
Commodity Derivatives - Crude [Member] \| Forwards Swaps [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		$ 0