0001276187-19-000051 | 10-Q | XBRL Viewer

DEI Document - shares	9 Months Ended
DEI Document - shares	Sep. 30, 2019	Nov. 01, 2019
Document and Entity Information [Abstract]
Entity Registrant Name	ENERGY TRANSFER LP
Document Transition Report	false
Document Quarterly Report	true
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Shell Company	false
Entity Central Index Key	0001276187
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2019
Entity File Number	1-32740
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		2,626,996,383
Entity Emerging Growth Company	false
Entity Small Business	false
Title of 12(b) Security	Common Units
Trading Symbol	ET
Security Exchange Name	NYSE
Entity Tax Identification Number	30-0108820
Entity Incorporation, State or Country Code	DE
Entity Address, Address Line One	8111 Westchester Drive
Entity Address, Address Line Two	Suite 600
Entity Address, City or Town	Dallas
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75225
City Area Code	214
Local Phone Number	981-0700

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
ASSETS
Cash and cash equivalents	$ 211	$ 419
Accounts receivable, net	4,368	4,009
Accounts receivable from related companies	166	111
Inventories	1,814	1,677
Income taxes receivable	109	73
Derivative assets	56	111
Other current assets	342	350
Total current assets	7,066	6,750
Property, plant and equipment	84,033	79,776
Accumulated depreciation and depletion	(14,864)	(12,813)
Property, Plant and Equipment, Net	69,169	66,963
Advances to and investments in unconsolidated affiliates	2,992	2,642
Lease, Right of Use Asset, Net	889	0
Other non-current assets, net	1,089	1,006
Intangible assets, net	5,781	6,000
Goodwill	4,870	4,885
Total assets	91,856	88,246
LIABILITIES AND EQUITY
Accounts payable	3,519	3,493
Accounts payable to related companies	32	59
Derivative liabilities	181	185
Operating lease current liabilities	57	0
Accrued and other current liabilities	3,234	2,918
Current maturities of long-term debt	14	2,655
Total current liabilities	7,037	9,310
Long-term debt, less current maturities	46,840	43,373
Non-current derivative liabilities	360	104
Non-current operating lease liabilities	807	0
Deferred income taxes	3,133	2,926
Other non-current liabilities	1,138	1,184
Commitments and contingencies
Redeemable noncontrolling interests	499	499
Limited Partners:
Common Unitholders	20,962	20,606
General Partner	(4)	(5)
Accumulated other comprehensive loss	(40)	(42)
Total partners’ capital	20,918	20,559
Noncontrolling interests	11,124	10,291
Total equity	32,042	30,850
Total liabilities and equity	$ 91,856	$ 88,246

Consolidated Statements Of Operations - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
REVENUES:
Total revenues	$ 13,495	$ 14,514	$ 40,493	$ 40,514
COSTS AND EXPENSES:
Cost of products sold	9,890	11,093	29,607	31,681
Operating expenses	806	784	2,406	2,280
Depreciation, depletion and amortization	784	750	2,343	2,109
Selling, general and administrative	173	184	499	515
Impairment losses	12	0	62	0
Total costs and expenses	11,665	12,811	34,917	36,585
OPERATING INCOME	1,830	1,703	5,576	3,929
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(579)	(535)	(1,747)	(1,511)
Equity in earnings of unconsolidated affiliates	82	87	224	258
Losses on extinguishments of debt	0	0	(18)	(106)
Gains (losses) on interest rate derivatives	(175)	45	(371)	117
Other, net	57	41	99	97
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	1,215	1,341	3,763	2,784
Income tax expense (benefit) from continuing operations	54	(52)	214	6
INCOME FROM CONTINUING OPERATIONS	1,161	1,393	3,549	2,778
Loss from discontinued operations, net of income taxes	0	(2)	0	(265)
NET INCOME	1,161	1,391	3,549	2,513
Less: Net income attributable to noncontrolling interests	317	1,008	931	1,412
Less: Net income attributable to redeemable noncontrolling interests	12	12	38	24
NET INCOME ATTRIBUTABLE TO PARTNERS	832	371	2,580	1,077
General Partner’s interest in net income	1	1	3	3
Series A Convertible Preferred Unitholders' interest in income	0	0	0	33
Limited Partners’ interest in net income	$ 831	$ 370	$ 2,577	$ 1,041
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$ 0.32	$ 0.32	$ 0.98	$ 0.94
Diluted	0.32	0.32	0.98	0.94
NET INCOME PER LIMITED PARTNER UNIT:
Basic	0.32	0.32	0.98	0.93
Diluted	$ 0.32	$ 0.32	$ 0.98	$ 0.93
Refined product sales
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	$ 4,311	$ 4,777	$ 12,514	$ 12,980
Crude sales
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	3,971	3,844	11,842	11,344
NGL sales
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	1,723	2,870	6,121	7,461
Gathering, transportation and other fees
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	2,466	1,781	6,768	4,878
Natural gas sales
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	822	1,026	2,549	3,112
Other
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	$ 202	$ 216	$ 699	$ 739

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Statement of Comprehensive Income [Abstract]
Net income	$ 1,161	$ 1,391	$ 3,549	$ 2,513
Other comprehensive income, net of tax:
Change in value of available-for-sale securities	0	2	8	0
Actuarial gain (loss) related to pension and other postretirement benefit plans	(3)	0	7	(2)
Change in other comprehensive income from unconsolidated affiliates	(4)	2	(13)	9
Other comprehensive income (loss), net of tax	(7)	4	2	7
Comprehensive income	1,154	1,395	3,551	2,520
Less: Comprehensive income attributable to noncontrolling interests	317	1,012	931	1,419
Other Comprehensive Income, Portion Attributable to Redeemable Noncontrolling Interest	12	12	38	24
Comprehensive income attributable to partners	$ 825	$ 371	$ 2,582	$ 1,077

Consolidated Statement Of Equity - USD ($) $ in Millions	Total	Series A Convertible Preferred Units [Member]	Limited Partner [Member]	General Partner	Noncontrolling Interest	AOCI Attributable to Parent [Member]
Cumulative effect adjustment due to change in accounting principle	$ (54)	$ 0	$ 0	$ 0	$ (54)
Balance, Beginning of Period at Dec. 31, 2017	29,980	450	(1,643)	(3)	31,176
Distributions to partners	(266)	0	(265)	(1)	0
Distributions to noncontrolling interests	(893)	0	0	0	(893)
Distributions reinvested	0	58	(58)	0	0
Subsidiary units repurchased	(24)	(6)	(98)	0	80
Subsidiary units issued	20	0	1	0	19
Capital contributions from noncontrolling interests	229	0	0	0	229
Other comprehensive income, net of tax	1	0	0	0	1
Other, net	(1)	(4)	26	0	(23)
Net income	489	21	341	1	126
Balance, End of Period at Mar. 31, 2018	29,481	519	(1,696)	(3)	30,661
Balance, Beginning of Period at Dec. 31, 2017	29,980	450	(1,643)	(3)	31,176
Distributions reinvested	0
Other comprehensive income, net of tax	7
Stock Issued During Period, Value, Conversion of Units			589
Net income	2,513
Balance, End of Period at Sep. 30, 2018	31,033	0	(1,099)	(4)	32,136
Balance, Beginning of Period at Mar. 31, 2018	29,481	519	(1,696)	(3)	30,661
Distributions to partners	(266)	0	(265)	(1)	0
Distributions to noncontrolling interests	(900)	0	0	0	(900)
Distributions reinvested	0	57	(57)	0	0
Subsidiary units repurchased	0	(1)	(21)	0	22
Subsidiary units issued	469	0	0	0	469
Capital contributions from noncontrolling interests	89	0	0	0	89
Other comprehensive income, net of tax	2	0	0	0	2
Noncontrolling Interest, Increase from Business Combination	832	0	0	0	832
Stock Issued During Period, Value, Conversion of Units	0	(589)	589	0	0
Other, net	43	2	2	(1)	40
Net income	633	12	342	1	278
Balance, End of Period at Jun. 30, 2018	30,383	0	(1,106)	(4)	31,493
Distributions to partners	(354)	0	(353)	(1)	0
Distributions to noncontrolling interests	(949)	0	0	0	(949)
Subsidiary units issued	449	0	0	0	449
Capital contributions from noncontrolling interests	120	0	0	0	120
Other comprehensive income, net of tax	4	0	0	0	4
Other, net	13	0	2	0	11
Net income	1,391
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	1,367	0	358	1	1,008
Balance, End of Period at Sep. 30, 2018	31,033	$ 0	(1,099)	(4)	32,136
Balance, Beginning of Period at Dec. 31, 2018	30,850		20,606	(5)	10,291	$ (42)
Distributions to partners	(800)		(799)	(1)	0	0
Distributions to noncontrolling interests	(425)		0	0	(425)	0
Capital contributions from noncontrolling interests	140		0	0	140	0
Sale of noncontrolling interest in subsidiary	93		0	0	93	0
Other comprehensive income, net of tax	8		0	0	0	8
Other, net	29		17	0	12	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	1,167		869	1	297	0
Balance, End of Period at Mar. 31, 2019	31,062		20,693	(5)	10,408	(34)
Balance, Beginning of Period at Dec. 31, 2018	30,850		20,606	(5)	10,291	(42)
Other comprehensive income, net of tax	2
Stock Issued During Period, Value, Conversion of Units			0
Net income	3,549
Balance, End of Period at Sep. 30, 2019	32,042		20,962	(4)	11,124	(40)
Balance, Beginning of Period at Mar. 31, 2019	31,062		20,693	(5)	10,408	(34)
Distributions to partners	(800)		(799)	(1)		0
Distributions to noncontrolling interests	(388)		0	0	(388)	0
Partners' Capital Account, Sale of Units	51		51	0	0	0
Subsidiary units issued	780		0	0	780	0
Capital contributions from noncontrolling interests	66		0	0	66	0
Other comprehensive income, net of tax	1		0	0	0	1
Other, net	50		50	0	0	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	1,195		877	1	317	0
Balance, End of Period at Jun. 30, 2019	32,017		20,872	(5)	11,183	(33)
Distributions to partners	(800)		(800)	0	0	0
Distributions to noncontrolling interests	(457)		0	0	(457)	0
Partners' Capital Account, Sale of Units	49		49	0	0	0
Capital contributions from noncontrolling interests	72		0	0	72	0
Other comprehensive income, net of tax	(7)		0	0	0	(7)
Other, net	19		10	0	9	0
Net income	1,161
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	1,149		831	1	317	0
Balance, End of Period at Sep. 30, 2019	$ 32,042		$ 20,962	$ (4)	$ 11,124	$ (40)

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
OPERATING ACTIVITIES
Net income	$ 3,549	$ 2,513
Reconciliation of net income to net cash provided by operating activities:
Loss from discontinued operations	0	265
Depreciation, depletion and amortization	2,343	2,109
Deferred income taxes	191	1
Non-cash compensation expense	85	82
Impairment losses	62	0
Losses on extinguishments of debt	(18)	(106)
Equity in earnings of unconsolidated affiliates	(224)	(258)
Distributions from unconsolidated affiliates	254	220
Inventory valuation adjustments	(71)	(50)
Distributions on unvested awards	(27)	(36)
Other non-cash	33	(80)
Net change in operating assets and liabilities, net of effects of acquisitions	(247)	423
Net Cash Provided by (Used in) Operating Activities, Continuing Operations	5,966	5,295
INVESTING ACTIVITIES
Proceeds from Divestiture of Businesses and Interests in Affiliates	93	0
Cash proceeds from USAC acquisition, net of cash received	0	461
Cash paid for all other acquisitions, net of cash received	(7)	(233)
Capital expenditures, excluding allowance for equity funds used during construction	(4,181)	(5,175)
Contributions in aid of construction costs	63	95
Contributions to unconsolidated affiliate	481	13
Distributions from unconsolidated affiliates in excess of cumulative earnings	40	62
Proceeds from the sale of other assets	55	40
Other	5	0
Net Cash Provided by (Used in) Investing Activities, Continuing Operations	(4,423)	(4,763)
FINANCING ACTIVITIES
Proceeds from borrowings	18,125	22,126
Repayments of debt	(17,247)	(23,323)
Subsidiary repurchases of common units	0	(24)
Subsidiary units issued for cash	780	1,390
Distributions to partners	(2,300)	(886)
Debt issuance costs	(114)	(188)
Distributions to noncontrolling interests	(1,270)	(2,742)
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	0	12
Capital contributions from noncontrolling interest	278	438
Other, net	(3)	13
Net cash used in financing activities	(1,751)	(3,208)
DISCONTINUED OPERATIONS
Operating activities	0	(480)
Investing activities	0	3,207
Changes in cash included in current assets held for sale	0	11
Net increase in cash and cash equivalents of discontinued operations	0	2,738
Increase (decrease) in cash and cash equivalents	(208)	62
Cash and cash equivalents, beginning of period	419	336
Cash and cash equivalents, end of period	$ 211	$ 398

Operations And Organization

9 Months Ended

Sep. 30, 2019

Operations And Organization [Abstract]

Operations And Organization

ORGANIZATION AND BASIS OF PRESENTATION

Organization

The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ET”). References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.

In October 2018, we completed the merger of ETO with a wholly-owned subsidiary of ET in a unit-for-unit exchange (the “Energy Transfer Merger”). In connection with the transaction, ETO unitholders (other than ET and its subsidiaries) received 1.28 common units of ET for each common unit of ETO they owned. Following the closing of the Energy Transfer Merger, Energy Transfer Partners, L.P. was renamed Energy Transfer Operating, L.P. In addition, Energy Transfer Equity, L.P. was renamed Energy Transfer LP, and its common units began trading on the New York Stock Exchange under the “ET” ticker symbol on October 19, 2018.

Immediately prior to the closing of the Energy Transfer Merger, the following also occurred:


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


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


•	ET contributed its 2,263,158 Sunoco LP common units to ETO in exchange for 2,874,275 ETO common units and 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 ETO in exchange for 42,812,389 ETO common units;


•	ET contributed its 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 ETO in exchange for 16,134,903 ETO common units; and


•	ET contributed its 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 ETO in exchange for 37,557,815 ETO common units.

Subsequent to the Energy Transfer Merger, substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in Sunoco LP and USAC. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ET’s subsidiaries.

Our financial statements reflect the following reportable segments:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services;

•investment in Sunoco LP;

•investment in USAC; and

•corporate and other, including the following:


•	activities of the Parent Company; and


•	certain operations and investments that are not separately reflected as reportable 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 included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on February 22, 2019. 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 consolidated financial statements of ET presented herein include the results of operations of:


•	the Parent Company;


•	our controlled subsidiary, Energy Transfer Operating, L.P. (“ETO”); and


•	ETP GP and Energy Transfer Partners, L.L.C. (“ETP LLC”), the general partner of ETP GP.

Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

Certain prior period amounts have also been reclassified to conform to the current period presentation. These reclassifications had no impact on net income or total equity.

Use of Estimates

The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.

Change in Accounting Policy

Adoption of Lease Accounting Standard

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which has amended the FASB Accounting Standards Codification (“ASC”) and introduced Topic 842, Leases. On January 1, 2019, the Partnership has adopted ASC Topic 842 (“Topic 842”), which is effective for interim and annual reporting periods beginning on or after December 15, 2018. Topic 842 requires entities to recognize lease assets and liabilities on the balance sheet for all leases with a term of more than one year, including operating leases, which historically were not recorded on the balance sheet in accordance with the prior standard.

To adopt Topic 842, the Partnership recognized a cumulative catch-up adjustment to the opening balance sheet as of January 1, 2019 related to certain leases that existed as of that date. As permitted, we have not retrospectively modified our consolidated financial statements for comparative purposes. The adoption of the standard had a material impact on our consolidated balance sheet, but did not have an impact on our consolidated statements of operations, comprehensive income or cash flows. As a result of adoption, we have recorded additional net right-of-use (“ROU”) lease assets and lease liabilities of approximately $888 million and $888 million, respectively, as of January 1, 2019. In addition, we have updated our business processes, systems, and internal controls to support the on-going reporting requirements under the new standard.

To adopt Topic 842, the Partnership elected the package of practical expedients permitted under the transition guidance within the standard. The expedient package allowed us not to reassess whether existing contracts contained a lease, the lease classification of existing leases and initial direct cost for existing leases. In addition to the package of practical expedients, the Partnership has elected not to capitalize amounts pertaining to leases with terms less than twelve months, to use the portfolio approach to determine discount rates, not to separate non-lease components from lease components and not to apply the use of hindsight to the active lease population.

Cumulative-effect adjustments made to the opening balance sheet at January 1, 2019 were as follows:



	Balance at December 31, 2018, as previously reported		Adjustments due to Topic 842 (Leases)			Balance at January 1, 2019
Assets:
Property, plant and equipment, net	$	66,963	$	(1	)	$	66,962
Lease right-of-use assets, net	—		889			889
Liabilities:
Operating lease current liabilities	$	—	$	71		$	71
Accrued and other current liabilities	2,918		(1		)	2,917
Current maturities of long-term debt	2,655		1			2,656
Long-term debt, less current maturities	43,373		6			43,379
Non-current operating lease liabilities	—		823			823
Other non-current liabilities	1,184		(12		)	1,172

Additional disclosures related to lease accounting are included in Note 13.

Goodwill

The Partnership’s interstate transportation and storage segment owns Southwest Gas which owns and operates natural gas storage assets. Due to a decrease in the demand for storage on these assets, the Partnership performed an interim impairment test on the assets of Southwest Gas during the three months ended September 30, 2019. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of $12 million related to Southwest Gas, primarily due to decreases in projected future revenues and cash flows. No other impairments of the Partnership’s other assets were identified. The Partnership estimated the fair value of Southwest Gas by using the income approach. The income approach is based on the present value of future cash flows, which are derived from our long-term financial forecasts, and requires significant assumptions including, among others, a discount rate and a terminal value.

Acquisitions

9 Months Ended

Sep. 30, 2019

ACQUISITIONS AND DIVESTITURE [Abstract]

Acquisitions

ACQUISITIONS AND OTHER INVESTING TRANSACTIONS

Sunoco LP Retail Store and Real Estate Sales

On January 23, 2018, Sunoco LP completed the disposition of assets pursuant to the purchase agreement with 7-Eleven, Inc. (the “7-Eleven Transaction”). As a result of the 7-Eleven Transaction, previously eliminated wholesale motor fuel sales to Sunoco LP’s retail locations are reported as wholesale motor fuel sales to third parties. Also, the related accounts receivable from such sales are no longer eliminated from the Partnership’s consolidated balance sheets and are reported as accounts receivable.

In connection with the 7-Eleven Transaction, Sunoco LP entered into a Distributor Motor Fuel Agreement dated as of January 23, 2018, as amended (“Supply Agreement”), with 7-Eleven and SEI Fuel (collectively, “Distributor”). The Supply Agreement consists of a 15-year take-or-pay fuel supply arrangement. For the period from January 1, 2018 through January 22, 2018, Sunoco LP recorded sales to the sites that were subsequently sold to 7-Eleven of $199 million, which were eliminated in consolidation. Sunoco LP received payments on trade receivables from 7-Eleven of $1.0 billion and $2.9 billion for the three and nine months ended September 30, 2019, respectively, and $1.0 billion and $2.6 billion for the three and nine months ended September 30, 2018, respectively, subsequent to the closing of the sale.

The Partnership has concluded that it meets the accounting requirements for reporting the financial position, results of operations and cash flows of Sunoco LP’s retail divestment as discontinued operations.

There were no results of operations associated with discontinued operations for the three and nine months ended September 30, 2019. The results of operations associated with discontinued operations for the three and nine months ended ended September 30, 2018 were as follows:



	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
REVENUES	$	—		$	349

COSTS AND EXPENSES
Cost of products sold	—			305
Operating expenses	—			61
Depreciation, depletion and amortization	—			—
Impairment losses	—			—
Selling, general and administrative	—			7
Total costs and expenses	—			373
OPERATING LOSS	—			(24		)
Interest expense, net	—			(2		)
Loss on extinguishment of debt and other	—			(20		)
Other, net	—			(61		)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE	—			(107		)
Income tax expense	2			158
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	(2	)	$	(265	)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ET	$	—		$	(10	)

Cash And Cash Equivalents

9 Months Ended

Sep. 30, 2019

Supplemental Cash Flow Information [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. The Partnership’s balance sheets did not include any material amounts of restricted cash as of September 30, 2019 or December 31, 2018.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

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



	Nine Months Ended September 30,
	2019			2018
Accounts receivable	$	(353	)	$	155
Accounts receivable from related companies	(36		)	64
Inventories	(66		)	78
Other current assets	14			(19		)
Other non-current assets, net	(127		)	(25		)
Accounts payable	25			(234		)
Accounts payable to related companies	(37		)	(110		)
Accrued and other current liabilities	129			422
Other non-current liabilities	(103		)	24
Derivative assets and liabilities, net	307			68
Net change in operating assets and liabilities, net of effects of acquisitions	$	(247	)	$	423

Non-cash activities are as follows:



	Nine Months Ended September 30,
	2019		2018
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	$	1,202	$	1,059
Losses from subsidiary common unit transactions	—		(125		)
Lease assets obtained in exchange for new lease liabilities	73		—
NON-CASH FINANCING ACTIVITIES:
Distribution reinvestment	$	100	$	—
Conversion of Series A Convertible Preferred Units to common units	—		589

Inventories (Notes)

9 Months Ended

Sep. 30, 2019

Inventory, Net [Abstract]

Inventories

INVENTORIES

Inventories consisted of the following:



	September 30, 2019		December 31, 2018
Natural gas, NGLs and refined products	$	900	$	833
Crude oil	510		506
Spare parts and other	404		338
Total inventories	$	1,814	$	1,677

We utilize commodity derivatives to manage price volatility associated with its natural gas inventories. 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, 2019

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, 2019 were $50.79 billion and $46.85 billion, respectively. As of December 31, 2018, the aggregate fair value and carrying amount of

our consolidated debt obligations were $45.06 billion and $46.03 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ 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, 2019, 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, 2019 and December 31, 2018 based on inputs used to derive their fair values:



				Fair Value Measurements at September 30, 2019
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	27		$	27		$	—
Swing Swaps IFERC	5			—			5
Fixed Swaps/Futures	44			44			—
Forward Physical Contracts	5			—			5
Power:
Forwards	21			—			21
Futures	4			4			—
NGLs – Forwards/Swaps	529			529			—
Refined Products – Futures	1			1			—
Crude – Forwards/Swaps	43			43			—
Total commodity derivatives	679			648			31
Other non-current assets	29			19			10
Total assets	$	708		$	667		$	41
Liabilities:
Interest rate derivatives	$	(528	)	$	—		$	(528	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(54		)	(54		)	—
Swing Swaps IFERC	(9		)	—			(9		)
Fixed Swaps/Futures	(29		)	(29		)	—
Forward Physical Contracts	(2		)	—			(2		)
Power:
Forwards	(14		)	—			(14		)
Futures	(5		)	(5		)	—
Options – Calls	(1		)	(1		)	—
NGLs – Forwards/Swaps	(479		)	(479		)	—
Refined Products – Futures	(3		)	(3		)	—
Crude – Forwards/Swaps	(1		)	(1		)	—
Total commodity derivatives	(597		)	(572		)	(25		)
Total liabilities	$	(1,125	)	$	(572	)	$	(553	)



				Fair Value Measurements at December 31, 2018
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	42		$	42		$	—
Swing Swaps IFERC	52			8			44
Fixed Swaps/Futures	97			97			—
Forward Physical Contracts	20			—			20
Power:
Forwards	48			—			48
Futures	1			1			—
Options – Calls	1			1			—
NGLs – Forwards/Swaps	291			291			—
Refined Products – Futures	7			7			—
Crude – Forwards/Swaps	1			1			—
Total commodity derivatives	560			448			112
Other non-current assets	26			17			9
Total assets	$	586		$	465		$	121
Liabilities:
Interest rate derivatives	$	(163	)	$	—		$	(163	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(91		)	(91		)	—
Swing Swaps IFERC	(40		)	—			(40		)
Fixed Swaps/Futures	(88		)	(88		)	—
Forward Physical Contracts	(21		)	—			(21		)
Power:
Forwards	(42		)	—			(42		)
Futures	(1		)	(1		)	—
NGLs – Forwards/Swaps	(224		)	(224		)	—
Refined Products – Futures	(15		)	(15		)	—
Crude – Forwards/Swaps	(61		)	(61		)	—
Total commodity derivatives	(583		)	(480		)	(103		)
Total liabilities	$	(746	)	$	(480	)	$	(266	)

- Definition

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

+ References + Details

Net Income per Limited Partner Unit

9 Months Ended

Sep. 30, 2019

Earnings Per Share [Abstract]

Net Income Per Limited Partner Unit

NET INCOME PER LIMITED PARTNER UNIT

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Income from continuing operations	$	1,161	$	1,393	$	3,549	$	2,778
Less: Income from continuing operations attributable to noncontrolling interests	317		1,010		931		1,667
Less: Net income attributable to redeemable noncontrolling interests	12		12		38		24
Income from continuing operations, net of noncontrolling interests	832		371		2,580		1,087
Less: Series A Convertible Preferred Unitholders’ interest in income	—		—		—		33
Less: General Partner’s interest in income	1		1		3		3
Income from continuing operations available to Limited Partners	$	831	$	370	$	2,577	$	1,051
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	2,624.9		1,158.2		2,621.9		1,117.7
Basic income from continuing operations per Limited Partner unit	$	0.32	$	0.32	$	0.98	$	0.94
Basic income (loss) from discontinued operations per Limited Partner unit	$	—	$	—	$	—	$	(0.01	)
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	831	$	370	$	2,577	$	1,051
Dilutive effect of distributions to Series A Convertible Preferred Unitholders	—		—		—		33
Diluted income from continuing operations available to Limited Partners	$	831	$	370	$	2,577	$	1,084
Weighted average limited partner units	2,624.9		1,158.2		2,621.9		1,117.7
Dilutive effect of Series A Convertible Preferred Units	—		—		—		40.5
Dilutive effect of unvested unit awards	10.6		—		11.0		—
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	2,635.5		1,158.2		2,632.9		1,158.2
Diluted income from continuing operations per Limited Partner unit	$	0.32	$	0.32	$	0.98	$	0.94
Diluted income (loss) from discontinued operations per Limited Partner unit	$	—	$	—	$	—	$	(0.01	)

Debt Obligations	9 Months Ended
Debt Obligations	Sep. 30, 2019
Debt Obligations [Abstract]
Debt Obligations	DEBT OBLIGATIONS Parent Company Indebtedness ET Term Loan Facility On January 15, 2019, ET paid in full all outstanding borrowings under its senior secured term loan agreement and thereafter terminated the term loan agreement. In connection with the termination of the term loan agreement, the collateral securing certain series of the Partnership’s outstanding senior notes was released in accordance with the terms of the applicable indentures governing such senior notes. Subsidiary Indebtedness ET-ETO Senior Notes Exchange In February 2019, ETO commenced offers to exchange all of ET’s outstanding senior notes for senior notes issued by ETO (the “ET-ETO senior notes exchange”). Approximately 97% of ET’s outstanding senior notes were tendered and accepted, and substantially all the exchanges settled on March 25, 2019. Following the exchange, the ET senior notes that were not tendered and remain outstanding as of September 30, 2019 were as follows: •$52 million aggregate principal amount of 7.50% senior notes due 2020; •$5 million aggregate principal amount of 4.25% senior notes due 2023; •$23 million aggregate principal amount of 5.875% senior notes due 2024; and •$44 million aggregate principal amount of 5.50% senior notes due 2027. In connection with the exchange, ETO issued approximately $4.21 billion aggregate principal amount of the following senior notes: •$1.14 billion aggregate principal amount of 7.50% senior notes due 2020; •$995 million aggregate principal amount of 4.25% senior notes due 2023; •$1.13 billion aggregate principal amount of 5.875% senior notes due 2024; and •$956 million aggregate principal amount of 5.50% senior notes due 2027. The senior notes were registered under the Securities Act of 1933 (as amended). ETO 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 ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO 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. ETO Senior Notes Offering and Redemption In January 2019, ETO issued the following senior notes: •$750 million aggregate principal amount of 4.50% senior notes due 2024; •$1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and •$1.75 billion aggregate principal amount of 6.25% senior notes due 2049. The senior notes were registered under the Securities Act of 1933 (as amended). ETO 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 ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO 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 $3.96 billion net proceeds from the offering were used to make an intercompany loan to ET (which ET used to repay its term loan in full), for general partnership purposes and to redeem at maturity all of the following: •ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019; •ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and •Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019. Panhandle Senior Notes Redemption In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO. Bakken Senior Notes Offering In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, LLC, issued the following senior notes related to the Bakken pipeline: •$650 million aggregate principal amount of 3.625% senior notes due 2022; •$1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and •$850 million aggregate principal amount of 4.625% senior notes due 2029. The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated. Sunoco LP Senior Notes Offering In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00% senior notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings under its credit facility. In July 2019, Sunoco LP completed an exchange of these notes for registered notes with substantially identical terms. USAC Senior Notes Offering In March 2019, USAC issued $750 million aggregate principal amount of 6.875% senior unsecured notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of USAC’s existing borrowings under its credit facility and for general partnership purposes. Credit Facilities and Commercial Paper ETO Term Loan On October 17, 2019, ETO entered into a term loan credit agreement providing for a $2 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement will be unsecured and will be guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P. Borrowings under the term loan agreement will bear interest at a eurodollar rate or a base rate, at ETO’s option, plus an applicable margin. The applicable margin and applicable rate used in connection with the interest rates are based on the credit ratings assigned to the senior, unsecured, non-credit enhanced long-term debt of ETO. ETO Five-Year Credit Facility ETO’s revolving credit facility (the “ETO Five-Year Credit Facility”) allows for unsecured borrowings up to $5.00 billion and matures on December 1, 2023. The ETO 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, 2019, the ETO Five-Year Credit Facility had $2.61 billion of outstanding borrowings, $2.15 billion of which was commercial paper. The amount available for future borrowings was $2.32 billion after taking into account letters of credit of $77 million. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 2.77%. ETO 364-Day Facility ETO’s 364-day revolving credit facility (the “ETO 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November 29, 2019. As of September 30, 2019, the ETO 364-Day Facility had no outstanding borrowings. Sunoco LP Credit Facility Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”), which matures in July 2023. As of September 30, 2019, the Sunoco LP Credit Facility had $154 million of outstanding borrowings and $8 million in standby letters of credit. As of September 30, 2019, Sunoco LP had $1.34 billion of availability under the Sunoco LP Credit Facility. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 4.04%. USAC Credit Facility USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”), with a further potential increase of $400 million, which matures in April 2023. As of September 30, 2019, the USAC Credit Facility had $395 million of outstanding borrowings and no outstanding letters of credit. As of September 30, 2019, USAC had $1.21 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $410 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 4.73%. Compliance with Our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2019.

Redeemable Noncontrolling Interest (Notes)	9 Months Ended
Redeemable Noncontrolling Interest (Notes)	Sep. 30, 2019
Temporary Equity Disclosure [Abstract]
Redeemable Noncontrolling Interest [Text Block]	REDEEMABLE NONCONTROLLING INTERESTS Certain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of September 30, 2019 included (i) $477 million related to the USAC Preferred Units described below and (ii) $22 million related to noncontrolling interest holders in one of ETO’s consolidated subsidiaries that have the option to sell their interests to ETO. USAC Preferred Units In 2018, USAC issued 500,000 USAC Preferred Units in a private placement at a price of $1,000 per USAC Preferred Unit, for total gross proceeds of $500 million. The USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed.

Equity

9 Months Ended

Sep. 30, 2019

Partners' Capital Notes [Abstract]

Equity

EQUITY

The change in ET Common Units during the nine months ended September 30, 2019 was as follows:



	Nine Months Ended September 30, 2019
Number of Common Units, beginning of period	2,619.4
Common Units issued in connection with the distribution reinvestment plan	7.1
Common Units issued under equity incentive plans and other	0.5
Number of Common Units, end of period	2,627.0

ET Equity Distribution Program

In March 2017, the Partnership entered into an equity distribution agreement relating to at-the-market offerings of its common units with an aggregate offering price up to $1 billion. As of September 30, 2019, there have been no sales of common units under the equity distribution agreement.

ET Repurchase Program

During the nine months ended September 30, 2019, ET did not repurchase any ET common units under its current buyback program. As of September 30, 2019, $936 million remained available to repurchase under the current program.

ET Distribution Reinvestment Program

During the nine months ended September 30, 2019, distributions of $100 million were reinvested under the distribution reinvestment program. As of September 30, 2019, a total of 33 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment program.

Subsidiary Equity Transactions

ETO Preferred Units

As of September 30, 2019 and December 31, 2018, ETO’s outstanding preferred units included 950,000 ETO Series A Preferred Units, 550,000 ETO Series B Preferred Units, 18,000,000 ETO Series C Preferred Units and 17,800,000 ETO Series D Preferred Units. As of September 30, 2019, ETO’s outstanding preferred units also included 32,000,000 ETO Series E Preferred Units.

ETO Series E Preferred Units Issuance

In April 2019, ETO issued 32 million of its 7.600% ETO Series E Preferred Units at a price of $25 per unit, including 4 million ETO Series E Preferred Units pursuant to the underwriters’ exercise of their option to purchase additional preferred units. The total gross proceeds from the ETO Series E Preferred Unit issuance were $800 million, including $100 million from the underwriters’ exercise of their option. The net proceeds were used to repay amounts outstanding under ETO’s Five-Year Credit Facility and for general partnership purposes.

Distributions on the ETO Series E Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2024, at a rate of 7.600% per annum of the stated liquidation preference of $25. On and after May 15, 2024, distributions on the ETO Series E 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 5.161% per annum. The ETO Series E Preferred Units are redeemable at ETO’s option on or after May 15, 2024 at a redemption price of $25 per ETO Series E Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Sunoco LP Equity Distribution Program

For the nine months ended September 30, 2019, Sunoco LP issued no additional units under its at-the-market equity distribution program. As of September 30, 2019, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.

USAC Class B Conversion

On July 30, 2019, the 6,397,965 USAC Class B units held by the Partnership converted into 6,397,965 common units representing limited partner interests in USAC. These common units will participate in any future distributions declared by USAC.

USAC Distribution Reinvestment Program

During the nine months ended September 30, 2019, distributions of $0.7 million were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 44,605 USAC common units.

Parent Company Cash Distributions

Distributions declared and/or paid subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	February 8, 2019	February 19, 2019	$	0.3050
March 31, 2019	May 7, 2019	May 20, 2019	0.3050
June 30, 2019	August 6, 2019	August 19, 2019	0.3050
September 30, 2019	November 5, 2019	November 19, 2019	0.3050

ETO Cash Distributions

Distributions declared and/or paid by ETO subsequent to December 31, 2018 were as follows:



Period Ended	Record Date	Payment Date	Series A⁽¹⁾		Series B⁽¹⁾		Series C		Series D		Series E ⁽²⁾
December 31, 2018	February 1, 2019	February 15, 2019	$	31.25	$	33.125	$	0.4609	$	0.4766	$	—
March 31, 2019	May 1, 2019	May 15, 2019	—		—		0.4609		0.4766		—
June 30, 2019	August 1, 2019	August 15, 2019	31.25		33.125		0.4609		0.4766		0.5806
September 30, 2019	November 1, 2019	November 15, 2019	—		—		0.4609		0.4766		0.4750

⁽¹⁾ETOSeries A Preferred Unit and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.

⁽²⁾ETO Series E Preferred Unit distributions related to the period ended June 30, 2019 represent a prorated initial distribution.

Sunoco LP Cash Distributions

Distributions declared and/or paid by Sunoco LP subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	February 6, 2019	February 14, 2019	$	0.8255
March 31, 2019	May 7, 2019	May 15, 2019	0.8255
June 30, 2019	August 6, 2019	August 14, 2019	0.8255
September 30, 2019	November 5, 2019	November 19, 2019	0.8255

USAC Cash Distributions

Distributions declared and/or paid by USAC subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	January 28, 2019	February 8, 2019	$	0.5250
March 31, 2019	April 29, 2019	May 10, 2019	0.5250
June 30, 2019	July 29, 2019	August 9, 2019	0.5250
September 30, 2019	October 28, 2019	November 8, 2019	0.5250

Accumulated Other Comprehensive Income (Loss)

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



	September 30, 2019			December 31, 2018
Available-for-sale securities	$	10		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial loss related to pensions and other postretirement benefits	(41		)	(48		)
Investments in unconsolidated affiliates, net	(4		)	9
Total AOCI, net of tax	$	(40	)	$	(42	)

Income Taxes (Notes)	9 Months Ended
Income Taxes (Notes)	Sep. 30, 2019
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. ETC Sunoco historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with ETC Sunoco’s 2004 through 2011 years, ETC Sunoco 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 ETC Sunoco petitioned the Court of Federal Claims (“CFC”) on this issue. In November 2016, the CFC ruled against ETC Sunoco, and the Federal Circuit affirmed the CFC’s ruling on November 1, 2018. ETC Sunoco filed a petition for rehearing with the Federal Circuit on December 17, 2018, and this was denied on January 24, 2019. ETC Sunoco filed a petition for writ of certiorari with the United States Supreme Court that was docketed on May 24, 2019, to review the Federal Circuit’s affirmation of the CFC’s ruling. The government filed its response to ETC Sunoco’s petition on July 24, 2019. In October 2019, the Supreme Court denied the petition related to the years 2004 through 2009. The years 2010 through 2011 are on extension with the IRS. Due to the uncertainty surrounding the litigation, a reserve of $530 million was previously established for the full amount of the pending refund claims, and the receivable and reserve for this issue were netted in the balance sheet. Subsequent to the Supreme Court’s denial of the petition in October 2019, the receivable and reserve have been reversed, with no impact to the Partnership’s financial position or results of operations.

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

9 Months Ended

Sep. 30, 2019

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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

FERC Proceedings

By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by the order dated October 1, 2019. A hearing in the combined proceedings is scheduled for August, 2020, with an initial decision expected in early 2021.

By order issued February 19, 2019, the FERC initiated a review of Southwest Gas’ existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing. Southwest Gas filed a cost and revenue study on May 6, 2019. On July 10, 2019, Southwest Gas filed an Offer of Settlement in this Section 5 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. By order dated October 29, 2019, the FERC approved the settlement as filed, and there is not a material impact on revenue.

In addition, on November 30, 2018, Sea Robin filed a rate case pursuant to Section 4 of the Natural Gas Act. On July 22, 2019, Sea Robin filed an Offer of Settlement in this Section 4 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. By order dated October 17, 2019, the FERC approved the settlement as filed, and there is not a material impact on revenue.

Commitments

In the normal course of business, ETO 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. ETO 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.

ETO’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

We have certain non-cancelable rights-of-way (“ROW”) commitments, which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The table below reflects ROW expense included in operating expenses in the accompanying statements of operations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
ROW expense	$	5	$	5	$	17	$	18

PES Refinery Fire and Bankruptcy

We own an approximately 7.4% non-operating interest in PES, which owns a refinery in Philadelphia. In addition, the Partnership provides logistics services to PES under commercial contracts and Sunoco LP has historically purchased refined products from PES. In June 2019, an explosion and fire occurred at the refinery complex.

On July 21, 2019 (the "Petition Date"), PES Holdings, LLC and seven of its subsidiaries (collectively, the "Debtors") filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of

Chapter 11 of the United States Bankruptcy Code, as a result of the explosion and fire at the Philadelphia refinery complex. The Debtors have announced an intent to temporarily cease refinery operations. The Debtors have also defaulted on a $75 million note payable to a subsidiary of the Partnership. The Partnership has not recorded a valuation allowance related to the note receivable as of September 30, 2019, because management is not yet able to determine the collectability of the note in bankruptcy.

In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of September 30, 2019, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such claims, and these liabilities are included in the total environmental liabilities discussed below under “Environmental Remediation.” It may be necessary for the Partnership to record additional environmental remediation liabilities in the future; however, management is not currently able to estimate such additional liabilities.

PES has rejected certain of the Partnership’s commercial contracts pursuant to Section 365 of the Bankruptcy Code; however, the impact of the bankruptcy on the Partnership’s commercial contracts and related revenue loss (temporary or permanent) is unknown at this time, as the Debtors have expressed an intent to rebuild the refinery with the proceeds of insurance claims while concurrently running a sale process for its assets and operations. In addition, Sunoco LP has been successful at acquiring alternative supplies to replace fuel volume lost from PES and does not anticipate any material impact to its business going forward.

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”). 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. SRST filed an amended complaint and added claims based on treaties between SRST and 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. CRST moved for a preliminary injunction and temporary restraining order (“TRO”) to block operation of the pipeline, which motion was denied, and raised claims based on the religious rights of CRST.

In June 2017, SRST and CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala Sioux 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 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.

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 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 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 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.

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 sought an order from the Court directing the USACE as to how it should conduct its additional review on remand. Dakota Access and the USACE opposed both motions. On April 16, 2018, the Court denied both motions.

On March 19, 2018, the 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 May 3, 2018, the 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 would conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they would 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. On October 1, 2018, the USACE produced a detailed remand analysis document supporting that determination. The Tribes and certain of the individuals sought leave of the Court to amend their complaints to challenge the remand process and the USACE’s decision on remand.

On January 3, 2019, the Court granted the Tribes’ requests to supplement their respective complaints challenging the remand process, subject to defendants’ right to argue later that such supplementation may be overbroad and not permitted by law. On January 10, 2019, the Court denied the Oglala Sioux Tribe’s motion to amend its complaint to expand one of its pre-remand claims.

On January 17, 2019, the DOJ, on behalf of the USACE, moved to stay the litigation in light of the lapse in appropriations for the DOJ. The Tribes and individual plaintiffs opposed that request. On January 28, 2019, the USACE moved to withdraw this motion because appropriations for the DOJ had been restored. The Court granted this motion the next day.

On January 31, 2019, the USACE notified the Court that it had provided the administrative record for the remand to all parties. On February 27, 2019, the four Tribes filed a joint motion challenging the completeness of the record. The USACE opposed this motion in part, and Dakota Access opposed in full.

On May 8, 2019, the Court issued an order on Plaintiffs’ motion to complete the administrative record, requiring the parties to submit additional information so that the Court can determine what documents, if any, should be added to the record. Following submittal of additional information by the parties, the Court issued an order on June 11, 2019 that determined which documents were to be added to the record. Plaintiffs filed motions for summary judgment on August 16, 2019, and Defendants filed their opposition and cross motions on October 9, 2019. Briefing is scheduled to conclude by November 20, 2019.

While we believe that the pending lawsuits are unlikely to halt or suspend operation of the pipeline, we cannot assure this outcome. Energy Transfer 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 LLC’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 obtained, and will continue to seek, reimbursement for these losses.

MTBE Litigation

ETC Sunoco and Sunoco (R&M) (collectively, “Sunoco”) 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, 2019, Sunoco is a defendant in five cases, including one case each initiated by the States of Maryland 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 ETO, ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. (“SPMT”).

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-ETO 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, ET, ETO, ETP GP, and the members of Regency’s board of directors.

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 or fair to Regency. On March 29, 2016, the Delaware Court of Chancery granted the defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The 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. On April 26, 2019, the Court of Chancery granted Dieckman’s unopposed motion for class certification. On May 14, 2019, the Regency Defendants filed a motion for summary judgment arguing that Dieckman’s claims fail because the Regency Defendants relied on the advice of their financial advisor in approving the Regency Merger. Also on May 14, 2019, Dieckman filed a motion for partial summary judgment arguing, among other things, that Regency’s conflicts committee was not properly formed. On October 29, 2019, the court granted Plaintiff’s summary judgment motion, holding that Regency failed (1) to form a valid conflicts committee such that Regency failed to satisfy the Special Approval safe harbor in connection with the merger, and (2) to issue a proxy that was not materially misleading such that Regency failed to satisfy the Unitholder Approval safe harbor in connection with the merger. The court denied Defendants’ summary judgment motion which argued that Defendants approved the merger in good faith because they relied upon the fairness opinion of an investment bank. The court held that fact questions existed regarding whether Defendants actually relied upon the fairness opinion given by JP Morgan when voting in favor of the merger. Trial is currently set for December 10-16, 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 ETO 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 ETO against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETO. The jury also found that

ETO owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETO and awarded ETO $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETO 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. ETO’s motion for rehearing to the Court of Appeals was denied. On November 27, 2017, ETO filed a Petition for Review with the Texas Supreme Court. On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. On June 28, 2019, the Texas Supreme Court granted ETO’s petition for review and oral argument was heard on October 8, 2019. The parties now await a decision.

Litigation Filed By or Against Williams

On April 6, 2016, The Williams Companies, Inc. (“Williams”) filed a complaint against ET and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the issuance of the Partnership’s Series A Convertible Preferred Units (the “Issuance”) and (b) invalidate an amendment to ET’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

On May 3, 2016, ET and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the ET-Williams merger agreement (the “Merger Agreement”) by (a) blocking ET’s attempts to complete a public offering of the Series A Convertible Preferred Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause.

On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ET and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”) (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ET breached the Merger Agreement, (b) enjoin ET from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ET from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ET to close the merger or take various other affirmative actions.

ET filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ET asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ET for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ET sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.

After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ET on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ET could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied Williams’ requests for injunctive relief. The Court did not reach a decision regarding Williams’ claims related to the Issuance or ET’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee, and Defendants filed amended counterclaims and affirmative defenses. In response, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses.

On March 23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June 2016 trial, and as a result, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.

On December 1, 2017, the Court issued a Memorandum Opinion granting Williams’ motion to dismiss in part and denying Williams’ motion to dismiss in part. On April 16, 2018, the Court denied ET’s motion for re-argument of the Court’s decision granting Williams’ motion to dismiss in part. Discovery is ongoing, and a trial is currently set for June 2020.

Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.

Unitholder Litigation Relating to the Issuance

On April 12, 2016, two purported ET unitholders (together with plaintiff Chester County Employees’ Retirement Fund, the “Plaintiffs”) filed putative class action lawsuits against ET, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Defendants”) in the Delaware Court of Chancery (the “Issuance Litigation”). Another purported ET unitholder, Chester County Employees’ Retirement Fund, later joined the Issuance Litigation.

The Plaintiffs allege that the Issuance breached various provisions of ET’s partnership agreement. The Plaintiffs sought, among other things, preliminary and permanent injunctive relief that (a) prevents ET from making distributions to holders of the Series A Convertible Preferred Units and (b) invalidates an amendment to ET’s partnership agreement that was adopted on March 8, 2016 as part of the issuance of the Series A Convertible Preferred Units (“Issuance”).

On August 29, 2016, the Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.

The matter was tried in front of Vice Chancellor Glasscock on February 19-21, 2018. Post-trial arguments were heard on April 16, 2018. In a post-trial opinion dated May 17, 2018, the Court found that one provision of the Issuance breached ET’s partnership agreement but that this breach caused no damages. The Court denied Plaintiffs’ requests for injunctive relief and declined to award damages or any other form of relief. Plaintiffs subsequently filed a motion seeking $8.5 million in attorneys’ fees and expenses from the Defendants, which the Defendants opposed. On May 6, 2019, the Court entered an Order and Final Judgment consistent with its May 2018 post-trial opinion. The Court ordered that Energy Transfer pay $4.5 million in attorneys’ fees and expenses and also granted Plaintiffs’ Motion for Class Certification.

On June 5, 2019, Plaintiffs filed a notice of appeal to the Supreme Court of Delaware from, among other things, the May 17, 2018 Memorandum Opinion and the May 6, 2019 Order and Final Judgment. Plaintiffs filed their opening brief on July 22, 2019, the Defendants filed their answering brief on August 21, 2019, and the Plaintiffs filed their reply brief on September 5, 2019. The case is set for oral argument before the Supreme Court of Delaware on November 13, 2019.

The Defendants cannot predict the outcome of this appeal or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve this lawsuit. The Defendants believe that the Plaintiffs’ claims are without merit and intend to defend vigorously against them.

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. The State’s opposition to those motions was filed on October 12, 2018. Rover and other Defendants filed their replies on November 2, 2018. On March 13, 2019, the court granted Rover and the other Defendants’ motion to dismiss on all counts. On April 10, 2019, the Ohio EPA filed a notice of appeal. The Ohio EPA’s appeal is now pending before the Fifth District court of appeals. Briefing was completed in August of 2019 and oral argument has been set for November 5, 2019.

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, 2018 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. Construction of Rover is now complete and the pipeline is fully operational.

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. ETO, 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 18, 2018. On September 18, 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. On November 6, 2018, the court struck plaintiffs’ motion as premature.

At an October 2, 2018 scheduling conference, the USACE agreed to lodge the administrative record for Plaintiffs’ original complaint, which it has done. Challenges to the completeness of the record have been briefed and are currently pending before the court. At the October 18, 2018 conference, the court also scheduled summary judgment briefing on Plaintiffs’ original complaint; briefing is scheduled to conclude by the end of 2019.

On December 28, 2018, Judge Dick issued a General Order for the Middle District of Louisiana holding in abeyance all civil matters where the United States is a party. Notwithstanding the General Order, on January 11, 2019, Plaintiffs prematurely filed a Motion for Summary Judgment on its National Environmental Policy Act and Clean Waters Act claims.

On January 23, 2019, Plaintiffs filed a Second Motion for Preliminary Injunction based on alleged permit violations, which the court later denied. On February 11, 2019, the court denied Plaintiffs’ August 14, 2018 motion for leave to amend their complaint.

On February 14, 2019, Judge Dick ordered that all summary judgment briefing is stayed until the court rules on the motions challenging the completeness of the administrative record. Judge Dick further ordered that once those motions are decided, the parties will be allowed to update any summary judgment briefs they have already filed, if necessary, and that the court will set new briefing deadlines.

On April 26, 2019, Plaintiffs filed a motion seeking reconsideration of Judge Dick’s February 14, 2019 order staying summary judgment briefing. Defendants filed their oppositions on May 6, 2019.

On May 14, 2019, Judge Dick issued orders denying the outstanding record motions and Plaintiffs’ motion seeking reconsideration of the February 14, 2019 order.

On May 22, 2019, in a telephonic status conference, Judge Dick set a schedule for summary judgment briefing. Plaintiffs filed their motion for summary judgment on July 8, 2019 and Defendants filed their oppositions and cross-motions on August 9, 2019. Briefing is now concluded and the motions are before the court.

Revolution

On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line, in the vicinity of Ivy Lane located in Center Township, Beaver County, Pennsylvania. There were no injuries, but there were evacuations of local residents as a precautionary measure. The Pennsylvania Department of Environmental Protection (“PADEP”) and the Pennsylvania Public Utility Commission (“PUC”) are investigating the incident. On October 29, 2018, PADEP issued a Compliance Order requiring our subsidiary, ETC Northeast Pipeline, LLC (“ETC Northeast”), to cease all earth disturbance activities at the site (except as necessary to repair and maintain existing Best Management Practices (“BMPs”) and temporarily stabilize disturbed areas), implement and/or maintain the Erosion and Sediment BMPs at the site, stake the limit of disturbance, identify and report all areas of non-compliance, and submit an updated Erosion and Sediment Control Plan, a Temporary Stabilization Plan, and an updated Post Construction Stormwater Management Plan. The scope of the Compliance Order has been expanded to include the disclosure to PADEP of alleged violations of environmental permits with respect to various construction and post-construction activities and restoration obligations along the 42-mile route of the Revolution line. ETC Northeast filed an appeal of the Compliance Order with the Pennsylvania Environmental Hearing Board.

On February 8, 2019, PADEP filed a Petition to Enforce the Compliance Order with Pennsylvania’s Commonwealth Court. The court issued an Order on February 14, 2019 requiring the submission of an answer to the Petition on or before March 12, 2019, and scheduled a hearing on the Petition for March 26, 2019. On March 12, 2019, ETC Northeast answered the Petition. ETC Northeast and PADEP have since agreed to a Stipulated Order regarding the issues raised in the Compliance Order, which obviated the need for a hearing. The Commonwealth Court approved the Stipulated Order on March 26, 2019. On February 8, 2019, PADEP also issued a Permit Hold on any requests for approvals/permits or permit amendments made by us or any of our subsidiaries for any projects in Pennsylvania pursuant to the state’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board on March 11, 2019. On May 14, 2019, PADEP issued a Compliance Order related to impacts to streams and wetlands. The Partnership filed an appeal of the Streams and Wetlands Compliance Order on June 14, 2019. On August 5, 2019, ETC Northeast and the Partnership received a Subpoena to Compel Documents and Information related to the Revolution pipeline and the Incident. ETC Northeast and the Partnership filed an appeal of the Subpoena on September 4, 2019.

The Partnership continues to work through these issues with PADEP during the pendency of these appeals.

The Pennsylvania Office of Attorney General has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.

Chester County, Pennsylvania Investigation

In December 2018, the Chester County District Attorney sent a letter to the Partnership stating that it was investigating the Partnership and related entities for “potential crimes” related to the Mariner East pipelines.

Subsequently, the matter was submitted to an Investigating grand Jury in Chester County, Pennsylvania. As part of the Grand Jury proceedings, since April and August 2019, the Partnership was served with a total of forty-one grand jury subpoenas seeking a variety of documents and records sought by the Chester County Investigation Grand Jury. On September 24, 2019, the Chester County District Attorney sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership intends to respond to the notice of Intent within the proscribed time period.

Delaware County, Pennsylvania Investigation

On March 11, 2019, the Delaware County District Attorney’s Office (“Delaware County D.A.”) announced that the Delaware County D.A. and the Pennsylvania Attorney General’s Office, at the request of the Delaware County D.A., are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. The Partnership has not been appraised of the specific conduct under investigation. This investigation is ongoing. While the Partnership will cooperate with the investigation, it intends to vigorously defend itself against these allegations.

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, 2019 and December 31, 2018, accruals of approximately $61 million and $55 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 SPLP before the 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 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 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 this matter. SPLP submitted a petition for permission to appeal on this issue of standing. Senator Dinniman and intervenors opposed that petition.

Briefing in the Commonwealth Court has been completed. On June 3, 2019, the Commonwealth Court heard argument on whether Senator Dinniman has standing. On September 9, 2019, the Commonwealth Court issued an Opinion finding that Senator Dinniman did not have standing in either his personal or representational capacity. The Commonwealth Court’s Order remanded the case to the PUC to dissolve the interim emergency injunction and dismiss the Complaint. Senator Dinniman has not sought to appeal the ruling.

Previously, on March 29, 2019, SPLP filed a supplemental affidavit with the PUC in accordance with the established procedure to request the PUC lift the stay of construction of ME2 for one of the remaining work locations in the Township - Shoen Road. That same day, Senator Dinniman filed a letter objecting to SPLP’s request, arguing the Commonwealth Court’s order staying all proceedings barred the PUC from issuing an approval to lift the stay of construction of ME2 at Shoen Road. Given the Commonwealth Court’s September 9 opinion, the PUC dissolved the injunction on September 19, 2019 and work on Shoen Road commenced.

No amounts have been recorded in our September 30, 2019 or December 31, 2018 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 on behalf of EPA and Louisiana Department of Environmental Quality (“LDEQ”) notifying SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three separate crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) which allegedly occurred 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) which allegedly occurred in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma which allegedly occurred in January 2015. In January 2019, a Consent Decree approved by all parties as well as an accompanying Complaint was filed in the United States District Court for the Western District of Louisiana seeking public comment and final court approval to resolve all penalties with DOJ and LDEQ for the three releases. Subsequently, the court approved the Consent Decree and the penalty payment of $5.4 million was satisfied. The Consent Decree requires certain injunctive relief to be completed on the Longview-to-Mayersville pipeline within three years but the injunctive relief is not expected to have any material impact on operations. In addition to resolution of the civil penalty and injunctive relief, we continue to discuss natural 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.

In October 2018, Pipeline Hazardous Materials Safety Administration (“PHMSA”) issued a notice of proposed safety order (the “Notice”) to SPMT, a wholly owned subsidiary of ETO. The Notice alleged that conditions exist on certain pipeline facilities owned and operated by SPMT in Nederland, Texas that pose a pipeline integrity risk to public safety, property or the environment. The Notice also made preliminary findings of fact and proposed corrective measures. SPMT responded to the Notice by submitting a timely written response on November 2, 2018, attended an informal consultation held on January 30, 2019 and entered into a consent agreement with PHMSA resolving the issues in the Notice as of March 2019. SPMT is currently awaiting response from PHMSA regarding the approval status of the submitted Remedial Work Plan.

On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The rupture occurred on the Noble to Douglas 8” pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC. The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure. SPLP is negotiating a settlement agreement with the OCC for a lesser penalty.

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

•

ETC Sunoco 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, 2019, ETC Sunoco had been named as a PRP at approximately 38 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. ETC Sunoco is usually one of a number of companies identified as a PRP at a site. ETC Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon ETC Sunoco’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, 2019		December 31, 2018
Current	$	46	$	42
Non-current	276		295
Total environmental liabilities	$	322	$	337

We have 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, 2019 and 2018, the Partnership recorded $16 million and $17 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2019 and 2018, the Partnership recorded $31 million and $32 million, respectively, of expenditures related to environmental cleanup programs.

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

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 Safety and Health 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, 2019

Revenue [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE

Disaggregation of Revenue

The Partnership’s consolidated financial statements reflect eight reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes. Note 16 depicts the disaggregation of revenue by segment.

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.

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 prepayments or 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. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.

The following table summarizes the consolidated activity of our contract liabilities:



	Contract Liabilities
Balance, December 31, 2018	$	392
Additions	448
Revenue recognized	(491		)
Balance, September 30, 2019	$	349

Balance, January 1, 2018	$	205
Additions	409
Revenue recognized	(211		)
Balance, September 30, 2018	$	403

The balances of receivables from contracts with customers listed in the table below, all of which are attributable to Sunoco LP, include both current trade receivables and long-term receivables, net of allowance for doubtful accounts. The allowance for receivables represents Sunoco LP’s best estimate of the probable losses associated with potential customer defaults. Sunoco LP determines the allowance based on historical experience and on a specific identification basis.

The balances of Sunoco LP’s contract assets as of September 30, 2019 and December 31, 2018 were as follows:



	September 30, 2019		December 31, 2018
Contract balances:
Contract asset	$	102	$	75
Accounts receivable from contracts with customers	403		348

Costs to Obtain or Fulfill a Contract

Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g. sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in future and are expected to be recovered. These capitalized costs are recorded as a part of other current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that Sunoco LP recognized for the three months ended September 30, 2019 and 2018 was $4 million and $4 million, respectively. The amount of amortization expense that Sunoco LP recognized for the nine months ended September 30, 2019 and 2018 was $12 million and $10 million, respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less.

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 expected contract consideration 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, 2019, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $41.13 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:



	Years Ending December 31,
	2019 (remainder)		2020		2021		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2019	$	1,716	$	5,544	$	4,812	$	29,062	$	41,134

Lease Accounting (Notes)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Lessee, Operating Leases [Text Block]

LEASE ACCOUNTING

Lessee Accounting

The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet.

At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term.

Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership, and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term.

To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives.

Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance.

For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.

The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of September 30, 2019 were as follows:



	September 30, 2019
Operating leases:
Lease right-of-use assets, net	$	850
Operating lease current liabilities	57
Accrued and other current liabilities	1
Non-current operating lease liabilities	807
Finance leases:
Property, plant and equipment, net	$	2
Lease right-of-use assets, net	39
Accrued and other current liabilities	1
Current maturities of long-term debt	7
Long-term debt, less current maturities	35
Other non-current liabilities	2

The components of lease expense for the three and nine months ended September 30, 2019 were as follows:



	Income Statement Location	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease costs:
Operating lease cost	Cost of goods sold	$	7	$	23
Operating lease cost	Operating expenses	18		54
Operating lease cost	Selling, general and administrative	3		10
Total operating lease costs		28		87
Finance lease costs:
Amortization of lease assets	Depreciation, depletion and amortization	2		4
Interest on lease liabilities	Interest expense, net of capitalized interest	1		1
Total finance lease costs		3		5
Short-term lease cost	Operating expenses	10		33
Variable lease cost	Operating expenses	3		11
Lease costs, gross		44		136
Less: Sublease income	Other revenue	14		37
Lease costs, net		$	30	$	99

The weighted average remaining lease terms and weighted average discount rates as of September 30, 2019 were as follows:



	September 30, 2019
Weighted-average remaining lease term (years):
Operating leases	22
Finance leases	6
Weighted-average discount rate (%):
Operating leases	5	%
Finance leases	5	%

Cash flows and non-cash activity related to leases for the nine months ended September 30, 2019 were as follows:



	Nine Months Ended September 30, 2019
Operating cash flows from operating leases	$	(78	)
Lease assets obtained in exchange for new finance lease liabilities	37
Lease assets obtained in exchange for new operating lease liabilities	36

Maturities of lease liabilities as of September 30, 2019 are as follows:



	Operating Leases		Finance Leases		Total
2019 (remainder)	$	27	$	2	$	29
2020	96		10		106
2021	87		10		97
2022	75		10		85
2023	70		9		79
Thereafter	1,170		10		1,180
Total lease payments	1,525		51		1,576
Less: present value discount	660		6		666
Present value of lease liabilities	$	865	$	45	$	910

Lessor Accounting

Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement.

Rental income included in other revenue in our consolidated statement of operations for the three and nine months ended September 30, 2019 was $39 million and $111 million, respectively.

Future minimum operating lease payments receivable as of September 30, 2019 are as follows:



	Lease Receivables
2019 (remainder)	$	25
2020	85
2021	69
2022	56
2023	4
Thereafter	7
Total undiscounted cash flows	$	246

Derivative Assets And Liabilities

9 Months Ended

Sep. 30, 2019

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Derivative 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 in 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 futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. 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, 2019			December 31, 2018
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX ⁽¹⁾	20,563		2019-2024	16,845		2019-2020
Fixed Swaps/Futures	1,723		2019-2020	468		2019
Options – Puts	—		—	10,000		2019
Power (Megawatt):
Forwards	2,847,350		2019-2029	3,141,520		2019
Futures	222,440		2019-2020	56,656		2019-2021
Options – Puts	515,317		2019-2020	18,400		2019
Options – Calls	(756,153	)	2019-2021	284,800		2019
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(23,653	)	2019-2022	(30,228	)	2019-2021
Swing Swaps IFERC	22,365		2019-2020	54,158		2019-2020
Fixed Swaps/Futures	2,323		2019-2021	(1,068	)	2019-2021
Forward Physical Contracts	(29,492	)	2019-2021	(123,254	)	2019-2020
NGLs (MBbls) – Forwards/Swaps	(9,687	)	2019-2021	(2,135	)	2019
Refined Products (MBbls) – Futures	(906	)	2019-2021	(1,403	)	2019
Crude (MBbls) – Forwards/Swaps	9,510		2019-2020	20,888		2019
Corn (thousand bushels)	(1,760	)	2019	(1,920	)	2019
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(31,703	)	2019-2020	(17,445	)	2019
Fixed Swaps/Futures	(31,703	)	2019-2020	(17,445	)	2019
Hedged Item – Inventory	31,703		2019-2020	17,445		2019


⁽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, 2019		December 31, 2018
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.56% and receive a floating rate	$	—	$	400
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		400
July 2022⁽²⁾	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	400		—
March 2019	Pay a floating rate and receive a fixed rate of 1.42%	—		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 our 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, we may at times require collateral under certain circumstances to mitigate credit risk as necessary. We also implements the use of industry standard commercial agreements which allow for the netting of positive and negative 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.

Our counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, motor fuel distributors, municipalities, utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic factors or regulatory changes that could impact its 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.

We have 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, 2019		December 31, 2018		September 30, 2019			December 31, 2018
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	16	$	—	$	—		$	(13	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	543		402		(520		)	(397		)
Commodity derivatives	120		158		(77		)	(173		)
Interest rate derivatives	—		—		(528		)	(163		)
	663		560		(1,125		)	(733		)
Total derivatives	$	679	$	560	$	(1,125	)	$	(746	)

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, 2019			December 31, 2018			September 30, 2019			December 31, 2018
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(528	)	$	(163	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	120			158			(77		)	(173		)
Broker cleared derivative contracts	Other current assets (liabilities)	559			402			(520		)	(410		)
Total gross derivatives		679			560			(1,125		)	(746		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(64		)	(47		)	64			47
Counterparty netting	Other current assets (liabilities)	(519		)	(397		)	519			397
Total net derivatives		$	96		$	116		$	(542	)	$	(302	)

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 non-current 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,
		2019		2018		2019		2018
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	—	$	—	$	—	$	9



	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,
		2019			2018		2019			2018
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	3		$	3	$	15		$	36
Commodity derivatives – Non-trading	Cost of products sold	21			21		(53		)	(345		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(175		)	45		(371		)	117
Total		$	(151	)	$	69	$	(409	)	$	(192	)

Related Party Transactions

9 Months Ended

Sep. 30, 2019

Related Party Transactions

RELATED PARTY TRANSACTIONS

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

The following table summarizes the revenues from related companies on our consolidated statements of operations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Revenues from related companies	$	129	$	103	$	374	$	325

The following table summarizes the accounts receivable from related companies on our consolidated balance sheets:



	September 30, 2019		December 31, 2018
Accounts receivable from related companies:
FGT	$	51	$	25
Phillips 66	36		42
Traverse	25		—
Other	54		44
Total accounts receivable from related companies	$	166	$	111

As of September 30, 2019 and December 31, 2018, accounts payable with unconsolidated affiliates in the Partnership’s consolidated balance sheets totaled $32 million and $59 million, respectively.

Reportable Segments

9 Months Ended

Sep. 30, 2019

Segment Reporting [Abstract]

Reportable Segments

REPORTABLE SEGMENTS

As a result of the Energy Transfer Merger in October 2018, our reportable segments were reevaluated and currently reflect the following segments, which conduct their business primarily in the United States:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services;

•investment in Sunoco LP;

•investment in USAC; and

•all other.

Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

The investment in USAC segment reflects the results of USAC beginning April 2018, the date that the Partnership obtained control of USAC.

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

We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership 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, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

The following tables present financial information by segment:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	675		$	846		$	2,115		$	2,424
Intersegment revenues	89			76			270			186
	764			922			2,385			2,610
Interstate transportation and storage:
Revenues from external customers	475			440			1,454			1,174
Intersegment revenues	4			5			16			13
	479			445			1,470			1,187
Midstream:
Revenues from external customers	704			537			1,704			1,571
Intersegment revenues	876			1,716			2,792			4,170
	1,580			2,253			4,496			5,741
NGL and refined products transportation and services:
Revenues from external customers	2,271			2,845			7,340			7,467
Intersegment revenues	607			218			1,181			710
	2,878			3,063			8,521			8,177
Crude oil transportation and services:
Revenues from external customers	4,453			4,422			13,685			12,942
Intersegment revenues	—			16			—			44
	4,453			4,438			13,685			12,986
Investment in Sunoco LP:
Revenues from external customers	4,328			4,760			12,494			13,114
Intersegment revenues	3			1			4			3
	4,331			4,761			12,498			13,117
Investment in USAC:
Revenues from external customers	169			166			505			331
Intersegment revenues	6			3			15			5
	175			169			520			336
All other:
Revenues from external customers	420			498			1,196			1,491
Intersegment revenues	21			27			80			108
	441			525			1,276			1,599
Eliminations	(1,606		)	(2,062		)	(4,358		)	(5,239		)
Total revenues	$	13,495		$	14,514		$	40,493		$	40,514



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	235		$	221		$	777		$	621
Interstate transportation and storage	442			459			1,358			1,200
Midstream	411			434			1,205			1,225
NGL and refined products transportation and services	667			498			1,923			1,410
Crude oil transportation and services	700			682			2,257			1,694
Investment in Sunoco LP	192			208			497			457
Investment in USAC	104			90			310			185
All other	35			(15		)	80			49
Adjusted EBITDA (consolidated)	2,786			2,577			8,407			6,841
Depreciation, depletion and amortization	(784		)	(750		)	(2,343		)	(2,109		)
Interest expense, net of interest capitalized	(579		)	(535		)	(1,747		)	(1,511		)
Impairment losses	(12		)	—			(62		)	—
Gains (losses) on interest rate derivatives	(175		)	45			(371		)	117
Non-cash compensation expense	(27		)	(27		)	(85		)	(82		)
Unrealized gains (losses) on commodity risk management activities	64			97			90			(255		)
Losses on extinguishments of debt	—			—			(18		)	(106		)
Inventory valuation adjustments	(26		)	(7		)	71			50
Adjusted EBITDA related to unconsolidated affiliates	(161		)	(179		)	(470		)	(503		)
Equity in earnings of unconsolidated affiliates	82			87			224			258
Adjusted EBITDA related to discontinued operations	—			—			—			25
Other, net	47			33			67			59
Income from continuing operations before income tax expense	1,215			1,341			3,763			2,784
Income tax (expense) benefit from continuing operations	(54		)	52			(214		)	(6		)
Income from continuing operations	1,161			1,393			3,549			2,778
Loss from discontinued operations, net of income taxes	—			(2		)	—			(265		)
Net income	$	1,161		$	1,391		$	3,549		$	2,513

Operations And Organization Accounting policy (Policies)	9 Months Ended
	Sep. 30, 2019
Accounting Policies [Abstract]
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]	Goodwill The Partnership’s interstate transportation and storage segment owns Southwest Gas which owns and operates natural gas storage assets. Due to a decrease in the demand for storage on these assets, the Partnership performed an interim impairment test on the assets of Southwest Gas during the three months ended September 30, 2019. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of $12 million related to Southwest Gas, primarily due to decreases in projected future revenues and cash flows. No other impairments of the Partnership’s other assets were identified. The Partnership estimated the fair value of Southwest Gas by using the income approach. The income approach is based on the present value of future cash flows, which are derived from our long-term financial forecasts, and requires significant assumptions including, among others, a discount rate and a terminal value.
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on February 22, 2019. 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.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
Lessee, Leases [Policy Text Block]	Change in Accounting Policy Adoption of Lease Accounting Standard In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which has amended the FASB Accounting Standards Codification (“ASC”) and introduced Topic 842, Leases. On January 1, 2019, the Partnership has adopted ASC Topic 842 (“Topic 842”), which is effective for interim and annual reporting periods beginning on or after December 15, 2018. Topic 842 requires entities to recognize lease assets and liabilities on the balance sheet for all leases with a term of more than one year, including operating leases, which historically were not recorded on the balance sheet in accordance with the prior standard. To adopt Topic 842, the Partnership recognized a cumulative catch-up adjustment to the opening balance sheet as of January 1, 2019 related to certain leases that existed as of that date. As permitted, we have not retrospectively modified our consolidated financial statements for comparative purposes. The adoption of the standard had a material impact on our consolidated balance sheet, but did not have an impact on our consolidated statements of operations, comprehensive income or cash flows. As a result of adoption, we have recorded additional net right-of-use (“ROU”) lease assets and lease liabilities of approximately $888 million and $888 million, respectively, as of January 1, 2019. In addition, we have updated our business processes, systems, and internal controls to support the on-going reporting requirements under the new standard. To adopt Topic 842, the Partnership elected the package of practical expedients permitted under the transition guidance within the standard. The expedient package allowed us not to reassess whether existing contracts contained a lease, the lease classification of existing leases and initial direct cost for existing leases. In addition to the package of practical expedients, the Partnership has elected not to capitalize amounts pertaining to leases with terms less than twelve months, to use the portfolio approach to determine discount rates, not to separate non-lease components from lease components and not to apply the use of hindsight to the active lease population. Lessee Accounting The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet. At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership, and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term. To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives. Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance. For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.

Cash And Cash Equivalents Cash and Cash Equivalents (Policies)	9 Months Ended
	Sep. 30, 2019
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. The Partnership’s balance sheets did not include any material amounts of restricted cash as of September 30, 2019 or December 31, 2018. 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, 2019
Inventory Disclosure [Abstract]
Inventory, Policy [Policy Text Block]	We utilize commodity derivatives to manage price volatility associated with its natural gas inventories. 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, 2019
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, 2019 were $50.79 billion and $46.85 billion, respectively. As of December 31, 2018, the aggregate fair value and carrying amount of our consolidated debt obligations were $45.06 billion and $46.03 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ 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, 2019, no transfers were made between any levels within the fair value hierarchy.

Income Taxes Income Taxes (Policies)	9 Months Ended
Income Taxes Income Taxes (Policies)	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Income Tax, Policy [Policy Text Block]	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.

- Definition

Disclosure of accounting policy for income taxes, which may include its accounting policies for recognizing and measuring deferred tax assets and liabilities and related valuation allowances, recognizing investment tax credits, operating loss carryforwards, tax credit carryforwards, and other carryforwards, methodologies for determining its effective income tax rate and the characterization of interest and penalties in the financial statements.

+ References

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-Publisher FASB
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Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
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+ Details

Revenue Revenue (Policies)

9 Months Ended

Sep. 30, 2019

Revenue from Contract with Customer [Abstract]

Revenue [Policy Text Block]

Disaggregation of Revenue

Revenue Recognition, Deferred Revenue [Policy Text Block]

Contract Balances with Customers

The following table summarizes the consolidated activity of our contract liabilities:



	Contract Liabilities
Balance, December 31, 2018	$	392
Additions	448
Revenue recognized	(491		)
Balance, September 30, 2019	$	349

Balance, January 1, 2018	$	205
Additions	409
Revenue recognized	(211		)
Balance, September 30, 2018	$	403

Performance Obligations

Lease Accounting (Policies)	9 Months Ended
Lease Accounting (Policies)	Sep. 30, 2019
Leases [Abstract]
Lessee, Leases [Policy Text Block]	Change in Accounting Policy Adoption of Lease Accounting Standard In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which has amended the FASB Accounting Standards Codification (“ASC”) and introduced Topic 842, Leases. On January 1, 2019, the Partnership has adopted ASC Topic 842 (“Topic 842”), which is effective for interim and annual reporting periods beginning on or after December 15, 2018. Topic 842 requires entities to recognize lease assets and liabilities on the balance sheet for all leases with a term of more than one year, including operating leases, which historically were not recorded on the balance sheet in accordance with the prior standard. To adopt Topic 842, the Partnership recognized a cumulative catch-up adjustment to the opening balance sheet as of January 1, 2019 related to certain leases that existed as of that date. As permitted, we have not retrospectively modified our consolidated financial statements for comparative purposes. The adoption of the standard had a material impact on our consolidated balance sheet, but did not have an impact on our consolidated statements of operations, comprehensive income or cash flows. As a result of adoption, we have recorded additional net right-of-use (“ROU”) lease assets and lease liabilities of approximately $888 million and $888 million, respectively, as of January 1, 2019. In addition, we have updated our business processes, systems, and internal controls to support the on-going reporting requirements under the new standard. To adopt Topic 842, the Partnership elected the package of practical expedients permitted under the transition guidance within the standard. The expedient package allowed us not to reassess whether existing contracts contained a lease, the lease classification of existing leases and initial direct cost for existing leases. In addition to the package of practical expedients, the Partnership has elected not to capitalize amounts pertaining to leases with terms less than twelve months, to use the portfolio approach to determine discount rates, not to separate non-lease components from lease components and not to apply the use of hindsight to the active lease population. Lessee Accounting The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet. At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership, and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term. To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives. Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance. For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.
Lessor, Leases [Policy Text Block]	Lessor Accounting Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement. Rental income included in other revenue in our consolidated statement of operations for the three and nine months ended September 30, 2019 was $39 million and $111 million, respectively.

Derivative Assets And Liabilities Derivative Assets and Liabilities (Policies)	9 Months Ended
	Sep. 30, 2019
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 our 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, we may at times require collateral under certain circumstances to mitigate credit risk as necessary. We also implements the use of industry standard commercial agreements which allow for the netting of positive and negative 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. Our counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, motor fuel distributors, municipalities, utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic factors or regulatory changes that could impact its 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. We have 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 in 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 futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. 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. 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 non-current depending on the anticipated settlement date.

Operations And Organization Operations and Organization (Tables)

9 Months Ended

Sep. 30, 2019

Operations and Organizations Tables [Abstract]

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

Cumulative-effect adjustments made to the opening balance sheet at January 1, 2019 were as follows:



	Balance at December 31, 2018, as previously reported		Adjustments due to Topic 842 (Leases)			Balance at January 1, 2019
Assets:
Property, plant and equipment, net	$	66,963	$	(1	)	$	66,962
Lease right-of-use assets, net	—		889			889
Liabilities:
Operating lease current liabilities	$	—	$	71		$	71
Accrued and other current liabilities	2,918		(1		)	2,917
Current maturities of long-term debt	2,655		1			2,656
Long-term debt, less current maturities	43,373		6			43,379
Non-current operating lease liabilities	—		823			823
Other non-current liabilities	1,184		(12		)	1,172

Additional disclosures related to lease accounting are included in Note 13.

Acquisitions (Tables)

9 Months Ended

Sep. 30, 2019

Disposal Groups, Including Discontinued Operations [Table Text Block]



	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
REVENUES	$	—		$	349

COSTS AND EXPENSES
Cost of products sold	—			305
Operating expenses	—			61
Depreciation, depletion and amortization	—			—
Impairment losses	—			—
Selling, general and administrative	—			7
Total costs and expenses	—			373
OPERATING LOSS	—			(24		)
Interest expense, net	—			(2		)
Loss on extinguishment of debt and other	—			(20		)
Other, net	—			(61		)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE	—			(107		)
Income tax expense	2			158
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	(2	)	$	(265	)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ET	$	—		$	(10	)

- Definition

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

+ References

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Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
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-Name Accounting Standards Codification
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+ Details

Cash And Cash Equivalents (Tables)

9 Months Ended

Sep. 30, 2019

Supplemental Cash Flow Information [Abstract]

Cash Flow, Operating Capital [Table Text Block]

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



	Nine Months Ended September 30,
	2019			2018
Accounts receivable	$	(353	)	$	155
Accounts receivable from related companies	(36		)	64
Inventories	(66		)	78
Other current assets	14			(19		)
Other non-current assets, net	(127		)	(25		)
Accounts payable	25			(234		)
Accounts payable to related companies	(37		)	(110		)
Accrued and other current liabilities	129			422
Other non-current liabilities	(103		)	24
Derivative assets and liabilities, net	307			68
Net change in operating assets and liabilities, net of effects of acquisitions	$	(247	)	$	423

Schedule Of Non-Cash Investing and Non-Cash Financing Activities

Non-cash activities are as follows:



	Nine Months Ended September 30,
	2019		2018
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	$	1,202	$	1,059
Losses from subsidiary common unit transactions	—		(125		)
Lease assets obtained in exchange for new lease liabilities	73		—
NON-CASH FINANCING ACTIVITIES:
Distribution reinvestment	$	100	$	—
Conversion of Series A Convertible Preferred Units to common units	—		589

Inventories (Tables)

9 Months Ended

Sep. 30, 2019

Inventory, Net [Abstract]

Schedule Of Inventory

Inventories consisted of the following:



	September 30, 2019		December 31, 2018
Natural gas, NGLs and refined products	$	900	$	833
Crude oil	510		506
Spare parts and other	404		338
Total inventories	$	1,814	$	1,677

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2019

Fair Value Measurements [Abstract]

Fair Value, by Balance Sheet Grouping [Table Text Block]



				Fair Value Measurements at September 30, 2019
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	27		$	27		$	—
Swing Swaps IFERC	5			—			5
Fixed Swaps/Futures	44			44			—
Forward Physical Contracts	5			—			5
Power:
Forwards	21			—			21
Futures	4			4			—
NGLs – Forwards/Swaps	529			529			—
Refined Products – Futures	1			1			—
Crude – Forwards/Swaps	43			43			—
Total commodity derivatives	679			648			31
Other non-current assets	29			19			10
Total assets	$	708		$	667		$	41
Liabilities:
Interest rate derivatives	$	(528	)	$	—		$	(528	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(54		)	(54		)	—
Swing Swaps IFERC	(9		)	—			(9		)
Fixed Swaps/Futures	(29		)	(29		)	—
Forward Physical Contracts	(2		)	—			(2		)
Power:
Forwards	(14		)	—			(14		)
Futures	(5		)	(5		)	—
Options – Calls	(1		)	(1		)	—
NGLs – Forwards/Swaps	(479		)	(479		)	—
Refined Products – Futures	(3		)	(3		)	—
Crude – Forwards/Swaps	(1		)	(1		)	—
Total commodity derivatives	(597		)	(572		)	(25		)
Total liabilities	$	(1,125	)	$	(572	)	$	(553	)



				Fair Value Measurements at December 31, 2018
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	42		$	42		$	—
Swing Swaps IFERC	52			8			44
Fixed Swaps/Futures	97			97			—
Forward Physical Contracts	20			—			20
Power:
Forwards	48			—			48
Futures	1			1			—
Options – Calls	1			1			—
NGLs – Forwards/Swaps	291			291			—
Refined Products – Futures	7			7			—
Crude – Forwards/Swaps	1			1			—
Total commodity derivatives	560			448			112
Other non-current assets	26			17			9
Total assets	$	586		$	465		$	121
Liabilities:
Interest rate derivatives	$	(163	)	$	—		$	(163	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(91		)	(91		)	—
Swing Swaps IFERC	(40		)	—			(40		)
Fixed Swaps/Futures	(88		)	(88		)	—
Forward Physical Contracts	(21		)	—			(21		)
Power:
Forwards	(42		)	—			(42		)
Futures	(1		)	(1		)	—
NGLs – Forwards/Swaps	(224		)	(224		)	—
Refined Products – Futures	(15		)	(15		)	—
Crude – Forwards/Swaps	(61		)	(61		)	—
Total commodity derivatives	(583		)	(480		)	(103		)
Total liabilities	$	(746	)	$	(480	)	$	(266	)

Net Income per Limited Partner Unit (Tables)

9 Months Ended

Sep. 30, 2019

Earnings Per Share [Abstract]

Reconciliation Of Net Income And Weighted Average Units

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Income from continuing operations	$	1,161	$	1,393	$	3,549	$	2,778
Less: Income from continuing operations attributable to noncontrolling interests	317		1,010		931		1,667
Less: Net income attributable to redeemable noncontrolling interests	12		12		38		24
Income from continuing operations, net of noncontrolling interests	832		371		2,580		1,087
Less: Series A Convertible Preferred Unitholders’ interest in income	—		—		—		33
Less: General Partner’s interest in income	1		1		3		3
Income from continuing operations available to Limited Partners	$	831	$	370	$	2,577	$	1,051
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	2,624.9		1,158.2		2,621.9		1,117.7
Basic income from continuing operations per Limited Partner unit	$	0.32	$	0.32	$	0.98	$	0.94
Basic income (loss) from discontinued operations per Limited Partner unit	$	—	$	—	$	—	$	(0.01	)
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	831	$	370	$	2,577	$	1,051
Dilutive effect of distributions to Series A Convertible Preferred Unitholders	—		—		—		33
Diluted income from continuing operations available to Limited Partners	$	831	$	370	$	2,577	$	1,084
Weighted average limited partner units	2,624.9		1,158.2		2,621.9		1,117.7
Dilutive effect of Series A Convertible Preferred Units	—		—		—		40.5
Dilutive effect of unvested unit awards	10.6		—		11.0		—
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	2,635.5		1,158.2		2,632.9		1,158.2
Diluted income from continuing operations per Limited Partner unit	$	0.32	$	0.32	$	0.98	$	0.94
Diluted income (loss) from discontinued operations per Limited Partner unit	$	—	$	—	$	—	$	(0.01	)

Equity (Tables)

9 Months Ended

Sep. 30, 2019

Schedule of Capital Units [Table Text Block]

The change in ET Common Units during the nine months ended September 30, 2019 was as follows:



	Nine Months Ended September 30, 2019
Number of Common Units, beginning of period	2,619.4
Common Units issued in connection with the distribution reinvestment plan	7.1
Common Units issued under equity incentive plans and other	0.5
Number of Common Units, end of period	2,627.0

Accumulated Other Comprehensive Income

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



	September 30, 2019			December 31, 2018
Available-for-sale securities	$	10		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial loss related to pensions and other postretirement benefits	(41		)	(48		)
Investments in unconsolidated affiliates, net	(4		)	9
Total AOCI, net of tax	$	(40	)	$	(42	)

Parent Company [Member]

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

Distributions declared and/or paid subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	February 8, 2019	February 19, 2019	$	0.3050
March 31, 2019	May 7, 2019	May 20, 2019	0.3050
June 30, 2019	August 6, 2019	August 19, 2019	0.3050
September 30, 2019	November 5, 2019	November 19, 2019	0.3050

ETO [Member]

Schedule of Preferred Units [Table Text Block]

Distributions declared and/or paid by ETO subsequent to December 31, 2018 were as follows:



Period Ended	Record Date	Payment Date	Series A⁽¹⁾		Series B⁽¹⁾		Series C		Series D		Series E ⁽²⁾
December 31, 2018	February 1, 2019	February 15, 2019	$	31.25	$	33.125	$	0.4609	$	0.4766	$	—
March 31, 2019	May 1, 2019	May 15, 2019	—		—		0.4609		0.4766		—
June 30, 2019	August 1, 2019	August 15, 2019	31.25		33.125		0.4609		0.4766		0.5806
September 30, 2019	November 1, 2019	November 15, 2019	—		—		0.4609		0.4766		0.4750

⁽¹⁾ETOSeries A Preferred Unit and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.

⁽²⁾ETO Series E Preferred Unit distributions related to the period ended June 30, 2019 represent a prorated initial distribution.

Sunoco LP [Member]

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

Distributions declared and/or paid by Sunoco LP subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	February 6, 2019	February 14, 2019	$	0.8255
March 31, 2019	May 7, 2019	May 15, 2019	0.8255
June 30, 2019	August 6, 2019	August 14, 2019	0.8255
September 30, 2019	November 5, 2019	November 19, 2019	0.8255

USA Compression Partners, LP [Member]

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

Distributions declared and/or paid by USAC subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	January 28, 2019	February 8, 2019	$	0.5250
March 31, 2019	April 29, 2019	May 10, 2019	0.5250
June 30, 2019	July 29, 2019	August 9, 2019	0.5250
September 30, 2019	October 28, 2019	November 8, 2019	0.5250

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

9 Months Ended

Sep. 30, 2019

Environmental Exit Costs by Cost



	September 30, 2019		December 31, 2018
Current	$	46	$	42
Non-current	276		295
Total environmental liabilities	$	322	$	337

Right Of Way [Member]

Schedule of Rent Expense [Table Text Block]



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
ROW expense	$	5	$	5	$	17	$	18

Revenue (Tables)

9 Months Ended

Sep. 30, 2019

Revenue [Abstract]

Contract with Customer, Asset and Liability [Table Text Block]

The balances of Sunoco LP’s contract assets as of September 30, 2019 and December 31, 2018 were as follows:



	September 30, 2019		December 31, 2018
Contract balances:
Contract asset	$	102	$	75
Accounts receivable from contracts with customers	403		348

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



	Years Ending December 31,
	2019 (remainder)		2020		2021		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2019	$	1,716	$	5,544	$	4,812	$	29,062	$	41,134

Lease Accounting (Tables)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

The weighted average remaining lease terms and weighted average discount rates as of September 30, 2019 were as follows:



	September 30, 2019
Weighted-average remaining lease term (years):
Operating leases	22
Finance leases	6
Weighted-average discount rate (%):
Operating leases	5	%
Finance leases	5	%

Maturities of lease liabilities as of September 30, 2019 are as follows:



	Operating Leases		Finance Leases		Total
2019 (remainder)	$	27	$	2	$	29
2020	96		10		106
2021	87		10		97
2022	75		10		85
2023	70		9		79
Thereafter	1,170		10		1,180
Total lease payments	1,525		51		1,576
Less: present value discount	660		6		666
Present value of lease liabilities	$	865	$	45	$	910

Schedule of additional lease information [Table Text Block]

Cash flows and non-cash activity related to leases for the nine months ended September 30, 2019 were as follows:



	Nine Months Ended September 30, 2019
Operating cash flows from operating leases	$	(78	)
Lease assets obtained in exchange for new finance lease liabilities	37
Lease assets obtained in exchange for new operating lease liabilities	36

Lessor, Operating Lease, Payments to be Received, Maturity [Table Text Block]

Future minimum operating lease payments receivable as of September 30, 2019 are as follows:



	Lease Receivables
2019 (remainder)	$	25
2020	85
2021	69
2022	56
2023	4
Thereafter	7
Total undiscounted cash flows	$	246

Schedule of Property Subject to or Available for Operating Lease [Table Text Block]

The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of September 30, 2019 were as follows:



	September 30, 2019
Operating leases:
Lease right-of-use assets, net	$	850
Operating lease current liabilities	57
Accrued and other current liabilities	1
Non-current operating lease liabilities	807
Finance leases:
Property, plant and equipment, net	$	2
Lease right-of-use assets, net	39
Accrued and other current liabilities	1
Current maturities of long-term debt	7
Long-term debt, less current maturities	35
Other non-current liabilities	2

Lease, Cost [Table Text Block]

The components of lease expense for the three and nine months ended September 30, 2019 were as follows:



	Income Statement Location	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease costs:
Operating lease cost	Cost of goods sold	$	7	$	23
Operating lease cost	Operating expenses	18		54
Operating lease cost	Selling, general and administrative	3		10
Total operating lease costs		28		87
Finance lease costs:
Amortization of lease assets	Depreciation, depletion and amortization	2		4
Interest on lease liabilities	Interest expense, net of capitalized interest	1		1
Total finance lease costs		3		5
Short-term lease cost	Operating expenses	10		33
Variable lease cost	Operating expenses	3		11
Lease costs, gross		44		136
Less: Sublease income	Other revenue	14		37
Lease costs, net		$	30	$	99

Derivative Assets And Liabilities (Tables)

9 Months Ended

Sep. 30, 2019

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:



	September 30, 2019			December 31, 2018
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX ⁽¹⁾	20,563		2019-2024	16,845		2019-2020
Fixed Swaps/Futures	1,723		2019-2020	468		2019
Options – Puts	—		—	10,000		2019
Power (Megawatt):
Forwards	2,847,350		2019-2029	3,141,520		2019
Futures	222,440		2019-2020	56,656		2019-2021
Options – Puts	515,317		2019-2020	18,400		2019
Options – Calls	(756,153	)	2019-2021	284,800		2019
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(23,653	)	2019-2022	(30,228	)	2019-2021
Swing Swaps IFERC	22,365		2019-2020	54,158		2019-2020
Fixed Swaps/Futures	2,323		2019-2021	(1,068	)	2019-2021
Forward Physical Contracts	(29,492	)	2019-2021	(123,254	)	2019-2020
NGLs (MBbls) – Forwards/Swaps	(9,687	)	2019-2021	(2,135	)	2019
Refined Products (MBbls) – Futures	(906	)	2019-2021	(1,403	)	2019
Crude (MBbls) – Forwards/Swaps	9,510		2019-2020	20,888		2019
Corn (thousand bushels)	(1,760	)	2019	(1,920	)	2019
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(31,703	)	2019-2020	(17,445	)	2019
Fixed Swaps/Futures	(31,703	)	2019-2020	(17,445	)	2019
Hedged Item – Inventory	31,703		2019-2020	17,445		2019

⁽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, 2019		December 31, 2018
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.56% and receive a floating rate	$	—	$	400
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		400
July 2022⁽²⁾	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	400		—
March 2019	Pay a floating rate and receive a fixed rate of 1.42%	—		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, 2019		December 31, 2018		September 30, 2019			December 31, 2018
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	16	$	—	$	—		$	(13	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	543		402		(520		)	(397		)
Commodity derivatives	120		158		(77		)	(173		)
Interest rate derivatives	—		—		(528		)	(163		)
	663		560		(1,125		)	(733		)
Total derivatives	$	679	$	560	$	(1,125	)	$	(746	)

Derivatives, Offsetting Fair Value Amounts [Table Text Block]



		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	September 30, 2019			December 31, 2018			September 30, 2019			December 31, 2018
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(528	)	$	(163	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	120			158			(77		)	(173		)
Broker cleared derivative contracts	Other current assets (liabilities)	559			402			(520		)	(410		)
Total gross derivatives		679			560			(1,125		)	(746		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(64		)	(47		)	64			47
Counterparty netting	Other current assets (liabilities)	(519		)	(397		)	519			397
Total net derivatives		$	96		$	116		$	(542	)	$	(302	)

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [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,
		2019		2018		2019		2018
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	—	$	—	$	—	$	9

Derivatives Not Designated as Hedging Instruments [Table Text Block]



	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,					Nine Months Ended September 30,
		2019			2018		2019			2018
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	3		$	3	$	15		$	36
Commodity derivatives – Non-trading	Cost of products sold	21			21		(53		)	(345		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(175		)	45		(371		)	117
Total		$	(151	)	$	69	$	(409	)	$	(192	)

- 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 Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2019

The following table summarizes the revenues from related companies on our consolidated statements of operations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Revenues from related companies	$	129	$	103	$	374	$	325

The following table summarizes the accounts receivable from related companies on our consolidated balance sheets:



	September 30, 2019		December 31, 2018
Accounts receivable from related companies:
FGT	$	51	$	25
Phillips 66	36		42
Traverse	25		—
Other	54		44
Total accounts receivable from related companies	$	166	$	111

Reportable Segments (Tables)

9 Months Ended

Sep. 30, 2019

Operating Segments [Member]

Financial Information By Segment



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	235		$	221		$	777		$	621
Interstate transportation and storage	442			459			1,358			1,200
Midstream	411			434			1,205			1,225
NGL and refined products transportation and services	667			498			1,923			1,410
Crude oil transportation and services	700			682			2,257			1,694
Investment in Sunoco LP	192			208			497			457
Investment in USAC	104			90			310			185
All other	35			(15		)	80			49
Adjusted EBITDA (consolidated)	2,786			2,577			8,407			6,841
Depreciation, depletion and amortization	(784		)	(750		)	(2,343		)	(2,109		)
Interest expense, net of interest capitalized	(579		)	(535		)	(1,747		)	(1,511		)
Impairment losses	(12		)	—			(62		)	—
Gains (losses) on interest rate derivatives	(175		)	45			(371		)	117
Non-cash compensation expense	(27		)	(27		)	(85		)	(82		)
Unrealized gains (losses) on commodity risk management activities	64			97			90			(255		)
Losses on extinguishments of debt	—			—			(18		)	(106		)
Inventory valuation adjustments	(26		)	(7		)	71			50
Adjusted EBITDA related to unconsolidated affiliates	(161		)	(179		)	(470		)	(503		)
Equity in earnings of unconsolidated affiliates	82			87			224			258
Adjusted EBITDA related to discontinued operations	—			—			—			25
Other, net	47			33			67			59
Income from continuing operations before income tax expense	1,215			1,341			3,763			2,784
Income tax (expense) benefit from continuing operations	(54		)	52			(214		)	(6		)
Income from continuing operations	1,161			1,393			3,549			2,778
Loss from discontinued operations, net of income taxes	—			(2		)	—			(265		)
Net income	$	1,161		$	1,391		$	3,549		$	2,513

Revenue, Segment Benchmark [Member]

Financial Information By Segment

The following tables present financial information by segment:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	675		$	846		$	2,115		$	2,424
Intersegment revenues	89			76			270			186
	764			922			2,385			2,610
Interstate transportation and storage:
Revenues from external customers	475			440			1,454			1,174
Intersegment revenues	4			5			16			13
	479			445			1,470			1,187
Midstream:
Revenues from external customers	704			537			1,704			1,571
Intersegment revenues	876			1,716			2,792			4,170
	1,580			2,253			4,496			5,741
NGL and refined products transportation and services:
Revenues from external customers	2,271			2,845			7,340			7,467
Intersegment revenues	607			218			1,181			710
	2,878			3,063			8,521			8,177
Crude oil transportation and services:
Revenues from external customers	4,453			4,422			13,685			12,942
Intersegment revenues	—			16			—			44
	4,453			4,438			13,685			12,986
Investment in Sunoco LP:
Revenues from external customers	4,328			4,760			12,494			13,114
Intersegment revenues	3			1			4			3
	4,331			4,761			12,498			13,117
Investment in USAC:
Revenues from external customers	169			166			505			331
Intersegment revenues	6			3			15			5
	175			169			520			336
All other:
Revenues from external customers	420			498			1,196			1,491
Intersegment revenues	21			27			80			108
	441			525			1,276			1,599
Eliminations	(1,606		)	(2,062		)	(4,358		)	(5,239		)
Total revenues	$	13,495		$	14,514		$	40,493		$	40,514

Operations And Organization Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
	Dec. 31, 2018 USD ($) shares	Sep. 30, 2018 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Jan. 01, 2019 USD ($)
Goodwill, Impairment Loss \| $		$ 0	$ 12	$ 0
Lease, Right of Use Asset, Net \| $	$ 0		889
Lease right-of-use assets, net \| $					$ 889
Operating Lease, Liability \| $			$ 865		888
ETE Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.28
ETE Merger [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%
ETE Merger [Member] \| Lake Charles LNG [Member]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	100.00%
ETE Merger [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] \| Sunoco GP [Member]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	100.00%
ETE Merger [Member] \| Sunoco LP [Member]
Sale of Stock, Number of Shares Issued in Transaction	2,263,158
IDRs [Member] \| ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction	1,168,205,710
General Partner \| ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction	18,448,341
ETO [Member] \| ETE Merger [Member] \| Lake Charles LNG [Member]
Sale of Stock, Number of Shares Issued in Transaction	37,557,815
ETO [Member] \| ETE Merger [Member] \| USAC [Member]
Sale of Stock, Number of Shares Issued in Transaction	16,134,903
ETO [Member] \| ETE Merger [Member] \| Sunoco GP [Member]
Sale of Stock, Number of Shares Issued in Transaction	42,812,389
ETO [Member] \| ETE Merger [Member] \| Sunoco LP [Member]
Sale of Stock, Number of Shares Issued in Transaction	2,874,275
Accounting Standards Update 2016-02 [Member]
Lease, Right of Use Asset, Net \| $					888
Lease right-of-use assets, net \| $					$ 889

Operations And Organization Accounting Change (Details) - USD ($) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018	Jan. 01, 2019	Dec. 31, 2018
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Lease right-of-use assets, net							$ 889
Current maturities of long-term debt	$ 14				$ 14		2,656	$ 2,655
Cost of products sold	9,890	$ 11,093			29,607	$ 31,681
Operating Income (Loss)	1,830	1,703			5,576	3,929
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	1,215	1,341			3,763	2,784
Net income	1,161	1,391	$ 633	$ 489	3,549	2,513
Less: Net income attributable to noncontrolling interests	317	1,008			931	1,412
Comprehensive income	1,154	1,395			3,551	2,520
Inventory valuation adjustments	26	7			(71)	(50)
Increase (Decrease) in Operating Capital					(247)	423
Other current assets	342				342			350
Property, plant and equipment, net	69,169				69,169		66,962	66,963
Lease, Right of Use Asset, Net	889				889			0
Intangible assets, net	5,781				5,781			6,000
Other non-current assets, net	1,089				1,089			1,006
Other non-current liabilities	1,138				1,138		1,172	1,184
Noncontrolling interests	11,124				11,124			10,291
Operating expenses	806	784			2,406	2,280
Depreciation, depletion and amortization	784	750			2,343	2,109
Operating Lease, Liability	865				865		888
Non-current operating lease liabilities	807				807		823	0
Long-term debt, less current maturities	46,840				46,840		43,379	43,373
Operating lease current liabilities	57				57		71	0
Accrued and other current liabilities	3,234				3,234		2,917	$ 2,918
Noncontrolling Interest
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net income			$ 278	$ 126
NGL sales
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,723	2,870			6,121	7,461
Crude sales
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	3,971	3,844			11,842	11,344
Gathering, transportation and other fees
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	2,466	1,781			6,768	4,878
Natural gas sales
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	822	1,026			2,549	3,112
Other
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 202	$ 216			$ 699	$ 739
Accounting Standards Update 2016-02 [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Lease right-of-use assets, net							889
Current maturities of long-term debt							1
Property, plant and equipment, net							(1)
Lease, Right of Use Asset, Net							888
Other non-current liabilities							(12)
Non-current operating lease liabilities							823
Long-term debt, less current maturities							6
Operating lease current liabilities							71
Accrued and other current liabilities							$ (1)

Acquisitions Narrative (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended			9 Months Ended
Acquisitions Narrative (Details) - USD ($) $ in Millions	Jan. 22, 2018	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Impairment losses		$ 12		$ 0	$ 62	$ 0
Revenues		13,495		14,514	40,493	40,514
Sunoco LP [Member] \| ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction			2,263,158
Sunoco GP [Member] \| ETE Merger [Member]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest			100.00%
USAC [Member] \| ETE Merger [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%
Lake Charles LNG [Member] \| ETE Merger [Member]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest			100.00%
Energy Transfer LNG Export LLC, ET Crude Oil Terminals LLC, & ETC Illinois LLC [Member] \| ETE Merger [Member]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest			60.00%
7-Eleven [Member]
Revenues	$ 199
Trade Receivables Held-for-sale, Reconciliation to Cash Flow, Period Increase (Decrease)		$ 1,000		$ 1,000	$ 2,900	$ 2,600
IDRs [Member] \| ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction			1,168,205,710

Acquisitions Discontinued Operations - Income Statement Data (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
REVENUES		$ 0		$ 349
Cost of products sold		0		305
Operating expenses		0		61
Selling, general and administrative		0		7
Total costs and expenses		0		373
OPERATING LOSS		0		(24)
Interest expense, net		0		(2)
Loss on extinguishment of debt and other		0		(20)
Other, net		0		(61)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE		0		(107)
Income tax expense		2		158
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$ 0	(2)	$ 0	(265)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ET		0		(10)
Disposal Group, Including Discontinued Operation, Depreciation and Amortization		0		0
Goodwill, Impairment Loss		$ 0	$ 12	$ 0

Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Supplemental Cash Flow Elements [Abstract]
Accounts receivable	$ (353)	$ 155
Accounts receivable from related companies	(36)	64
Inventories	(66)	78
Other current assets	14	(19)
Other non-current assets, net	(127)	(25)
Accounts payable	25	(234)
Accounts payable to related companies	(37)	(110)
Accrued and other current liabilities	129	422
Other non-current liabilities	(103)	24
Derivative assets and liabilities, net	307	68
Net change in operating assets and liabilities, net of effects of acquisitions	$ 247	$ (423)

Cash And Cash Equivalents Non-Cash Activities (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures			$ 1,202	$ 1,059
Losses from subsidiary common unit transactions			0	(125)
Right-of-Use Assets Obtained in Exchange for Liabilities			73	0
Lease assets obtained in exchange for new lease liabilities			36
Stock Issued During Period, Value, Dividend Reinvestment Plan			100
Distributions reinvested	$ 0	$ 0		0
Stock Issued During Period, Value, Conversion of Units	0
Limited Partner [Member]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Distributions reinvested	(57)	$ (58)
Stock Issued During Period, Value, Conversion of Units	$ 589		$ 0	$ 589

Inventories Table - Inventory Balances (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Inventory, Net [Abstract]
Other Inventory, Supplies, Gross	$ 404	$ 338
Natural gas, NGLs, and refined products	900	833
Energy Related Inventory, Crude Oil, Products and Merchandise	510	506
Inventory, Net	$ 1,814	$ 1,677

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Fair Value Measurements [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	$ 0
Debt obligations, fair value	50,790	$ 45,060
Long-term Debt	$ 46,850	$ 46,030

Fair Value Measurements Table - Fair Value of Financial Assets and Liabilities (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Price Risk Derivative Assets, at Fair Value	$ 679	$ 560
Other Assets, Fair Value Disclosure	29	26
Assets, Fair Value Disclosure	708	586
Interest Rate Derivative Liabilities, at Fair Value	(528)	(163)
Price Risk Derivative Liabilities, at Fair Value	(597)	(583)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(1,125)	(746)
Level 1
Price Risk Derivative Assets, at Fair Value	648	448
Other Assets, Fair Value Disclosure	19	17
Assets, Fair Value Disclosure	667	465
Interest Rate Derivative Liabilities, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	(572)	(480)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(572)	(480)
Level 2
Price Risk Derivative Assets, at Fair Value	31	112
Other Assets, Fair Value Disclosure	10	9
Assets, Fair Value Disclosure	41	121
Interest Rate Derivative Liabilities, at Fair Value	(528)	(163)
Price Risk Derivative Liabilities, at Fair Value	(25)	(103)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(553)	(266)
Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	27	42
Price Risk Derivative Liabilities, at Fair Value	(54)	(91)
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	5	52
Price Risk Derivative Liabilities, at Fair Value	(9)	(40)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	44	97
Price Risk Derivative Liabilities, at Fair Value	(29)	(88)
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	5	20
Price Risk Derivative Liabilities, at Fair Value	(2)	(21)
Commodity Derivatives - Natural Gas [Member] \| Level 1 \| Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	27	42
Price Risk Derivative Liabilities, at Fair Value	(54)	(91)
Commodity Derivatives - Natural Gas [Member] \| Level 1 \| Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	0	8
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] \| Level 1 \| Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	44	97
Price Risk Derivative Liabilities, at Fair Value	(29)	(88)
Commodity Derivatives - Natural Gas [Member] \| Level 1 \| Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] \| Level 2 \| Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] \| Level 2 \| Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	5	44
Price Risk Derivative Liabilities, at Fair Value	(9)	(40)
Commodity Derivatives - Natural Gas [Member] \| Level 2 \| Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] \| Level 2 \| Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	5	20
Price Risk Derivative Liabilities, at Fair Value	(2)	(21)
Commodity Derivatives - Refined Products [Member] \| Future [Member]
Price Risk Derivative Assets, at Fair Value	1	7
Price Risk Derivative Liabilities, at Fair Value	(3)	(15)
Commodity Derivatives - Refined Products [Member] \| Level 1 \| Future [Member]
Price Risk Derivative Assets, at Fair Value	1	7
Price Risk Derivative Liabilities, at Fair Value	(3)	(15)
Commodity Derivatives - Refined Products [Member] \| Level 2 \| Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Crude [Member] \| Future [Member]
Price Risk Derivative Assets, at Fair Value	43
Price Risk Derivative Liabilities, at Fair Value	(1)
Commodity Derivatives - Crude [Member] \| Forwards Swaps [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(61)
Commodity Derivatives - Crude [Member] \| Level 1 \| Future [Member]
Price Risk Derivative Assets, at Fair Value	43
Price Risk Derivative Liabilities, at Fair Value	(1)
Commodity Derivatives - Crude [Member] \| Level 1 \| Forwards Swaps [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(61)
Commodity Derivatives - Crude [Member] \| Level 2 \| Future [Member]
Price Risk Derivative Assets, at Fair Value	0
Price Risk Derivative Liabilities, at Fair Value	0
Commodity Derivatives - Crude [Member] \| Level 2 \| Forwards Swaps [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Power [Member] \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	21	48
Price Risk Derivative Liabilities, at Fair Value	(14)	(42)
Commodity Derivatives - Power [Member] \| Call Option [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value	1
Commodity Derivatives - Power [Member] \| Future [Member]
Price Risk Derivative Assets, at Fair Value	4	1
Price Risk Derivative Liabilities, at Fair Value	(5)	(1)
Commodity Derivatives - Power [Member] \| Level 1 \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] \| Level 1 \| Call Option [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value	(1)
Commodity Derivatives - Power [Member] \| Level 1 \| Future [Member]
Price Risk Derivative Assets, at Fair Value	4	1
Price Risk Derivative Liabilities, at Fair Value	(5)	(1)
Commodity Derivatives - Power [Member] \| Level 2 \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	21	48
Price Risk Derivative Liabilities, at Fair Value	(14)	(42)
Commodity Derivatives - Power [Member] \| Level 2 \| Call Option [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value	0
Commodity Derivatives - Power [Member] \| Level 2 \| Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	529	291
Price Risk Derivative Liabilities, at Fair Value	(479)	(224)
Commodity Derivatives - NGLs [Member] \| Level 1 \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	529	291
Price Risk Derivative Liabilities, at Fair Value	(479)	(224)
Commodity Derivatives - NGLs [Member] \| Level 2 \| Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	$ 0	$ 0

Net Income per Limited Partner Unit Table - Income Reconciliation (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items]
Income from continuing operations	$ 1,161	$ 1,393	$ 3,549	$ 2,778
Less: Net income attributable to redeemable noncontrolling interests	12	12	38	24
Less: Income from continuing operations attributable to noncontrolling interest	317	1,010	931	1,667
Income from continuing operations, net of noncontrolling interests	832	371	2,580	1,087
Less: Series A Convertible Preferred Unitholders’ interest in income	0	0	0	33
Less: General Partner’s interest in income	1	1	3	3
Net Income (Loss) from Continuing Operations Available to Common Shareholders, Basic	$ 831	$ 370	$ 2,577	$ 1,051
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	2,624.9	1,158.2	2,621.9	1,117.7
Basic income from continuing operations per Limited Partner unit	$ 0.32	$ 0.32	$ 0.98	$ 0.94
Basic income (loss) from discontinued operations per Limited Partner unit	$ 0	$ 0
Diluted Income from Continuing Operations per Limited Partner Unit:
Dilutive effect of distributions to Series A Convertible Preferred Unitholders	$ 0	$ 0	$ 0	$ 33
Diluted income from continuing operations available to Limited Partners	$ 831	$ 370	$ 2,577	$ 1,084
Dilutive effect of Series A Convertible Preferred Units	0.0	0.0	0.0	40.5
Dilutive effect of unvested unit awards	10.6	0.0	11.0	0.0
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	2,635.5	1,158.2	2,632.9	1,158.2
Diluted income from continuing operations per Limited Partner unit	$ 0.32	$ 0.32	$ 0.98	$ 0.94
Diluted income (loss) from discontinued operations per Limited Partner unit	$ 0	$ 0	$ 0	$ (0.01)

Debt Obligations Narrative (Details) - USD ($)	1 Months Ended			9 Months Ended
Debt Obligations Narrative (Details) - USD ($)	Jun. 30, 2019	Mar. 31, 2019	Jan. 31, 2019	Sep. 30, 2019	Sep. 30, 2018	Oct. 31, 2019
Debt Instrument [Line Items]
Document Period End Date				Sep. 30, 2019
Proceeds from Issuance of Senior Long-term Debt			$ 3,960,000,000
Repayments of Long-term Debt				$ 17,247,000,000	$ 23,323,000,000
Proceeds from Issuance of Long-term Debt				18,125,000,000	$ 22,126,000,000
Dakota Access, LLC [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Senior Long-term Debt				2,480,000,000
ET [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed		97.00%
ETO [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Senior Long-term Debt		$ 4,210,000,000
Panhandle [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.125%
Repayments of Senior Debt	$ 150,000,000
Sunoco LP [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				0.0600
Line of Credit Facility, Increase (Decrease), Net		600,000,000
USAC [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity				1,210,000,000
Line of Credit Facility, Maximum Borrowing Capacity				0.06875
Line of Credit Facility, Increase (Decrease), Net		$ 750,000,000
ETO Credit Facility due December 2022 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity				2,320,000,000
Long-term Line of Credit				2,610,000,000
Long-term Commercial Paper, Noncurrent				2,150,000,000
Letters of Credit Outstanding, Amount				$ 77,000,000
Line of Credit Facility, Interest Rate at Period End				2.77%
Line of Credit Facility, Maximum Borrowing Capacity				$ 5,000,000,000.00
ETO Credit Facility due December 2022 [Member] \| Accordion feature [Member]
Debt Instrument [Line Items]
Long-term Line of Credit				6,000,000,000.00
ETO 364-day Credit Facility due November 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit				0
Line of Credit Facility, Maximum Borrowing Capacity				1,000,000,000.00
ETE 7.5% Senior Notes due 2020 [Member] \| Parent Company [Member]
Debt Instrument [Line Items]
Senior Notes				$ 52,000,000
Debt Instrument, Interest Rate, Stated Percentage				7.50%
3.625% Senior Notes due 2022 [Member] \| Dakota Access, LLC [Member]
Debt Instrument [Line Items]
Senior Notes				$ 650,000,000
Debt Instrument, Interest Rate, Stated Percentage				3.625%
Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member] \| Sunoco LP [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity				$ 1,500,000,000
Long-term Line of Credit				154,000,000
Letters of Credit Outstanding, Amount				8,000,000
Line of Credit Facility, Remaining Borrowing Capacity				$ 1,340,000,000
Line of Credit Facility, Interest Rate at Period End				4.04%
USAC Credit Facility, due 2023 [Member] \| USA Compression Partners, LP [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity				$ 1,600,000,000
Line of Credit Facility, Maximum Borrowing Capacity				400,000,000
USAC Credit Facility, due 2023 [Member] \| USAC [Member]
Debt Instrument [Line Items]
Long-term Line of Credit				395,000,000
Letters of Credit Outstanding, Amount				0
Line of Credit Facility, Remaining Borrowing Capacity				$ 410,000,000
Line of Credit Facility, Interest Rate at Period End				4.73%
4.20% Senior Notes due 2023 [Member] \| ETO [Member]
Debt Instrument [Line Items]
Senior Notes				$ 750,000,000
Debt Instrument, Interest Rate, Stated Percentage				4.50%
4.95% Senior Notes due 2028 [Member] \| ETO [Member]
Debt Instrument [Line Items]
Senior Notes				$ 1,500,000,000
Debt Instrument, Interest Rate, Stated Percentage				5.25%
5.80% Senior Notes due 2038 [Member] \| ETO [Member]
Debt Instrument [Line Items]
Senior Notes				$ 1,750,000,000
Debt Instrument, Interest Rate, Stated Percentage				6.25%
3.90% Senior Notes due 2024 [Member] \| Dakota Access, LLC [Member]
Debt Instrument [Line Items]
Senior Notes				$ 1,000,000,000.00
Debt Instrument, Interest Rate, Stated Percentage				3.90%
4.625% Senior Notes due 2029 [Member] \| Dakota Access, LLC [Member]
Debt Instrument [Line Items]
Senior Notes				$ 850,000,000
Debt Instrument, Interest Rate, Stated Percentage				4.625%
4.25% Senior Notes due March 15, 2023 [Member] \| Parent Company [Member]
Debt Instrument [Line Items]
Senior Notes				$ 5,000,000
Debt Instrument, Interest Rate, Stated Percentage				4.25%
4.25% Senior Notes due March 15, 2023 [Member] \| ETO [Member]
Debt Instrument [Line Items]
Senior Notes				$ 995,000,000
Debt Instrument, Interest Rate, Stated Percentage				4.25%
5.875% Senior Notes due January 15, 2024 [Member] \| Parent Company [Member]
Debt Instrument [Line Items]
Senior Notes				$ 23,000,000
Debt Instrument, Interest Rate, Stated Percentage				5.875%
5.875% Senior Notes due January 15, 2024 [Member] \| ETO [Member]
Debt Instrument [Line Items]
Senior Notes				$ 1,130,000,000
Debt Instrument, Interest Rate, Stated Percentage				5.875%
5.5% Senior Notes due June 1, 2027 [Member] \| Parent Company [Member]
Debt Instrument [Line Items]
Senior Notes				$ 44,000,000
Debt Instrument, Interest Rate, Stated Percentage				5.50%
5.5% Senior Notes due June 1, 2027 [Member] \| ETO [Member]
Debt Instrument [Line Items]
Senior Notes				$ 956,000,000
Debt Instrument, Interest Rate, Stated Percentage				5.50%
7.50% Senior Notes Due 2020 [Member] \| ETO [Member]
Debt Instrument [Line Items]
Senior Notes				$ 1,140,000,000
Debt Instrument, Interest Rate, Stated Percentage				7.50%
9.7% Senior Notes, due March 15, 2019 [Member] \| ETO [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			9.70%
Repayments of Senior Debt			$ 400,000,000
9.0% Senior Notes due April 15, 2019 [Member] \| ETO [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			9.00%
Repayments of Senior Debt			$ 450,000,000
8.125% Senior Notes, due June 1, 2019 [Member] \| Panhandle [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			8.125%
Repayments of Senior Debt			$ 150,000,000
Subsequent Event [Member] \| ETO Term Loan [Member] \| ETO [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity						$ 2,000,000,000

Redeemable Noncontrolling Interest (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Apr. 30, 2018	Sep. 30, 2019	Dec. 31, 2018	Apr. 02, 2018
Redeemable noncontrolling interests		$ 499	$ 499
USAC [Member]
Redeemable noncontrolling interests		477
ETO [Member]
Redeemable noncontrolling interests		$ 22
Preferred Units [Member] \| USAC [Member]
Preferred Units, Issued				500,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 24.375
Shares Issued, Price Per Share				$ 1,000
Proceeds from Issuance of Preferred Limited Partners Units	$ 500

Equity Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended	9 Months Ended
	Jul. 31, 2019	Apr. 30, 2019	Dec. 31, 2018	Sep. 30, 2019	Sep. 30, 2018
Payments for Repurchase of Common Stock				$ 0.0	$ 24.0
Losses from subsidiary common unit transactions				0.0	$ (125.0)
Stock Repurchase Program, Remaining Authorized Repurchase Amount				936.0
Stock Issued During Period, Value, Dividend Reinvestment Plan				$ 100.0
Stock Issued During Period, Shares, Dividend Reinvestment Plan				7,100,000
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan				33,000,000
ET [Member]
Equity Distribution Agreements, Value of Units Available to be Issued				$ 1,000.0
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement				0.0
USAC [Member]
Stock Issued During Period, Value, Dividend Reinvestment Plan				$ 0.7
Stock Issued During Period, Shares, Dividend Reinvestment Plan				44,605
Class B Units [Member] \| USAC [Member]
Partners' Capital Account, Units, Converted	6,397,965
Series E Preferred Units [Member]
Preferred Stock, Shares Issued		32,000,000
Preferred Stock, Dividend Rate, Percentage		7.60%
Shares Issued, Price Per Share		$ 25
Preferred Units, Liquidation Spread, Percent		5.161%
Proceeds from Issuance of Preferred Limited Partners Units		$ 800.0
USAC [Member]
Stock Issued During Period, Shares, Conversion of Units	6,397,965
ETE Merger [Member] \| Sunoco LP [Member]
Sale of Stock, Number of Shares Issued in Transaction			2,263,158
ETE Merger [Member] \| USAC [Member]
Sale of Stock, Number of Shares Issued in Transaction			12,466,912
Equity Distribution Program [Member] \| Sunoco LP [Member]
Equity Distribution Agreements, Value of Units Available to be Issued				$ 295.0
Partners' Capital Account, Units, Sale of Units				0
Over-Allotment Option [Member] \| Series E Preferred Units [Member]
Preferred Stock, Shares Issued		4,000,000
Proceeds from Issuance of Preferred Limited Partners Units		$ 100.0
Series E Preferred Units [Member]
Preferred Units, Outstanding				32,000,000
Series D Preferred Units [Member]
Preferred Units, Outstanding				17,800,000
Series C Preferred Units [Member]
Preferred Units, Outstanding				18,000,000
Series B Preferred Units [Member]
Preferred Units, Outstanding				550,000
Series A Preferred Units [Member]
Preferred Units, Outstanding				950,000

Equity Table - Change In ETE Common Units (Details) - shares shares in Millions	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Class of Stock [Line Items]
Limited Partners' Capital Account, Units Outstanding	2,627.0	2,619.4
Stock Issued During Period, Shares, Dividend Reinvestment Plan	7.1
Partners' Capital Account, Unit-based Payment Arrangement, Number of Units	0.5

Equity Table - Quarterly Distributions of Available Cash (Details) - $ / shares

3 Months Ended

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.3050

USAC [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.5250

Sunoco LP [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.8255

Series A Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

31.25

Series B Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

33.125

Series C Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.4609

Series D Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.4766

Series E Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.4750

^[2]

$ 0.5806

^[2]

$ 0

[1]	ETOSeries A Preferred Unit and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.
[2]	ETO Series E Preferred Unit distributions related to the period ended June 30, 2019 represent a prorated initial distribution.

Equity Table - Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 10	$ 2
Foreign currency translation adjustment	(5)	(5)
Actuarial gain related to pensions and other postretirement benefits	(41)	(48)
AOCI attributable to equity method investments	(4)	9
Total AOCI, net of tax	$ (40)	$ (42)

Income Taxes (Details) $ in Millions	Sep. 30, 2019 USD ($)
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Reserves	$ 530

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)	1 Months Ended	3 Months Ended		9 Months Ended
	Feb. 28, 2018 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2019 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2019 USD ($)	Dec. 31, 2018 USD ($)
Document Period End Date				Sep. 30, 2019
Loss Contingency Accrual, at Carrying Value		$ 61,000,000		$ 61,000,000			$ 55,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed		0		0
Accrual for Environmental Loss Contingencies		$ 322,000,000		$ 322,000,000			$ 337,000,000
Civil penalties	$ 12,600,000
PES [Member]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest		7.40%
Notes Receivable, Related Parties						$ 75,000,000
Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number		5		5
Payments for Environmental Liabilities		$ 16,000,000	$ 17,000,000	$ 31,000,000	$ 32,000,000
Williams [Member]
Loss on Contract Termination for Default				410,000,000
Loss Contingency, Damages Sought, Value				10,000,000,000
Rover Pipeline LLC [Member]
Proposed Environmental Penalty				2,600,000
SPLP [Member]
Proposed Environmental Penalty				5,400,000
SPLP and Mid-Valley Pipeline [Member]
Proposed Environmental Penalty				1,000,000
ET [Member]
Loss Contingency, Damages Sought, Value				8,500,000
Legal Fees				$ 4,500,000
Sunoco [Member]
Site Contingency, Number of Sites Needing Remediation		38		38
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount		$ 319,000,000		$ 319,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount		536,000,000		536,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount		1,000,000		1,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount		$ 595,000,000		$ 595,000,000

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Table - Accrued Environmental Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Environmental Exit Cost [Line Items]
Document Period End Date	Sep. 30, 2019
Current	$ 46	$ 42
Non-current	276	295
Total environmental liabilities	$ 322	$ 337

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Schedule of Right of Way Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Contractual Right of Way, Expense	$ 5	$ 5	$ 17	$ 18

Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Revenue (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Contract with Customer, Liability, Revenue Recognized			$ (491)	$ (211)
Increase (Decrease) in Accounts Receivable			353	(155)
Contract with Customer, Liability	$ 349	$ 403	349	403	$ 392	$ 205
Sunoco LP [Member]
Contract with Customer, Asset, after Allowance for Credit Loss	102		102		75
Capitalized Contract Cost, Amortization	4	$ 4	12	$ 10
Receivables from Customers	$ 403		$ 403		$ 348

Revenue Revenue, Remaining Performance Obligation (Details) $ in Millions	Sep. 30, 2019 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-12-31
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 1,716
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-12-31
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	5,544
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-12-31
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	4,812
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-12-31
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	29,062
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 41,134

Revenue Revenue Contract Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Revenue from Contract Liabilities [Abstract]
Contract with Customer, Liability	$ 349	$ 403	$ 392	$ 205
Deferred Revenue, Additions	448	409
Contract with Customer, Liability, Revenue Recognized	$ (491)	$ (211)

Lease Accounting Leasee Accounting (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019	Sep. 30, 2018	Jan. 01, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Lease right-of-use assets, net				$ 889
Lessee, Operating Lease, Liability, 2019 (remainder)	$ 27	$ 27
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability		37
Net Cash Provided by (Used in) Financing Activities		$ (1,751)	$ (3,208)
Operating Lease, Weighted Average Remaining Lease Term	22 years	22 years
Finance Lease, Weighted Average Remaining Lease Term	6 years	6 years
Operating Lease, Cost	$ 28	$ 87
Finance Lease, Interest Expense	1	1
Lease assets obtained in exchange for new lease liabilities		36
Finance Lease, Liability, 2019 (remainder)	2	2
Lease Liabilities, 2019 (remainder)	29	29
Lessee, Operating Lease, 2020	96	96
Finance Lease, Liability, 2020	10	10
Lease Liabilities, 2020	106	106
Lessee, Operating Lease, 2021	87	87
Finance Lease, Liability, 2021	10	10
Lease Liabilities, 2021	97	97
Lessee, Operating Lease, 2022	75	75
Finance Lease, Liability, 2022	10	10
Lease Liabilities, 2022	85	85
Lessee, Operating Lease, 2023	70	70
Finance Lease, Liability, 2023	9	9
Lease Liabilities, 2023	79	79
Lessee, Operating Lease, Thereafter	1,170	1,170
Thereafter	7	7
Finance Lease, Liability, Thereafter	10	10
Lease Liabilities, Thereafter	1,180	1,180
Lessee, Operating Lease, Liability, Payments, Due	1,525	1,525
Finance Lease, Liability, Payment, Due	51	51
Lease Liabilities, Due	1,576	1,576
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	660	660
Finance Lease, Liability, Undiscounted Excess Amount	6	6
Lease Liability, Undiscounted Excess Amount	666	666
Operating Lease, Liability	865	865		888
Finance Lease, Liability	45	45
Lease, Liabilities	910	910
Lease, Cost, Gross	44	136
Lease, Cost	30	99
Operating lease current liabilities	57	57		71	$ 0
Accrued and other current liabilities	3,234	3,234		2,917	2,918
Non-current operating lease liabilities	807	807		823	0
Property, plant and equipment, net	69,169	69,169		66,962	66,963
Current maturities of long-term debt	14	14		2,656	2,655
Long-term debt, less current maturities	46,840	46,840		43,379	43,373
Other non-current liabilities	$ 1,138	$ 1,138		$ 1,172	$ 1,184
Minimum [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Renewal Term	1 year	1 year
Maximum [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Renewal Term	20 years	20 years
Equipment [Member] \| Minimum [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	5 years	5 years
Equipment [Member] \| Maximum [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	15 years	15 years
Real Estate [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	40 years	40 years
Operating Leases [Member]
Lessee, Lease, Description [Line Items]
Lease right-of-use assets, net	$ 850	$ 850
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		(78)
Operating lease current liabilities	57	57
Accrued and other current liabilities	1	1
Non-current operating lease liabilities	807	807
Finance Leases [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost	3	5
Accrued and other current liabilities	1	1
Property, plant and equipment, net	2	2
Finance Lease, Right-of-Use Asset	39	39
Current maturities of long-term debt	7	7
Long-term debt, less current maturities	35	35
Other non-current liabilities	$ 2	$ 2
ETO [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Discount Rate, Percent	5.00%	5.00%
Finance Lease, Weighted Average Discount Rate, Percent	5.00%	5.00%
Cost of Goods and Service Benchmark [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	$ 7	$ 23
Depreciation And Amortization [Member]
Lessee, Lease, Description [Line Items]
Finance Lease, Right-of-Use Asset, Amortization	2	4
Operating Expense [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	18	54
Short-term Lease, Cost	10	33
Variable Lease, Cost	3	11
Selling, General and Administrative Expenses [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	3	10
Other Revenue [Member]
Lessee, Lease, Description [Line Items]
Sublease Income	$ 14	$ 37

Lease Accounting Lessor Accounting (Details) $ in Millions	3 Months Ended	9 Months Ended
Lease Accounting Lessor Accounting (Details) $ in Millions	Sep. 30, 2019 USD ($)	Sep. 30, 2019 USD ($)
Leases [Abstract]
Lessor, Operating Lease, Term of Contract	5 years	5 years
2019 (remainder)	$ 25	$ 25
2020	85	85
2021	69	69
2022	56	56
2023	4	4
Thereafter	7	7
Total undiscounted cash flows	246	246
Rental Income, Nonoperating	$ 39	$ 111

Derivative Assets And Liabilities Table - Outstanding Commodity-Related Derivatives (Details)

Sep. 30, 2019

MMbtu

barrels

bbl

Megawatt

bushels

Dec. 31, 2018

MMbtu

barrels

bbl

Megawatt

bushels

Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Short [Member]

Notional Volume | bushels

(1,760)

Natural Gas Liquids [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Short [Member]

Notional Volume | bbl

(9,687)

(2,135)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Short [Member]

Notional Volume

(23,653)

(30,228)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Long [Member]

Notional Volume

(22,365)

(54,158)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Short [Member]

Notional Volume

(1,068)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Long [Member]

Notional Volume

(2,323)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Short [Member]

Notional Volume

(29,492)

(123,254)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Long [Member]

Notional Volume

^[1]

(20,563)

(16,845)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Long [Member]

Notional Volume

(1,723)

(468)

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Long [Member]

Notional Volume

Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member] | Long [Member]

Notional Volume

(10,000)

Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Short [Member]

Notional Volume

(31,703)

(17,445)

Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Short [Member]

Notional Volume

(31,703)

(17,445)

Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | Long [Member]

Notional Volume

(31,703)

(17,445)

Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Long [Member]

Notional Volume | Megawatt

(515,317)

Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Call Option [Member] | Short [Member]

Notional Volume | Megawatt

(756,153)

Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Call Option [Member] | Long [Member]

Notional Volume | Megawatt

(284,800)

Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forwards Swaps [Member] | Long [Member]

Notional Volume | Megawatt

(2,847,350)

(3,141,520)

Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Long [Member]

Notional Volume | Megawatt

(222,440)

(56,656)

Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member] | Long [Member]

Notional Volume | Megawatt

(18,400)

Crude Oil [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Long [Member]

Notional Volume | bbl

(9,510)

(20,888)

Refined product sales | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Short [Member]

Notional Volume | barrels

(906)

(1,403)

Corn [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Short [Member]

Notional Volume | bushels

(1,920)

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

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

9 Months Ended

Sep. 30, 2019

Dec. 31, 2018

March 2019 [Member]

Notional Amount

$ 0

$ 300

Type

^[1]

Pay a floating rate and receive a fixed rate of 1.42%

July 2020 [Member]

Notional Amount

$ 400

^[2]

400

Type

^[1],[2]

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

July 2021 [Member]

Notional Amount

$ 400

^[2]

400

Type

^[1],[2]

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

July 2022 [Member]

Notional Amount

$ 400

^[2]

Type

^[1],[2]

Forward-starting to pay a fixed rate of 3.80% and receive a floating rate

July 2019 [Member]

Notional Amount

$ 0

^[2]

$ 400

Type

^[1],[2]

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

[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.

Derivative Assets And Liabilities Table - Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Total derivatives assets	$ 679	$ 560
Total derivatives liabilities	(1,125)	(746)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	663	560
Total derivatives liabilities	(1,125)	(733)
Fair Value, Recurring [Member]
Price Risk Derivative Liabilities, at Fair Value	597	583
Forward Physical Swaps [Member] \| Fair Value, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Liabilities, at Fair Value	2	21
Level 1 \| Fair Value, Recurring [Member]
Price Risk Derivative Liabilities, at Fair Value	572	480
Level 1 \| Forward Physical Swaps [Member] \| Fair Value, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Liabilities, at Fair Value	0	0
Level 2 \| Fair Value, Recurring [Member]
Price Risk Derivative Liabilities, at Fair Value	25	103
Level 2 \| Forward Physical Swaps [Member] \| Fair Value, Recurring [Member] \| Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Liabilities, at Fair Value	2	21
Commodity Derivatives [Member] \| Not Designated as Hedging Instrument [Member]
Total derivatives assets	120	158
Total derivatives liabilities	(77)	(173)
Commodity Derivatives (Margin Deposits) [Member] \| Designated as Hedging Instrument [Member]
Total derivatives assets	16	0
Total derivatives liabilities	0	(13)
Commodity Derivatives (Margin Deposits) [Member] \| Not Designated as Hedging Instrument [Member]
Total derivatives assets	543	402
Total derivatives liabilities	(520)	(397)
Interest Rate Derivatives [Member] \| Not Designated as Hedging Instrument [Member]
Total derivatives assets	0	0
Total derivatives liabilities	$ (528)	$ (163)

Derivative Assets And Liabilities Table - Gross FV and Netting Offset (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 679	$ 560
Derivative Liability, Fair Value, Gross Liability	(1,125)	(746)
Counterparty netting	(64)	(47)
Counterparty netting	64	47
Payments on margin deposit	(519)	(397)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	519	397
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	96	116
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	542	302
Without offsetting agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(528)	(163)
OTC Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	120	158
Derivative Liability, Fair Value, Gross Liability	(77)	(173)
Broker cleared derivative contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	559	402
Derivative Liability, Fair Value, Gross Liability	$ (520)	$ (410)

Derivative Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Amount of Gain (Loss) Recognized (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (151)	$ 69	$ (409)	$ (192)
Gains (losses) on interest rate derivatives	(175)	45	(371)	117
Commodity Derivatives [Member]
Gain (Loss) on Components Excluded from Assessment of Price Risk Hedge Effectiveness	0	0	0	9
Amount of Gain/(Loss) Recognized in Income on Derivatives	21	21	(53)	(345)
Commodity Derivatives - Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 3	$ 3	$ 15	$ 36

Related Party Transactions Related Party Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Related Party Transaction [Line Items]
Contract with Customer, Liability, Revenue Recognized			$ (491)	$ (211)
Accounts payable to related companies	$ 32		32		$ 59
Revenue from Related Parties	129	$ 103	374	$ 325
Accounts Receivable, Related Parties, Current	166		166		111
FGT [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	51		51		25
Phillips 66 Company [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	36		36		42
Traverse [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	25		25		0
Other Related Parties [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	$ 54		$ 54		$ 44

Reportable Segments Table - Revenues (External and Intersegment) by Investments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenues	$ 13,495	$ 14,514	$ 40,493	$ 40,514
Intrastate Transportation And Storage [Member]
Revenues	764	922	2,385	2,610
Investment In Sunoco LP [Member]
Revenues	4,331	4,761	12,498	13,117
Investment In USAC [Member]
Revenues	175	169	520	336
Interstate Transportation and Storage [Member]
Revenues	479	445	1,470	1,187
Midstream [Member]
Revenues	1,580	2,253	4,496	5,741
NGL and refined products transportation and services [Member]
Revenues	2,878	3,063	8,521	8,177
Crude oil transportation and services [Member]
Revenues	4,453	4,438	13,685	12,986
Other Segments [Member]
Revenues	441	525	1,276	1,599
Intersegment Eliminations [Member]
Revenues	(1,606)	(2,062)	(4,358)	(5,239)
Intersegment [Member] \| Intrastate Transportation And Storage [Member]
Revenues	89	76	270	186
Intersegment [Member] \| Investment In Sunoco LP [Member]
Revenues	3	1	4	3
Intersegment [Member] \| Investment In USAC [Member]
Revenues	6	3	15	5
Intersegment [Member] \| Interstate Transportation and Storage [Member]
Revenues	4	5	16	13
Intersegment [Member] \| Midstream [Member]
Revenues	876	1,716	2,792	4,170
Intersegment [Member] \| NGL and refined products transportation and services [Member]
Revenues	607	218	1,181	710
Intersegment [Member] \| Crude oil transportation and services [Member]
Revenues	0	16	0	44
Intersegment [Member] \| Other Segments [Member]
Revenues	21	27	80	108
External Customers [Member] \| Intrastate Transportation And Storage [Member]
Revenues	675	846	2,115	2,424
External Customers [Member] \| Investment In Sunoco LP [Member]
Revenues	4,328	4,760	12,494	13,114
External Customers [Member] \| Investment In USAC [Member]
Revenues	169	166	505	331
External Customers [Member] \| Interstate Transportation and Storage [Member]
Revenues	475	440	1,454	1,174
External Customers [Member] \| Midstream [Member]
Revenues	704	537	1,704	1,571
External Customers [Member] \| NGL and refined products transportation and services [Member]
Revenues	2,271	2,845	7,340	7,467
External Customers [Member] \| Crude oil transportation and services [Member]
Revenues	4,453	4,422	13,685	12,942
External Customers [Member] \| Other Segments [Member]
Revenues	$ 420	$ 498	$ 1,196	$ 1,491

Reportable Segments Table - Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018
Segment Reporting Information [Line Items]
Document Period End Date					Sep. 30, 2019
Segment Adjusted EBITDA	$ 2,786	$ 2,577			$ 8,407	$ 6,841
Depreciation, depletion and amortization	(784)	(750)			(2,343)	(2,109)
Interest expense, net	(579)	(535)			(1,747)	(1,511)
Impairment losses	(12)	0			(62)	0
Gains (losses) on interest rate derivatives	(175)	45			(371)	117
Non-cash compensation expense	(27)	(27)			(85)	(82)
Unrealized gains (losses) on commodity risk management activities	64	97			90	(255)
Losses on extinguishments of debt	0	0			(18)	(106)
Inventory valuation adjustments	(26)	(7)			71	50
Equity in earnings of unconsolidated affiliates	82	87			224	258
Adjusted EBITDA related to unconsolidated affiliates	(161)	(179)			(470)	(503)
Adjusted EBITDA attributable to discontinued operations	0	0			0	25
Other, net	(47)	(33)			(67)	(59)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	1,215	1,341			3,763	2,784
Income tax (benefit) expense from continuing operations	(54)	52			(214)	(6)
Income from continuing operations	1,161	1,393			3,549	2,778
Loss from discontinued operations, net of income taxes	0	(2)			0	(265)
Net income	1,161	1,391	$ 633	$ 489	3,549	2,513
Intrastate Transportation And Storage [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	235	221			777	621
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	192	208			497	457
Investment In USAC [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	104	90			310	185
Adjustments And Eliminations [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	35	(15)			80	49
Interstate Transportation and Storage [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	442	459			1,358	1,200
Midstream [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	411	434			1,205	1,225
NGL and refined products transportation and services [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	667	498			1,923	1,410
Crude oil transportation and services [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 700	$ 682			$ 2,257	$ 1,694