Energy Transfer Operating (ET+E) 10-K 19 Feb 21 2020 FY Annual report Financial data

Cover Page

Cover Page $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)shares
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Document Transition Report	false
Entity File Number	1-31219
Entity Registrant Name	ENERGY TRANSFER OPERATING, L.P.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	73-1493906
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
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding | shares	0
Entity Public Float | $	$ 0
Documents Incorporated by Reference	None
Amendment Flag	false
Entity Central Index Key	0001161154
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2020
ICFR Auditor Attestation Flag	false
7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Document Information [Line Items]
Title of 12(b) Security	7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETPprC
Security Exchange Name	NYSE
7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Document Information [Line Items]
Title of 12(b) Security	7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETPprD
Security Exchange Name	NYSE
7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Document Information [Line Items]
Title of 12(b) Security	7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETPprE
Security Exchange Name	NYSE

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Lease, Right of Use Asset, Net	$ 866
Operating Lease, Right-of-Use Asset	1,000	$ 964
Current assets:
Cash and cash equivalents	366	288
Accounts receivable, net	3,875	5,038
Accounts receivable from related companies	79	167
Inventories	1,739	1,532
Income taxes receivable	35	146
Derivative assets	9	23
Other current assets	222	291
Total current assets	6,325	7,485
Property, plant and equipment	93,620	89,294
Accumulated depreciation and depletion	(18,801)	(15,398)
PROPERTY, PLANT AND EQUIPMENT, net	74,819	73,896
Advances to and investments in unconsolidated affiliates	3,055	3,454
Other non-current assets, net	1,657	1,571
Long-term affiliate receivable	1,883	3,603
Intangible assets, net	5,746	6,154
Goodwill	2,391	5,167
Total assets	96,742	102,294
Current liabilities:
Accounts payable	2,809	4,119
Accounts payable to related companies	177	31
Derivative liabilities	238	147
Operating lease current liabilities	53	60
Accrued and other current liabilities	2,769	3,336
Current maturities of long-term debt	21	26
Total current liabilities	6,067	7,719
Long-term debt, less current maturities	51,345	50,904
Non-current derivative liabilities	237	273
Non-current operating lease liabilities	837	901
Deferred income taxes	3,392	3,171
Other non-current liabilities	1,152	1,162
Commitments and contingencies
Redeemable noncontrolling interests	762	739
Limited Partners:
Common Unitholders and Other	20,084	24,226
Accumulated other comprehensive income (loss)	6	(18)
Total partners’ capital	24,854	27,382
Noncontrolling interests	8,096	8,018
Total equity	32,950	37,425
Total liabilities and equity	96,742	102,294
Predecessor Equity [Member]
Limited Partners:
Total equity	0	2,025
Series A Preferred Units [Member]
Equity:
Preferred Units	958	958
Series B Preferred Units [Member]
Equity:
Preferred Units	556	556
Series C Preferred Units
Equity:
Preferred Units	440	440
Series D Preferred Units
Equity:
Preferred Units	434	434
Series E Preferred Units [Member]
Equity:
Preferred Units	786	786
Series F Preferred Units [Member]
Equity:
Preferred Units	496	0
Series G Preferred Units [Member]
Equity:
Preferred Units	$ 1,094	$ 0

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2020	Dec. 31, 2019
Series A Preferred Units [Member]
Preferred Units, Authorized	950,000	950,000
Preferred Units, Issued	950,000	950,000
Preferred Units, Outstanding	950,000	950,000
Series B Preferred Units [Member]
Preferred Units, Authorized	550,000	550,000
Preferred Units, Issued	550,000	550,000
Preferred Units, Outstanding	550,000	550,000
Series C Preferred Units
Preferred Units, Authorized	18,000,000	18,000,000
Preferred Units, Issued	18,000,000	18,000,000
Preferred Units, Outstanding	18,000,000	18,000,000
Series D Preferred Units
Preferred Units, Authorized	17,800,000	17,800,000
Preferred Units, Issued	17,800,000	17,800,000
Preferred Units, Outstanding	17,800,000	17,800,000
Series E Preferred Units [Member]
Preferred Units, Authorized	32,000,000	0
Preferred Units, Issued	32,000,000	0
Preferred Units, Outstanding	32,000,000	0
Series F Preferred Units [Member]
Preferred Units, Authorized	500,000	0
Preferred Units, Issued	500,000	0
Preferred Units, Outstanding	500,000	0
Series G Preferred Units [Member]
Preferred Units, Authorized	1,100,000	0
Preferred Units, Issued	1,100,000	0
Preferred Units, Outstanding	1,100,000	0

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
REVENUES:
Total revenues	$ 38,954	$ 54,213	$ 54,087
COSTS AND EXPENSES:
Cost of products sold	25,487	39,801	41,603
Operating expenses	3,218	3,294	3,089
Depreciation, depletion and amortization	3,669	3,136	2,843
Selling, general and administrative	701	686	664
Impairment losses	2,880	74	431
Total costs and expenses	35,955	46,991	48,630
OPERATING INCOME	2,999	7,222	5,457
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(2,323)	(2,262)	(1,709)
Equity in earnings of unconsolidated affiliates	119	302	344
Impairment of investments in unconsolidated affiliates	(129)	0	0
Losses on extinguishments of debt	(72)	(2)	(109)
Gains (losses) on interest rate derivatives	(203)	(241)	47
Other, net	159	295	69
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	550	5,314	4,099
Income tax expense from continuing operations	239	199	5
INCOME FROM CONTINUING OPERATIONS	311	5,115	4,094
Loss from discontinued operations, net of income taxes	0	0	(265)
NET INCOME	311	5,115	3,829
Less: Net income attributable to noncontrolling interests	410	1,051	715
Less: Net income attributable to redeemable noncontrolling interests	49	51	39
Less: Net income (loss) attributable to predecessor	(6)	3	(5)
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS	$ (142)	$ 4,010	$ 3,080

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net income	$ 311	$ 5,115	$ 3,829
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	5	11	(4)
Actuarial gain (loss) relating to pension and other postretirement benefits	21	24	(43)
Change in other comprehensive income from unconsolidated affiliates	(13)	(10)	4
Total other comprehensive income	82	31	(43)
Comprehensive income	393	5,146	3,786
Less: Comprehensive income attributable to noncontrolling interests	410	1,051	715
Less: Comprehensive income attributable to redeemable noncontrolling interests	49	51	39
Less: Comprehensive income (loss) attributable to predecessor	(6)	3	(5)
Comprehensive income (loss) attributable to partners	(60)	4,041	3,037
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax, Portion Attributable to Parent	$ 69	$ 6	$ 0

CONSOLIDATED STATEMENT OF EQUIT

CONSOLIDATED STATEMENT OF EQUITY - USD ($) $ in Millions	Total	Cumulative Effect, Period of Adoption, Adjustment	General Partner	General PartnerCumulative Effect, Period of Adoption, Adjustment	AOCI Attributable to Parent [Member]	AOCI Attributable to Parent [Member]Cumulative Effect, Period of Adoption, Adjustment	Noncontrolling Interest [Member]	Noncontrolling Interest [Member]Cumulative Effect, Period of Adoption, Adjustment	Predecessor Equity [Member]	Predecessor Equity [Member]Cumulative Effect, Period of Adoption, Adjustment	Preferred Units [Member]	Preferred Units [Member]Cumulative Effect, Period of Adoption, Adjustment	Common Unitholders and Other [Member]	Common Unitholders and Other [Member]Cumulative Effect, Period of Adoption, Adjustment
Balance at Dec. 31, 2017	$ 37,079		$ 244		$ 3		$ 5,882		$ 2,816		$ 1,491		$ 26,643
Increase (Decrease) in Unitholders' Equity
Distributions to partners	(4,556)		(1,080)		0		0		0		(100)		(3,376)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	1,167		0		0		891		276		0		0
Distributions to noncontrolling interest	(891)
Partnership units issued for cash	925		0		0		0		0		867		58
Capital contributions from noncontrolling interest	649		0		0		649		0		0		0
Deemed Distribution	402		0		0		58		497		0		37
Partners Capital Account, Acquisitions	0		(340)		0		1,474		(2,504)		0		1,370
Subsidiary units repurchased	300		0		0		0		300		0		0
Noncontrolling Interest, Increase from Business Combination	832		0		0		0		832		0		0
Other comprehensive loss, net of tax	(43)		0		(43)		0		0		0		0
Other, net	35		(17)		(2)		16		(12)		(3)		53
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	3,790		1,193		0		715		(5)		133		1,754
Net income	3,829
Balance at Dec. 31, 2018	36,788		0		(42)		7,903		0		2,388		26,539
Increase (Decrease) in Unitholders' Equity
Cumulative Effect of New Accounting Principle in Period of Adoption		$ (54)		$ 0		$ 0		$ 0		$ (54)		$ 0		$ 0
Distributions to partners	(6,284)		0		0		0		0		(197)		(6,087)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	1,401		0		0		1,399		2		0		0
Distributions to noncontrolling interest	(1,401)
Partnership units issued for cash	780		0		0		0		0		780		0
Capital contributions from noncontrolling interest	348		0		0		348		0		0		0
Sale of noncontrolling interest in subsidiary	93		0		0		93		0		0		0
Other comprehensive loss, net of tax	39		0		24		0		15		0		0
Other, net	(10)		0		0		22		1		(1)		(32)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	5,064		0		0		1,051		3		204		3,806
Net income	5,115
Balance at Dec. 31, 2019	37,425		0		(18)		8,018		2,025		3,174		24,226
Increase (Decrease) in Unitholders' Equity
Proceeds from Contributions from Parent	2,008		0		0		0		2,008		0		0
Distributions to partners	(5,265)		0		0		0		0		(315)		(4,950)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	1,336		0		0		1,311		25		0		0
Distributions to noncontrolling interest	(1,311)
Partnership units issued for cash	1,580		0		0		0		0		1,580		0
Capital contributions from noncontrolling interest	222		0		0		192		30		0		0
Other comprehensive loss, net of tax	44		0		46		36		(38)		0		0
Other, net	18		0		0		(37)		(10)		(4)		69
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	262		0		0		410		(6)		329		(471)
Net income	311
Balance at Dec. 31, 2020	32,950		0		6		8,096		0		4,764		20,084
Increase (Decrease) in Unitholders' Equity
Proceeds from Contributions from Parent	$ 0		$ 0		$ (22)		$ 788		$ (1,976)		$ 0		$ 1,210

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 311	$ 5,115	$ 3,829
Reconciliation of net income to net cash provided by operating activities:
Loss from discontinued operations	0	0	265
Depreciation, depletion and amortization	3,669	3,136	2,843
Deferred income taxes	212	221	(8)
Inventory valuation adjustments	82	(79)	85
Non-cash compensation expense	121	113	105
Impairment losses	2,880	74	431
Losses on extinguishment of debt	72	2	109
Impairment of investments in unconsolidated affiliates	129	0	0
Distributions on unvested awards	(9)	(9)	(33)
Equity in earnings of unconsolidated affiliates	(119)	(302)	(344)
Distributions from unconsolidated affiliates	220	290	328
Other non-cash	89	132	113
Net change in operating assets and liabilities, net of effects of acquisitions	212	(395)	62
Net cash provided by operating activities	7,869	8,298	7,559
INVESTING ACTIVITIES:
Cash received for sale of noncontrolling interest	0	93	0
Cash paid for all other acquisitions	0	(7)	(429)
Capital expenditures, excluding allowance for equity funds used during construction	(5,130)	(5,960)	(7,407)
Contributions in aid of construction costs	67	80	109
Contributions to unconsolidated affiliates	(38)	(523)	(26)
Distributions from unconsolidated affiliates in excess of cumulative earnings	186	98	69
Proceeds from the sale of assets	19	54	87
Other	3	18	16
Net cash used in investing activities	(4,899)	(6,397)	(6,902)
FINANCING ACTIVITIES:
Proceeds from borrowings	24,440	22,583	28,538
Repayments of debt	(24,081)	(18,881)	(27,297)
Proceeds from Related Party Debt	1,591	995
Cash received from (paid to) related company			(440)
Common units issued for cash	0	0	58
Preferred units issued for cash	1,580	780	867
Cash Inflow from Redeemable Noncontrolling Interest	0	0	465
Capital contributions from noncontrolling interests	192	348	649
Distributions to partners	5,265	6,284	4,556
Predecessor distributions to partners	0	0	(276)
Distributions to noncontrolling interest	(1,311)	(1,401)	(891)
Distributions to redeemable noncontrolling interests	(49)	(53)	(24)
Payments for Repurchase of Common Stock	0	0	(24)
Debt issuance costs	(59)	(117)	(162)
Other	(65)	(1)	(85)
Net cash used in financing activities	(2,892)	(2,031)	(3,308)
DISCONTINUED OPERATIONS:
Operating activities	0	0	(484)
Investing activities	0	0	3,207
Changes in cash included in current assets held for sale	0	0	11
Net increase in cash and cash equivalents of discontinued operations	0	0	2,734
Increase (decrease) in cash and cash equivalents	78	(130)	83
Cash and cash equivalents, beginning of period	288	418	335
Cash and cash equivalents, end of period	366	288	418
Predecessor proceeds from noncontrolling interest	30	0	0
Payments to Noncontrolling Interests	(25)	0	0
CDM Distribution and USAC Acquisition [Member]
INVESTING ACTIVITIES:
Proceeds from Divestiture of Interest in Joint Venture	0	0	711
PennTex [Member]
INVESTING ACTIVITIES:
Cash paid for all other acquisitions	0	250	0
Sunoco LP [Member]
Reconciliation of net income to net cash provided by operating activities:
Impairment losses		47
FINANCING ACTIVITIES:
Payments for Repurchase of Common Stock	$ 0	$ 0	$ (300)

Operations and Organization (No

Operations and Organization (Notes)	12 Months Ended
	Dec. 31, 2020
Operations And Organization [Abstract]
OPERATIONS AND ORGANIZATION	OPERATIONS AND BASIS OF PRESENTATION: The consolidated financial statements presented herein contain the results of Energy Transfer Operating, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETO”). ETO is a consolidated subsidiary of Energy Transfer LP. In December 2019, ET completed the acquisition of SemGroup. During the first and second quarters of 2020, ET contributed SemGroup and its former subsidiaries to ETO through sale and contribution transactions. The contribution transactions were accounted for as reorganizations of entities under common control; therefore, the contributed entities’ assets and liabilities were not adjusted as of the contribution date. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation beginning December 5, 2019 for SemGroup assets contributed (the date ET acquired SemGroup). Predecessor equity included in the consolidated financial statements represents the equity of contributed entities prior to the contribution transactions. 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, the former common unitholders (other than ET and its subsidiaries) received 1.28 common units of ET for each common unit of ETO they owned. 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; and • 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. The Energy Transfer Merger was a combination of entities under common control; therefore, Sunoco LP, Lake Charles LNG and USAC’s (see Note 3 for more information) assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation beginning January 1, 2018 of Sunoco LP and Lake Charles LNG and April 2, 2018 of USAC (the date ET acquired USAC, see Note 3). Predecessor equity included on the consolidated financial statements represents Sunoco LP, Lake Charles LNG and USAC’s equity prior to the Energy Transfer Merger. Following the closing of the Energy Transfer Merger, Energy Transfer Equity, L.P. changed its name to “Energy Transfer LP” and its common units began trading on the New York Stock Exchange under the “ET” ticker symbol on Friday, October 19, 2018. In addition, Energy Transfer Partners, L.P. changed its name to “Energy Transfer Operating, L.P.” For purposes of maintaining clarity, the following references are used herein: • References to “ETO” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer Operating, L.P. subsequent to the close of the Energy Transfer Merger; and • References to “ET” refer to the entity named Energy Transfer Equity, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer LP subsequent to the close of the Energy Transfer Merger. 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 • all other. The Partnership owns and operates intrastate natural gas pipeline systems and storage facilities that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States. The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales. The Partnership owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products. The Partnership owns a controlling interest in Sunoco LP which is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers, and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites. As of December 31, 2020, our interest in Sunoco LP consisted of 100% of the general partner and IDRs, as well as 28.5 million common units. The Partnership owns a controlling interest in USAC which provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. As of December 31, 2020, our interest in USAC consisted of 100% of the general partner and 46.1 million common units. Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity. The consolidated financial statements of the Partnership presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC.

Estimates, Significant Accounti

Estimates, Significant Accounting Policies and Balance Sheet Detials (Notes)	12 Months Ended
	Dec. 31, 2020
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Business Combination Disclosure	ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL: Change in Accounting Policy Effective January 1, 2020, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. Under the revised accounting policy, certain amounts of crude oil that are not available for sale have been reclassified from inventory to non-current assets. These crude oil barrels, which are owned by the Partnership’s crude oil acquisition and marketing business, include pipeline linefill and tank bottoms and are not considered to be available for sale because the volumes must be maintained in order to continue normal operation of the related pipelines or tanks and because there is no expectation of liquidation or sale of these volumes in the near term. Under the previous accounting policy, all crude oil barrels were recorded as inventory under the weighted average cost method. Under the revised accounting policy, barrels related to pipeline linefill and tank bottoms are accounted for as long-lived assets and reflected as non-current assets on the consolidated balance sheet. These crude oil barrels will be tested for impairment consistent with the Partnership’s existing accounting policy for impairments of long-lived assets. The Partnership’s management believes that the change in accounting policy is preferable as it more closely aligns the accounting policies across the consolidated entity, given that similar assets in the Partnership’s natural gas, NGLs and refined products businesses are accounted for as non-current assets. In addition, management believes that reflecting these crude oil barrels as non-current assets better represents the economic results of the Partnership’s crude oil acquisition and marketing business by reducing volatility resulting from market price adjustments to crude oil barrels that are not expected to be sold or liquidated in the near term. As a result of this change in accounting policy, the Partnership’s consolidated balance sheet for the prior period has been retrospectively adjusted as follows: December 31, 2019 As Originally Reported* Effect of Change As Adjusted Inventories $ 1,935 $ (403) $ 1,532 Total current assets 7,888 (403) 7,485 Other non-current assets, net 1,075 496 1,571 Total assets 102,201 93 102,294 Total partners’ capital 27,289 93 27,382 *Amounts reflect the retrospective consolidation of the SemGroup entities as discussed in Note 3. In addition, the Partnership’s consolidated statements of operations, comprehensive income and cash flows for prior periods have been retrospectively adjusted as follows: Year Ended December 31, 2019* 2018 As originally reported: Consolidated Statements of Operations and Comprehensive Income Cost of products sold $ 39,727 $ 41,658 Operating income 7,296 5,402 Income from continuing operations before income tax expense 5,388 4,044 Net income 5,189 3,774 Comprehensive income 5,220 3,731 Comprehensive income attributable to partners 4,115 2,982 Consolidated Statements of Cash Flows Net income 5,189 3,774 Net change in operating assets and liabilities (469) 117 Effect of change: Consolidated Statements of Operations and Comprehensive Income Cost of products sold 74 (55) Operating income (74) 55 Income from continuing operations before income tax expense (74) 55 Net income (74) 55 Comprehensive income (74) 55 Comprehensive income attributable to partners (74) 55 Consolidated Statements of Cash Flows Net income (74) 55 Net change in operating assets and liabilities 74 (55) As adjusted: Consolidated Statements of Operations and Comprehensive Income Cost of products sold 39,801 41,603 Operating income 7,222 5,457 Income from continuing operations before income tax expense 5,314 4,099 Net income 5,115 3,829 Comprehensive income 5,146 3,786 Comprehensive income attributable to partners 4,041 3,037 Consolidated Statements of Cash Flows Net income 5,115 3,829 Net change in operating assets and liabilities (395) 62 *Amounts reflect the retrospective consolidation of the SemGroup entities as discussed in Note 3. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates. Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs. Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2020 2019 2018 Accounts receivable $ 1,163 $ (473) $ 506 Accounts receivable from related companies (290) (17) 128 Inventories (271) (20) 237 Other current assets 189 107 7 Other non-current assets, net (7) (155) (119) Accounts payable (1,327) 148 (769) Accounts payable to related companies 517 (92) (206) Accrued and other current liabilities 161 23 365 Other non-current liabilities 8 (134) (34) Price risk management assets and liabilities, net 69 218 (53) Net change in operating assets and liabilities, net of effects of acquisitions $ 212 $ (395) $ 62 Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2020 2019 2018 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 604 $ 1,334 $ 1,030 Lease assets obtained in exchange for new lease liabilities 42 68 — Net gains (losses) from subsidiary common unit transactions — — (127) SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 2,086 $ 1,799 $ 1,537 Cash paid for income taxes (net of refunds) (64) 30 508 Accounts Receivable Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for credit losses on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Changes in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due. Inventories Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method. Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2020 and 2019, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $311 million and $229 million, respectively, and the inventory carrying value equaled or exceeded its replacement cost. For the years ended December 31, 2020, 2019 and 2018, the Partnership’s consolidated statements of operations did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. Inventories consisted of the following: December 31, 2020 2019 Natural gas, NGLs and refined products (1) $ 1,013 $ 833 Crude oil 287 251 Spare parts and other 439 448 Total inventories $ 1,739 $ 1,532 (1) Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of $82 million for the year ended December 31, 2020. We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations. Other Current Assets Other current assets consisted of the following: December 31, 2020 2019 Deposits paid to vendors $ 75 $ 95 Prepaid expenses and other 147 196 Total other current assets $ 222 $ 291 Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC-mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2020, the Partnership recognized a $58 million fixed asset impairment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. USAC recorded an $8 million impairment of compression equipment as a result of its evaluations of the future deployment of its idle fleet. In 2019, USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets. Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York. In 2018, USAC recognized a $9 million fixed asset impairment related to certain idle compressor assets. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds. Components and useful lives of property, plant and equipment were as follows: December 31, 2020 2019 Land and improvements $ 1,233 $ 1,232 Buildings and improvements (1 to 45 years) 4,204 2,631 Pipelines and equipment (5 to 83 years) 69,120 64,678 Product storage and related facilities and equipment (2 to 83 years) 6,393 5,898 Right of way (20 to 83 years) 5,091 4,851 Other (1 to 48 years) 1,808 1,509 Construction work-in-process 5,771 8,495 Property, plant and equipment, gross 93,620 89,294 Less: Accumulated depreciation and depletion (18,801) (15,398) Property, plant and equipment, net $ 74,819 $ 73,896 We recognized the following amounts for the periods presented: Years Ended December 31, 2020 2019 2018 Depreciation, depletion and amortization expense $ 3,266 $ 2,828 $ 2,522 Capitalized interest 189 166 294 Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. During the year ended December 31, 2020, the Partnership recorded an impairment of its investment in White Cliffs of $129 million due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition and related purchase price allocation in December 2019. Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2020 2019 Crude pipeline linefill and tank bottoms $ 517 $ 496 Regulatory assets 41 42 Pension assets 103 84 Deferred charges 188 178 Restricted funds 179 178 Other 629 593 Total other non-current assets, net $ 1,657 $ 1,571 Restricted funds includes an immaterial amount of restricted cash primarily held in our wholly-owned captive insurance companies. Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: December 31, 2020 December 31, 2019 Gross Carrying Accumulated Gross Carrying Accumulated Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 7,513 $ (2,117) $ 7,535 $ (1,743) Patents (10 years) 48 (40) 48 (35) Trade Names (20 years) 66 (35) 66 (31) Other (5 to 20 years) 19 (15) 19 (12) Total amortizable intangible assets 7,646 (2,207) 7,668 (1,821) Non-amortizable intangible assets: Trademarks 295 — 295 — Other 12 — 12 — Total non-amortizable intangible assets 307 — 307 — Total intangible assets $ 7,953 $ (2,207) $ 7,975 $ (1,821) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2020 2019 2018 Reported in depreciation, depletion and amortization expense $ 403 $ 308 $ 321 Estimated aggregate amortization of intangible assets for the next five years is as follows: Years Ending December 31: 2021 $ 393 2022 379 2023 363 2024 349 2025 335 We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. Sunoco LP performed impairment tests on its indefinite-lived intangible assets during the fourth quarter of 2018 and recognized a $30 million impairment charge on its contractual rights, included in other in the table above, primarily due to decreases in projected future revenues and cash flows from the date the intangible assets were originally recorded. Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Intrastate Interstate Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services Investment in Sunoco LP Investment in USAC All Other Total Balance, December 31, 2018 $ 10 $ 196 $ 492 $ 693 $ 1,167 $ 1,559 $ 619 $ 149 $ 4,885 Acquired — 42 — — 230 — — 35 307 Impaired — (12) (9) — — — — — (21) Other — — — — — (4) — — (4) Balance, December 31, 2019 10 226 483 693 1,397 1,555 619 184 5,167 Acquired — — — — — 9 — — 9 Impaired (10) (226) (483) — (1,279) — (619) (198) (2,815) Other — — — — (66) — — 96 30 Balance, December 31, 2020 $ — $ — $ — $ 693 $ 52 $ 1,564 $ — $ 82 $ 2,391 Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. The Partnership performed the interim impairment tests consistent with our approach for annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized goodwill impairments of $483 million related to our Ark-La-Tex and South Texas operations within the midstream segment, $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to contractually scheduled reductions in payments for the remainder of the contract term, and $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations. During the third quarter of 2020, the Partnership performed interim impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $1.28 billion related to our crude operations, $132 million related to our Energy Transfer Canada operations within the all other segment and $43 million related to our interstate operations primarily due to decreases in projected future cash flow as a result of the overall market demand decline. During the fourth quarter of 2020, the Partnership performed annual impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $10 million related to our intrastate operations, $11 million related to our PEI operations and $15 million related to our Natural Resources operations within the all other segment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. No other impairments of the Partnership’s goodwill were identified. During the third quarter of 2019, the Partnership recognized a goodwill impairment of $12 million related to the Southwest Gas operations within the interstate segment primarily due to decreases in projected future revenues and cash flows. During the fourth quarter of 2019, the Partnership recognized a goodwill impairment of $9 million related to our North Central operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows. During the fourth quarter of 2018, the Partnership recognized goodwill impairments of $378 million related to our Northeast operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. These changes in assumptions reflect delays in the construction of third-party takeaway capacity in the Northeast. The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. Management does not believe that any of the goodwill balances in its reporting units is currently at significant risk of impairment; however, of the $2.39 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2020, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test. Asset Retirement Obligations We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an ARO in the periods in which management can reasonably estimate the settlement dates. As of December 31, 2020 and 2019, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $270 million and $247 million, respectively. For the years ended December 31, 2020, 2019 and 2018 aggregate accretion expense related to AROs was $16 million, $5 million and $13 million, respectively. Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2020 and 2019, in most cases because the settlement dates were indeterminable. Although a number of onshore assets in our systems are subject to agreements or regulations that give rise to an ARO upon discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Our subsidiaries also have legal obligations for several other assets at previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, our subsidiaries are legally or contractually required to abandon in place or remove the asset. We believe we may have additional AROs related to pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP also has AROs related to the estimated future cost to remove underground storage tanks. Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely. As of December 31, 2020 and 2019, other non-current assets on the Partnership’s consolidated balance sheets included $34 million and $31 million, respectively, of funds that were legally restricted for the purpose of settling AROs. Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: December 31, 2020 2019 Interest payable $ 598 $ 576 Customer advances and deposits 161 123 Accrued capital expenditures 604 1,334 Accrued wages and benefits 109 217 Taxes payable other than income taxes 446 263 Exchanges payable 127 67 Other 724 756 Total accrued and other current liabilities $ 2,769 $ 3,336 Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may be required when customers exceed their credit limits or do not qualify for open credit. Redeemable Noncontrolling Interests Our redeemable noncontrolling interests relate to certain preferred unitholders of one of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in one of our consolidated subsidiaries that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable noncontrolling interests on our consolidated balance sheets. See Note 6 for further information. Environmental Remediation We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued. Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. 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 debt obligations as of December 31, 2020 was $56.13 billion and $51.37 billion, respectively. As of December 31, 2019, the aggregate fair value and carrying amount of our debt obligations was $54.66 billion and $50.93 billion, respectively. The fair value

Acquisitions, Divestitures and

Acquisitions, Divestitures and Related Transactions (Notes)	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
ACQUISITIONS AND DIVESTITURE	ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS: ET Contribution of SemGroup Assets to ETO As discussed in Note 1, former SemGroup subsidiaries were transferred from ET to ETO during the first and second quarters of 2020. The following table represents the fair value, as of December 5, 2019, of the SemGroup assets and liabilities transferred from ET to ETO: At December 5, 2019 Total current assets $ 794 Property, plant and equipment 3,891 Other non-current assets 617 Goodwill 295 Intangible assets 460 Total assets $ 6,057 Total current liabilities $ 629 Long-term debt, less current maturities (1) 2,576 Other non-current liabilities 197 Energy Transfer Canada Preferred shares 241 Total liabilities 3,643 Noncontrolling interest 822 Partners’ capital 1,592 Total liabilities and partners’ capital $ 6,057 (1) Long-term debt at December 5, 2019 includes SemGroup senior notes with an aggregate principal amount of $1.375 billion and SemGroup subsidiary debt of $593 million, all of which was redeemed in December 2019, subsequent to the close of the SemGroup Transaction. During 2020, the Partnership has recorded impairments on certain of the contributed SemGroup assets. Those impairments include a $244 million impairment of goodwill and a $129 million impairment of other non-current assets. ET Contribution of Assets to ETO Immediately prior to the closing of the Energy Transfer Merger discussed in Note 1, ET contributed the following to ETO: • 2,263,158 common units representing limited partner interests in Sunoco LP to ETO in exchange for 2,874,275 ETO common units; • 100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETO in exchange for 42,812,389 ETO common units; • 12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETO in exchange for 16,134,903 ETO common units; and • a 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC to ETO in exchange for 37,557,815 ETO common units. USAC Acquisition On April 2, 2018, ET acquired a controlling interest in USAC, a publicly traded partnership that provides compression services in the United States. Specifically, the Partnership acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC (“USAC GP”), the general partner of USAC, and (ii) 12,466,912 USAC common units representing limited partner interests in USAC for cash consideration equal to $250 million (the “USAC Transaction”). Concurrently, USAC cancelled its IDRs and converted its economic general partner interest into a non-economic general partner interest in exchange for the issuance of 8,000,000 USAC common units to USAC GP. Concurrent with these transactions, ETO contributed to USAC all of the issued and outstanding membership interests of CDM for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 USAC common units, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“USAC Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The USAC Class B Units are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019. As noted above, ET contributed its interests in USAC to ETO in October 2018. ET’s contribution of its interests in USAC was a transaction between entities under common control; therefore, the Partnership’s consolidated financial statements reflect USAC on a consolidated basis beginning April 2, 2018, the date that ET obtained control of USAC. The Partnership had previously deconsolidated CDM upon its contribution to USAC on April 2, 2018; however, due to the retrospective consolidation of USAC as of that date, CDM is reflected as a consolidated subsidiary for all periods presented herein. Summary of Assets Acquired and Liabilities Assumed The USAC Transaction was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. The total purchase price was allocated as follows: At April 2, 2018 Total current assets (2) $ 786 Property, plant and equipment 1,332 Other non-current assets 15 Goodwill (1) 366 Intangible assets 222 Total assets $ 2,721 Total current liabilities $ 110 Long-term debt, less current maturities 1,527 Other non-current liabilities 2 Total liabilities 1,639 Noncontrolling interest 832 Partners’ capital 250 Total liabilities and partners’ capital $ 2,721 (1) None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations. (2) Includes cash and cash equivalents of $711 million held by USAC as of the acquisition date. The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. Sunoco LP Retail Store Divestment 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. In connection with the 7-Eleven Transaction, Sunoco LP entered into a 15-year take-or-pay fuel supply arrangement with 7-Eleven and SEI Fuel. 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 sales were eliminated in consolidation. The Partnership has concluded that it meets the accounting requirements for reporting the financial position, results of operations and cash flows of the 7-Eleven Transaction and the operations of the related assets as discontinued operations. There were no results of operations associated with discontinued operations for the years ended December 31, 2020 and 2019. The results of operations associated with discontinued operations for the year ended December 31, 2018 are presented in the following table: Year Ended December 31, 2018 REVENUES $ 349 COSTS AND EXPENSES Cost of products sold 305 Operating expenses 61 Selling, general and administrative 7 Total costs and expenses 373 OPERATING LOSS (24) OTHER EXPENSE Interest expense, net 2 Loss on extinguishment of debt 20 Other, net 61 LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (107) Income tax expense 158 LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES $ (265)

Advances to and Investments in

Advances to and Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2020
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Investments in and Advances to Affiliates, Schedule of Investments [Text Block]	INVESTMENTS IN UNCONSOLIDATED AFFILIATES: Citrus We own CrossCountry Energy, LLC, a wholly-owned subsidiary of ETO, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, an approximately 5,362-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment. FEP We have a 50% interest in FEP which owns the Fayetteville Express Pipeline, an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline in Panola County, Mississippi. Our investment in FEP is reflected in the interstate transportation and storage segment. MEP We own a 50% interest in MEP, which owns the Midcontinent Express Pipeline, an approximately 500-miles natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment. White Cliffs We own a 51% interest in White Cliffs, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020. White Cliffs consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline. These pipelines transport crude and NGLs from Platteville, Colorado to Cushing, Oklahoma. The Partnership recorded an impairment of its investment in White Cliffs of $129 million during the year ended December 31, 2020 due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition and related purchase price allocation in December 2019. The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2020 and 2019 were as follows: December 31, 2020 2019 Citrus $ 1,867 $ 1,876 FEP 4 218 MEP 406 429 White Cliffs 274 436 Others 504 495 Total $ 3,055 $ 3,454 The following table presents equity in earnings (losses) of unconsolidated affiliates: Years Ended December 31, 2020 2019 2018 Citrus $ 162 $ 148 $ 141 FEP (1) (139) 59 55 MEP (6) 15 31 White Cliffs 20 4 — Other 82 76 117 Total equity in earnings of unconsolidated affiliates $ 119 $ 302 $ 344 (1) For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million. Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP and White Cliffs (on a 100% basis) for all periods presented, except as noted below: December 31, 2020 2019 Current assets $ 227 $ 247 Property, plant and equipment, net 7,339 7,680 Other assets 58 40 Total assets $ 7,624 $ 7,967 Current liabilities $ 600 $ 738 Non-current liabilities 3,298 3,242 Equity 3,726 3,987 Total liabilities and equity $ 7,624 $ 7,967 Years Ended December 31, 2020 2019 2018 Revenue $ 1,243 $ 1,192 $ 1,249 Operating income 6 683 723 Net income (loss) (199) 443 460 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

Debt Obligations (Notes)

Debt Obligations (Notes)	12 Months Ended
	Dec. 31, 2020
Debt Obligations [Abstract]
DEBT OBLIGATIONS	DEBT OBLIGATIONS: Our debt obligations consist of the following: December 31, 2020 2019 ETO Debt 5.50% Senior Notes due February 15, 2020 (1) $ — $ 250 5.75% Senior Notes due September 1, 2020 (1) — 400 4.15% Senior Notes due October 1, 2020 (1) — 1,050 7.50% Senior Notes due October 15, 2020 (1) — 1,135 4.40% Senior Notes due April 1, 2021 (2) 600 600 4.65% Senior Notes due June 1, 2021 (2) 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 4.65% Senior Notes due February 15, 2022 300 300 5.875% Senior Notes due March 1, 2022 900 900 5.00% Senior Notes due October 1, 2022 700 700 3.45% Senior Notes due January 15, 2023 350 350 3.60% Senior Notes due February 1, 2023 800 800 4.25% Senior Notes due March 15, 2023 995 995 4.20% Senior Notes due September 15, 2023 500 500 4.50% Senior Notes due November 1, 2023 600 600 5.875% Senior Notes due January 15, 2024 1,127 1,127 4.90% Senior Notes due February 1, 2024 350 350 7.60% Senior Notes due February 1, 2024 277 277 4.25% Senior Notes due April 1, 2024 500 500 4.50% Senior Notes due April 15, 2024 750 750 9.00% Debentures due November 1, 2024 65 65 4.05% Senior Notes due March 15, 2025 1,000 1,000 2.90% Senior Notes due May 15, 2025 1,000 — 5.95% Senior Notes due December 1, 2025 400 400 4.75% Senior Notes due January 15, 2026 1,000 1,000 3.90% Senior Notes due July 15, 2026 550 550 4.20% Senior Notes due April 15, 2027 600 600 5.50% Senior Notes due June 1, 2027 956 956 4.00% Senior Notes due October 1, 2027 750 750 4.95% Senior Notes due June 15, 2028 1,000 1,000 5.25% Senior Notes due April 15, 2029 1,500 1,500 8.25% Senior Notes due November 15, 2029 267 267 3.75% Senior Note due May 15, 2030 1,500 — 4.90% Senior Notes due March 15, 2035 500 500 6.625% Senior Notes due October 15, 2036 400 400 5.80% Senior Notes due June 15, 2038 500 500 7.50% Senior Notes due July 1, 2038 550 550 6.85% Senior Notes due February 15, 2040 250 250 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.30% Senior Notes due April 1, 2044 700 700 5.15% Senior Notes due March 15, 2045 1,000 1,000 5.35% Senior Notes due May 15, 2045 800 800 6.125% Senior Notes due December 15, 2045 1,000 1,000 5.30% Senior Notes due April 15, 2047 900 900 5.40% Senior Notes due October 1, 2047 1,500 1,500 6.00% Senior Notes due June 15, 2048 1,000 1,000 6.25% Senior Notes due April 15, 2049 1,750 1,750 5.00% Senior Notes due May 15, 2050 2,000 — Floating Rate Junior Subordinated Notes due November 1, 2066 546 546 ETO $2.00 billion Term Loan facility due October 2022 2,000 2,000 ETO $5.00 billion Revolving Credit Facility due December 2023 3,103 4,214 Unamortized premiums, discounts and fair value adjustments, net (17) (5) Deferred debt issuance costs (215) (207) 42,654 42,120 Transwestern Debt 5.36% Senior Notes due December 9, 2020 (1) — 175 5.89% Senior Notes due May 24, 2022 150 150 5.66% Senior Notes due December 9, 2024 175 175 6.16% Senior Notes due May 24, 2037 75 75 Deferred debt issuance costs — (1) 400 574 Panhandle Debt 7.60% Senior Notes due February 1, 2024 82 82 7.00% Senior Notes due July 15, 2029 66 66 8.25% Senior Notes due November 15, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 10 11 245 246 Bakken Project Debt 3.625% Senior Notes due April 1, 2022 650 650 3.90% Senior Notes due April 1, 2024 1,000 1,000 4.625% Senior Notes due April 1, 2029 850 850 Unamortized premiums, discounts and fair value adjustments, net (3) (3) Deferred debt issuance costs (13) (16) 2,484 2,481 Sunoco LP Debt 4.875% Senior Notes Due January 15, 2023 436 1,000 5.50% Senior Notes Due February 15, 2026 800 800 6.00% Senior Notes Due April 15, 2027 600 600 5.875% Senior Notes Due March 15, 2028 400 400 4.50% Senior Notes due May 15, 2029 800 — Sunoco LP $1.50 billion Revolving Credit Facility due July 2023 — 162 Lease-related obligations 103 135 Deferred debt issuance costs (27) (26) 3,112 3,071 USAC Debt 6.875% Senior Notes due April 1, 2026 725 725 6.875% Senior Notes due September 1, 2027 750 750 USAC $1.60 billion Revolving Credit Facility due April 2023 474 403 Deferred debt issuance costs (22) (26) 1,927 1,852 SemGroup Debt HFOTCO Tax Exempt Notes due 2050 225 225 Energy Transfer Canada Revolver due February 25, 2024 57 92 Energy Transfer Canada Term Loan A due February 25, 2024 261 269 Unamortized premiums, discounts and fair value adjustments, net — 1 Deferred debt issuance costs (2) (3) 541 584 Other 3 2 Total debt 51,366 50,930 Less: Current maturities of long-term debt 21 26 Long-term debt, less current maturities $ 51,345 $ 50,904 (1) As of December 31, 2019, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The notes were redeemed in January 2020. (2) As of December 31, 2020, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $289 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: 2021 $ 1,420 2022 5,731 2023 7,287 2024 4,598 2025 2,408 Thereafter 30,211 Total $ 51,655 Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap. Notes and Debentures ETO Senior Notes The ETO senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETO senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETO senior notes. The balance is payable upon maturity. Interest on the ETO senior notes is paid semi-annually. The ETO senior notes are unsecured obligations of the Partnership and as a result, the ETO senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETO senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries. ETO January 2020 Senior Notes Offering and Redemption On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of the Partnership’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of the Partnership’s 3.750% Senior Notes due 2030 and $2.00 billion aggregate principal amount of the Partnership’s 5.000% Senior Notes due 2050, (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’s wholly-owned subsidiary, Sunoco Logistics Operations, on a senior unsecured basis. Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020. Transwestern Senior Notes The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually. Sunoco LP November 2020 Senior Notes Offering and Repurchase On November 9, 2020, Sunoco LP completed a private offering of $800 million in aggregate principal amount of 4.500% senior notes due 2029. Sunoco LP used the proceeds to fund the tender offer on its 4.875% $1 billion senior notes due 2023. Approximately 56% of the 2023 senior notes were tendered. On January 15, 2021, Sunoco LP repurchased the remaining outstanding portion of its 2023 senior notes. Credit Facilities, Term Loan and Commercial Paper ETO Term Loan On October 17, 2019, ETO entered into a term loan credit agreement (the “ETO Term Loan”) providing for a $2.00 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 is unsecured and is guaranteed by our subsidiary, Sunoco Logistics Operations. As of December 31, 2020, the ETO Term Loan had $2.00 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 1.15%. 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 December 31, 2020, the ETO Five-Year Credit Facility had $3.10 billion outstanding, of which $1.66 billion was commercial paper. The amount available for future borrowings was $1.79 billion after accounting for outstanding letters of credit in the amount of $109 million. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 1.12%. 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 26, 2021. As of December 31, 2020, 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”). As of December 31, 2020, the Sunoco LP Credit Facility had no outstanding borrowings and $8 million in standby letters of credit. The amount available for future borrowings was $1.5 billion at December 31, 2020. USAC Credit Facility USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”), which matures on April 2, 2023 and permits up to $400 million of future increases in borrowing capacity. As of December 31, 2020, USAC had $474 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2020, USAC had $1.1 billion of availability under its credit facility. The weighted average interest rate on the total amount outstanding as of December 31, 2020 was 3.27%. Energy Transfer Canada Credit Facilities Energy Transfer Canada is party to a credit agreement providing for a C$350 million (US$275 million at the December 31, 2020 exchange rate) senior secured term loan facility, a C$525 million (US$412 million at the December 31, 2020 exchange rate) senior secured revolving credit facility, and a C$300 million (US$236 million at the December 31, 2020 exchange rate) senior secured construction loan facility (the “KAPS Facility”). The term loan facility and the revolving credit facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. Energy Transfer Canada may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$196 million at the December 31, 2020 exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders. Covenants Related to Our Credit Agreements Covenants Related to ETO The agreements relating to the ETO senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions. The ETO Credit Facilities (defined as the ETO Term Loan, ETO Five-Year Credit Facility and ETO 364-Day Credit Facility) contain covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things: • incur indebtedness; • grant liens; • enter into mergers; • dispose of assets; • make certain investments; • make Distributions (as defined in the ETO Credit Facilities) during certain Defaults (as defined in the ETO Credit Facilities) and during any Event of Default (as defined in the ETO Credit Facilities); • engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries; • engage in transactions with affiliates; and • enter into restrictive agreements. The ETO Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETO Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETO Five-Year Credit Facility ranges from 0.125% to 0.300%. The applicable margin for eurodollar rate loans under the ETO 364-Day Facility ranges from 1.500% to 2.000% and the applicable margin for base rate loans ranges from 0.500% to 1.000%. The applicable rate for commitment fees under the ETO 364-Day Facility ranges from 0.125% to 0.225%. The ETO Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The ETO Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 4.31 to 1 at December 31, 2020, as calculated in accordance with the credit agreements. The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio. Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders. Covenants Related to Panhandle Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Panhandle’s restrictive covenants include restrictions on liens securing debt and guarantees and restrictions on mergers and on the sales of assets. A breach of any of these covenants could result in acceleration of Panhandle’s debt. Covenants Related to Sunoco LP The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a Net Leverage Ratio of not more than 5.5 to 1. The maximum Net Leverage Ratio is subject to upwards adjustment of not more than 6.0 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in certain specified acquisitions of not less than $50 million (as permitted under Sunoco LP’s Credit Facility agreement). The Sunoco LP Credit Facility also requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in the Sunoco LP’s Credit Facility agreement) of not less than 2.25 to 1. Covenants Related to USAC The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things: • grant liens; • make certain loans or investments; • incur additional indebtedness or guarantee other indebtedness; • merge or consolidate; • sell our assets; or • make certain acquisitions. The credit facility is also subject to the following financial covenants, including covenants requiring us to maintain: • a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter; and • a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.75 to 1 through the end of the fiscal quarter ending December 31, 2020 and (ii) 5.5 to 1 for the fiscal quarters ending March 31, 2021 and June 30, 2021, (iii) 5.25 to 1 for the fiscal quarters ending September 30, 2021 and December 31, 2021 and (iv) 5.0 to 1 thereafter, subject to a provision for increases to such thresholds, in the case of any fiscal quarter ending September 30, 2021 or thereafter, by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs, provided that, in any event, such ratio shall not exceed 5.5 to 1. Covenants Related to the HFOTCO Tax Exempt Notes The indentures covering HFOTCO's tax exempt notes due 2050 ("IKE Bonds") include customary representations and warranties and affirmative and negative covenants. Such covenants include limitations on the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the bondholders, taking actions to remove the trustee, making certain amendments to the bond documents, and taking actions or omitting to take actions that adversely impact the tax exempt status of the IKE Bonds. Compliance with our Covenants We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2020.

Redeemable Noncontrolling Inter

Redeemable Noncontrolling Interest (Notes)	12 Months Ended
	Dec. 31, 2020
Temporary Equity [Abstract]
Redeemable Noncontrolling Interest [Text Block]	REDEEMABLE NONCONTROLLING INTERESTSCertain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of December 31, 2020 included a balance of $477 million related to the USAC Preferred Units described below and a balance of $15 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. In addition, redeemable noncontrolling interests includes a balance of $270 million in Energy Transfer Canada preferred shares contributed by ET subsequent to its acquisition of SemGroup. USAC Series A 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 in a private placement. 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. Certain portions of the USAC Preferred Units will be convertible into USAC common units at the election of the holders beginning in 2021. To the extent the holders of the USAC Preferred Units have not elected to convert their preferred units by the fifth anniversary of the issue date, USAC will have the option to redeem all or any portion of the USAC Preferred Units for cash. In addition, at any time on or after the tenth anniversary of the issue date, the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and the Partnership may elect to pay up to 50% of such redemption amount in USAC common units.

Equity (Notes)

Equity (Notes)	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Partners' Capital Notes Disclosure	EQUITY: Limited Partner interests are represented by Common Units and other classes of units described below, as well as Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, and Series G Preferred Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance. Class K Units As of December 31, 2020, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETO. Each Class K Unit is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETO making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETO from ETP Holdco. If the Partnership is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. Class L Units On December 31, 2018, ETO issued a new class of limited partner interests titled Class L Units to two wholly-owned subsidiaries of the Partnership when the Partnership’s previously outstanding Class E units and Class G units held by such subsidiaries were converted into Class L Units. As a result of the conversion, the Class E units and Class G units were cancelled. The Class L Units generally do not have any voting rights. The Class L Units are entitled to aggregate cash distributions equal to 7.65% per annum of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution. Distributions shall be paid quarterly, in arrears, within 45 days after the end of each quarter. As the Class L Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. Class M Units On July 1, 2019, ETO issued a new class of limited partner interests titled Class M Units to ETP Holdco, a wholly-owned subsidiary of the Partnership, in exchange for the contribution of ETP Holdco’s equity ownership interest in Panhandle to the Partnership. The Class M Units generally do not have any voting rights. The Class M Units are entitled to aggregate cash distributions equal to 8.00% per annum of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution. Distributions shall be paid quarterly, in arrears, within 45 days after the end of each quarter. As the Class M Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. Class N Units In April and May, 2020, ETO issued a new class of limited partner interests titles Class N Units in connection with a series of internal transactions to simplify its capital structure. All of the Class N Units are held by ETP Holdco. The Class N Units generally do not have any voting rights. each Class N Unit is entitled to a quarterly cash distribution of $0.2375 per Class N Unit prior to ETO making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETO from ETP Holdco. Distributions shall be paid quarterly, in arrears, within 45 days after the end of each quarter. If the Partnership is unable to pay the Class N Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As the Class N Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. ETO Preferred Units As of December 31, 2020 and 2019, our outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series B Preferred Units, 18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units and 32,000,000 Series E Preferred Units. As of December 31, 2020, our outstanding preferred units also included 500,000 Series F Preferred Units and 1,100,000 Series G Preferred Units. The following table summarizes changes in the amounts of our Series A, Series B, Series C, Series D, Series E, Series F and Series G preferred units for the years ended December 31, 2020, 2019 and 2018 were as follows: Preferred Unitholders Series A Series B Series C Series D Series E Series F Series G Total Balance, December 31, 2017 $ 944 $ 547 $ — $ — $ — $ — $ — $ 1,491 Distributions to partners (44) (27) (18) (11) — — — (100) Units issued for cash — — 436 431 — — — 867 Other, net (1) — (1) (1) — — — (3) Net income 59 36 23 15 — — — 133 Balance, December 31, 2018 958 556 440 434 — — — 2,388 Distributions to partners (59) (37) (33) (34) (34) — — (197) Units issued for cash — — — — 780 — — 780 Other, net — — — — (1) — — (1) Net income 59 37 33 34 41 — — 204 Balance, December 31, 2019 958 556 440 434 786 — — 3,174 Distributions to partners (59) (37) (33) (34) (61) (27) (64) (315) Units issued for cash — — — — — 494 1,086 1,580 Other, net — — — — — (2) (2) (4) Net income 59 37 33 34 61 31 74 329 Balance, December 31, 2020 $ 958 $ 556 $ 440 $ 434 $ 786 $ 496 $ 1,094 $ 4,764 ETO Series A Preferred Units Distributions on the Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The Series A Preferred Units are redeemable at ETO’s option on or after February 15, 2023 at a redemption price of $1,000 per Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. ETO Series B Preferred Units Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The Series B Preferred Units are redeemable at ETO’s option on or after February 15, 2028 at a redemption price of $1,000 per Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. ETO Series C Preferred Units Distributions on the Series C Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.530% per annum. The Series C Preferred Units are redeemable at ETO’s option on or after May 15, 2023 at a redemption price of $25 per Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. ETO Series D Preferred Units Distributions on the Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.738% per annum. The Series D Preferred Units are redeemable at ETO’s option on or after August 15, 2023 at a redemption price of $25 per Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. ETO Series E Preferred Units Distributions on the 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 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 Series E Preferred Units are redeemable at ETO’s option on or after May 15, 2024 at a redemption price of $25 per Series E Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. ETO Series F Preferred Units On January 22, 2020, the Partnership issued 500,000 of its 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units representing limited partner interest in the Partnership, at a price to the public of $1,000 per unit. Distributions on the Series F Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2025, at a rate equal to 6.750% per annum of the $1,000 liquidation preference. On and after May 15, 2025, the distribution rate on the Series F Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.134% per annum. The Series F Preferred Units are redeemable at ETO’s option on or after May 15, 2025 at a redemption price of $1,000 per Series F Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. ETO Series G Preferred Units On January 22, 2020, the Partnership issued 1,100,000 of its 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units representing limited partner interest in the Partnership, at a price to the public of $1,000 per unit. Distributions on the Series G Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2030, at a rate equal to 7.125% per annum of the $1,000 liquidation preference. On and after May 15, 2030, the distribution rate on the Series G Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.306% per annum. The Series G Preferred Units are redeemable at ETO’s option on or after May 15, 2030 at a redemption price of $1,000 per Series G Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Subsidiary Equity Transactions Sunoco LP’s Equity Distribution Program Sunoco LP is party to an equity distribution agreement for an at-the-market (“ATM”) offering pursuant to which Sunoco LP may sell its common units from time to time. For the years ended December 31, 2020, 2019 and 2018, Sunoco LP issued no units under its ATM program. As of December 31, 2020, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement. USAC’s Distribution Reinvestment Program During the year ended December 31, 2020 and 2019, distributions of $1.9 million and $1 million, respectively, were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 188,695 and 60,584 USAC common units, respectively. USAC’s Warrant Private Placement On April 2, 2018, USAC issued two tranches of warrants to purchase USAC common units (the “USAC Warrants”), which included USAC Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and USAC Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The USAC Warrants may be exercised by the holders thereof at any time beginning on the one year anniversary of the closing date and before the tenth anniversary of the closing date. Upon exercise of the USAC Warrants, USAC may, at its option, elect to settle the USAC Warrants in common units on a net basis. USAC’s Class B Units The USAC Class B Units, all of which are owned by ETO, are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of the USAC Transaction on April 2, 2018. Each USAC Class B Unit automatically converted into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019. 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 participate in distributions declared by USAC. Cash Distributions ETO Preferred Unit Distributions Distributions on the ETO’s Series A, Series B, Series C, Series D and Series E preferred units declared and/or paid by ETO were as follows: Period Ended Record Date Payment Date Series A (1) Series B (1) Series C Series D Series E Series F (1) Series G (1) June 30, 2018 August 1, 2018 August 15, 2018 $ 31.2500 $ 33.1250 $ 0.5634 * $ — $ — $ — $ — September 30, 2018 November 1, 2018 November 15, 2018 — — 0.4609 0.5931 * — — — December 31, 2018 February 1, 2019 February 15, 2019 31.2500 33.1250 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 31.2500 33.1250 0.4609 0.4766 0.5806 * — — September 30, 2019 November 1, 2019 November 15, 2019 — — 0.4609 0.4766 0.4750 — — December 31, 2019 February 3, 2020 February 18, 2020 31.2500 33.1250 0.4609 0.4766 0.4750 — — March 31, 2020 May 1, 2020 May 15, 2020 — — 0.4609 0.4766 0.4750 21.19 * 22.36 * June 30, 2020 August 3, 2020 August 17, 2020 31.2500 33.1250 0.4609 0.4766 0.4750 — — September 30, 2020 November 2, 2020 November 15, 2020 — — 0.4609 0.4766 0.4750 33.75 35.625 December 31, 2020 February 1, 2021 February 16, 2021 31.2500 33.1250 0.4609 0.4766 0.4750 — — * Represent prorated initial distributions. (1) ETO Series A Preferred Unit, ETO Series B Preferred Unit, ETO Series F Preferred Unit and ETO Series G Preferred Unit distributions are paid on a semi-annual basis. Sunoco LP Cash Distributions The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Marginal Percentage Interest in Distributions Total Quarterly Distribution Target Amount Common Unitholders Holder of IDRs Minimum Quarterly Distribution $0.4375 100% —% First Target Distribution $0.4375 to $0.503125 100% —% Second Target Distribution $0.503125 to $0.546875 85% 15% Third Target Distribution $0.546875 to $0.656250 75% 25% Thereafter Above $0.656250 50% 50% Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2017 February 6, 2018 February 14, 2018 $ 0.8255 March 31, 2018 May 7, 2018 May 15, 2018 0.8255 June 30, 2018 August 7, 2018 August 15, 2018 0.8255 September 30, 2018 November 6, 2018 November 14, 2018 0.8255 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 December 31, 2019 February 7, 2020 February 19, 2020 0.8255 March 31, 2020 May 7, 2020 May 19, 2020 0.8255 June 30, 2020 August 7, 2020 August 19, 2020 0.8255 September 30, 2020 November 6, 2020 November 19, 2020 0.8255 December 31, 2020 February 8, 2021 February 19, 2021 0.8255 USAC Cash Distributions Subsequent to the Energy Transfer Merger and USAC Transactions described in Note 1 and Note 3, respectively, ETO owned approximately 39.7 million USAC common units and 6.4 million USAC Class B units. Subsequent to the conversion of the USAC Class B Units to USAC common units on July 30, 2019, ETO owns approximately 46.1 million USAC common units. As of December 31, 2020, USAC had approximately 97.0 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs. Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows: Quarter Ended Record Date Payment Date Rate March 31, 2018 May 1, 2018 May 11, 2018 $ 0.5250 June 30, 2018 July 30, 2018 August 10, 2018 0.5250 September 30, 2018 October 29, 2018 November 9, 2018 0.5250 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 December 31, 2019 January 27, 2020 February 7, 2020 0.5250 March 31, 2020 April 27, 2020 May 8, 2020 0.5250 June 30, 2020 July 31, 2020 August 10, 2020 0.5250 September 30, 2020 October 26, 2020 November 6, 2020 0.5250 December 31, 2020 January 25, 2021 February 5, 2021 0.5250 Accumulated Other Comprehensive Income The following table presents the components of AOCI, net of tax: December 31, 2020 2019 Available-for-sale securities $ 18 $ 13 Foreign currency translation adjustment 7 (5) Actuarial loss related to pensions and other postretirement benefits (7) (25) Investments in unconsolidated affiliates, net (14) (1) Subtotal 4 (18) Amounts attributable to noncontrolling interest 2 — Total AOCI, net of tax $ 6 $ (18) The table below sets forth the tax amounts included in the respective components of other comprehensive income: December 31, 2020 2019 Available-for-sale securities $ (1) $ (1) Foreign currency translation adjustment 8 2 Actuarial loss relating to pension and other postretirement benefits 3 8 Total $ 10 $ 9

Unit-Based Compensation Plans (

Unit-Based Compensation Plans (Notes)	12 Months Ended
	Dec. 31, 2020
Deferred Compensation Arrangements [Abstract]
UNIT-BASED COMPENSATION PLANS	NON-CASH COMPENSATION PLANS: ETO Long-Term Incentive Plan We have previously issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETO Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. The Partnership does not currently have any equity compensation plans. In connection with the Energy Transfer Merger in October 2018, all of the Partnership’s equity compensation plans, as well as the Partnership’s obligations under those plans, were assumed by ET. The Partnership recorded stock compensation expense of $121 million, $113 million, and $105 million for the years ended December 31, 2020, 2019 and 2018, respectively. Subsidiary Long-Term Incentive Plans Each of Sunoco LP and USAC has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards”) to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a three or five-year period, that entitles the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding. The following table summarizes the activity of the Subsidiary Unit Awards: Sunoco LP USAC Number of Weighted Average Number of Weighted Average Unvested awards as of December 31, 2019 2.1 $ 29.21 1.8 $ 15.09 Awards granted 0.7 28.63 0.7 12.55 Awards vested (0.5) 30.47 (0.2) 17.27 Awards forfeited (0.2) 29.11 (0.2) 15.36 Unvested awards as of December 31, 2020 2.1 28.63 2.1 14.88 The following table summarizes the weighted average grant-date fair value per unit award granted: Years Ended December 31, 2020 2019 2018 Sunoco LP $ 28.63 $ 30.70 $ 27.67 USAC 12.55 15.88 15.47 The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2020, 2019 and 2018 was $16 million, $17 million and $22 million, respectively, based on the market price of Sunoco LP and USAC common units as of the vesting date for the years ended December 31, 2020, 2019 and 2018. As of December 31, 2020, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $39 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.6 years.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES: As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows: Years Ended December 31, 2020 2019 2018 Current expense (benefit): Federal $ (6) $ (20) $ (7) State 32 (2) 20 Foreign 1 — — Total 27 (22) 13 Deferred expense (benefit): Federal 178 176 183 State 41 45 (191) Foreign (7) — — Total 212 221 (8) Total income tax expense $ 239 $ 199 $ 5 Historically, our effective tax rate has differed 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. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2020, 2019 and 2018 is as follows: Years Ended December 31, 2020 2019 2018 Income tax expense at United States statutory rate $ 116 $ 1,116 $ 861 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax 54 (925) (730) Noncontrolling interests 16 — — State income taxes (net of federal income tax effects) 58 14 (125) Dividend received deduction — (3) (5) Foreign (7) — — Other 2 (3) 4 Income tax expense $ 239 $ 199 $ 5 Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: December 31, 2020 2019 Deferred income tax assets: Net operating losses, alternative minimum tax credit and other carryforwards $ 1,047 $ 936 Pension and other postretirement benefits — 7 Other 34 85 Total deferred income tax assets 1,081 1,028 Valuation allowance (134) (95) Net deferred income tax assets $ 947 $ 933 Deferred income tax liabilities: Property, plant and equipment $ (263) $ (464) Investments in affiliates (3,994) (3,547) Trademarks (77) (72) Other (5) (21) Total deferred income tax liabilities (4,339) (4,104) Net deferred income taxes $ (3,392) $ (3,171) As of December 31, 2020, ETP Holdco had a federal net operating loss carryforward of $3.73 billion, of which $1.3 billion will expire in 2031 through 2037 while the remaining can be carried forward indefinitely. A total of $787 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in a particular year may be limited. As of December 31, 2020, Sunoco Property Company LLC, a corporate subsidiary of Sunoco LP, had a state net operating loss carrryforward of $121 million, which we expect to fully utilize. Sunoco Property Company LLC has no federal net operating loss carryforward. Our corporate subsidiaries have state net operating loss carryforward benefits of $174 million, net of federal tax, some of which will expire between 2021 and 2039, while others are carried forward indefinitely. Our corporate subsidiaries have Canadian net operating losses of $7 million that will begin to expire in 2033. Our corporate subsidiaries have cumulative excess business interest expense of $129 million available for carryforward indefinitely. A valuation allowance of $89 million is applicable to the state net operating loss carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania. A separate valuation allowance of $45 million is attributable to foreign tax credits. The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2020 2019 2018 Balance at beginning of year $ 94 $ 624 $ 609 Additions attributable to tax positions taken in the current year — — 8 Additions attributable to tax positions taken in prior years — 11 7 Reduction attributable to tax positions taken in prior years — (541) — Lapse of statute (4) — — Balance at end of year $ 90 $ 94 $ 624 As of December 31, 2020, we have $90 million ($48 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2020, we recognized interest and penalties of $7 million. At December 31, 2020, we have interest and penalties accrued of $10 million, net of tax. We appealed the adverse Court of Federal Claims decision against ETC Sunoco regarding the IRS’ denial of ethanol blending credits claims under Section 6426 to the Federal Circuit. The Federal Circuit affirmed the CFC’s denial on November 1, 2018. ETC Sunoco filed a petition for certiorari with the Supreme Court on May 24, 2019 to review the Federal Circuit's affirmation of the CFC's ruling, and the Court denied Sunoco's petition on October 7, 2019. The petition for certiorari applied to ETC Sunoco’s 2004 through 2009 tax years, and 2010 through 2011 remained on extension with the IRS through September 28, 2020. We filed a petition for the 2010 and 2011 years in the Federal District Court for the Northern District of Texas on September 25, 2020. 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 consolidated 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 and results of operations. In November 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact. Nextel subsequently filed a petition for writ of certiorari with the United States Supreme Court, and this was denied on June 11, 2018. Now certain Pennsylvania taxpayers are proceeding with litigation in Pennsylvania state courts on issues not addressed by the Pennsylvania Supreme Court in Nextel, specifically, whether the Due Process and Equal Protection Clauses of the United States Constitution and the Remedies Clause of the Pennsylvania Constitution require a court to grant the taxpayer relief. ETC Sunoco has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter. However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $34 million ($27 million after federal income tax benefits) against the receivable. In general, ETO and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2014 and prior tax years. ETO and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

Regulatory Matters, Commitments

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Notes)	12 Months Ended
	Dec. 31, 2020
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Commitments Contingencies and Guarantees [Text Block]	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 (“NGA”) 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 NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by the order of the Chief Judge dated October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. By an order dated January 19, 2021, the Chief Judge has extended the deadline for the initial decision to March 2021. 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. Our joint venture agreements require that we fund our proportionate share of capital contributions to its unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. We have certain non-cancelable 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: Years Ended December 31, 2020 2019 2018 ROW expense $ 47 $ 45 $ 46 PES Refinery Fire and Bankruptcy We previously owned an approximately 7.4% indirect non-operating interest in PES, which owned a former refinery in Philadelphia. In addition, the Partnership previously provided logistics services to PES under commercial contracts and Sunoco LP previously purchased refined products from PES. In June 2019, an explosion and fire occurred at the refinery complex. On July 21, 2019, 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 also defaulted on a $75 million note payable to a subsidiary of the Partnership. In June 2020, the Partnership received $12 million from PES on the note payable and recorded a reserve for the remaining $63 million note balance. In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of December 31, 2020, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such costs, 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 depending upon the use of such property by the buyer; 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. 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. 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 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. As of December 31, 2020 and 2019, accruals of approximately $77 million and $120 million, respectively, were reflected on our consolidated balance sheets related to contingent obligations that met both the probable and reasonably estimable criteria. In addition, we may recognize additional contingent losses in the future related to (i) contingent matters for which a loss is currently considered reasonably possible but not probable and/or (ii) losses in excess of amounts that have already been accrued for such contingent matters. In some of these cases, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. For such matters where additional contingent losses can be reasonably estimated, the range of additional losses is estimated to be up to approximately $80 million. 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 or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Dakota Access Pipeline On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) that challenged permits issued by the United States Army Corps of Engineers (“USACE”) that allowed Dakota Access, LLC (“Dakota Access”) to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE that allowed the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the District Court vacated the easement and ordered Dakota Access to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the United States Court of Appeals for the District of Columbia (“Court of Appeals”), which granted an administrative stay of the District Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August 5, 2020, the Court of Appeals 1) granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, 2) denied a motion to stay the March 25 order pending a decision on the merits by the Court of Appeals as to whether the USACE would be required to prepare an EIS, and 3) denied a motion to stay the District Court’s order to vacate the easement during this appeal process. The August 5 order also stated that the Court of Appeals expected the USACE to clarify its position with respect to whether the USACE intended to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary. On August 10, 2020, the District Court ordered the USACE to submit a status report by August 31, 2020, clarifying its position with regard to its decision-making process with respect to the continued operation of the pipeline. On August 31, 2020, the USACE submitted a status report that indicated that it considered the presence of the pipeline at the Lake Oahe crossing without an easement to constitute an encroachment on federal land, and that it was still considering whether to exercise its enforcement discretion regarding this encroachment. Following the filing of this status report, the District Court ordered briefing on whether to enjoin the operation of the pipeline. That motion was fully briefed as of January 8, 2021. The District Court has yet to rule on this matter. On January 26, 2021, the Court of Appeals affirmed the District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order vacating the easement. In this same January 26 order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline shut down and be emptied of oil. The District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. At the request of the USACE, on February 9, 2021 the District Court granted a two-month continuance for the status conference until April 9, 2021. The pipeline continues to operate pending rulings from the District Court. ET cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access pipelines; however, ET expects after the law and complete record are fully considered, the issues in this litigation will be resolved in a manner that will allow the pipeline to continue to operate. In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations. 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; however, 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 Holdings LLC and Sunoco (R&M), LLC (collectively, “Sunoco Defendants”) 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 December 31, 2020, Sunoco Defendants are defendants 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 On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint related to the Regency-ETO merger (the “Regency Merger”) 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. On March 29, 2016, the Delaware Court of Chancery granted the defendants’ motion to dismiss the lawsuit in its entirety. Plaintiff appealed, and the Delaware Supreme Court reversed the judgment of the Court of Chancery. Plaintiff then filed an Amended Verified Class Action Complaint, which defendants moved to dismiss. The Court of Chancery granted in part and denied in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP LP and Regency GP LLC (the “Regency Defendants”). The Court of Chancery later granted plaintiff’s unopposed motion for class certification. Trial was held on December 10-16, 2019, and a post-trial hearing was held on May 6, 2020. On February 15, 2021, the Court of Chancery ruled in favor of the Regency Defendants on both remaining counts at issue in this litigation. The Regency Defendants cannot predict whether the plaintiff will appeal this decision. Rover On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants seeking to recover civil penalties allegedly owed and certain injunctive relief related to permit compliance. The defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court, which the defendants opposed in briefs filed in February 2020. On April 22, 2020, the Ohio Supreme Court granted the Ohio EPA’s request for review. Briefing has concluded and oral argument was held on January 26, 2021. Revolution On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution Pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries. On February 8, 2019, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Permit Hold on any requests for approvals/permits or permit amendments for any project 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 January 3, 2020, the Partnership entered into a Consent Order and Agreement with the PADEP in which, among other things, the Permit Hold was lifted, the Partnership agreed to pay a $28.6 million civil penalty and fund a $2 million community environmental project, and all related appeals were withdrawn. On November 11, 2020, the PADEP issued an order that required additional approvals and work prior to placing the Revolution Pipeline back in service. The Partnership filed an appeal of this order on December 8, 2020. 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 former Chester County District Attorney (the “Chester County DA”) sent a letter to the Partnership stating that his office 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, which has issued subpoenas seeking documents and testimony. On September 24, 2019, the Chester County DA sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership responded to the Notice of Intent within the proscribed time period. In December 2019, the Chester County DA announced charges against a current employee related to the provision of security services. On June 25, 2020, a preliminary hearing was held on the charges against the employee, and the judge dismissed all charges. Delaware County, Pennsylvania Investigation On March 11, 2019, the Delaware County District Attorney’s Office (the “Delaware County DA”) announced that the Delaware County DA and the Pennsylvania Attorney General’s Office, at the request of the Delaware County DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. On March 16, 2020, the Pennsylvania Attorney General Office served a Statewide Investigating Grand Jury subpoena for documents relating to inadvertent returns and water supplies related to the Mariner East pipelines. While the Partnership will cooperate with the subpoena, it intends to vigorously defend itself. Cline Class Action Lawsuit On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco, Inc. (R&M) and Sunoco Partners Marketing & Terminals L.P. (collectively, “SPMT”) that alleged SPMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012 and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments, and pass through payments, as well as governmental agencies and publicly traded oil and gas companies. After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $74.8 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $80.7 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees. On August 27, 2020, SPMT filed its Notice of Appeal with the 10th Circuit and appealed the entirety of the Order. SPMT cannot predict the outcome of the case, nor can SPMT predict the amount of time and expense that will be required to resolve the appeal, but intends to vigorously appeal the entirety of the Order. 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 the 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 related to the Caddo Parish, Louisiana release. In October 2018, the Pipeline and 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. The Remedial Work Plan was approved by PHMSA on August 28, 2020. 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 release 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. The OCC has accepted our counter offer in conjunction with a proposed consent order. The Consent Order was presented to the OCC at a hearing on August 18, 2020, and is awaiting final signature by the OCC Commissioners. Environmental Remediation Our subsidiaries are responsible for environmental remediation at certain sites, including the following: • certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties. • certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons. • legacy sites related to Sunoco that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites. 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 December 31, 2020, Sunoco had been named as a PRP at approximately 35 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon 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. December 31, 2020 2019 Current $ 44 $ 46 Non-current 262 274 Total environmental liabilities $ 306 $ 320 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 years ended December 31, 2020 and 2019, the Partnership recorded $29 million and $39 million, respectively, of expenditures related to environmental cleanup programs. Our pipeline operations are subject to regulation by the United States Department of Transportation under PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, 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

Revenue (Notes)

Revenue (Notes)	12 Months Ended
	Dec. 31, 2020
Revenue [Abstract]
Revenue from Contract with Customer [Text Block]	REVENUE: Disaggregation of revenue The major types of revenue within our reportable segments, are as follows: • 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; • fuel distribution and marketing; • all other; • investment in USAC; • contract operations; • retail parts and services; and • all other. Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Shell. Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed. The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal. The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. Midstream revenue Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported. The various types of revenue contracts our midstream segment enters into include: Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed. Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed. Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below: • In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed. • Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers. NGL and refined products transportation and services revenue Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGLs and other related hydrocarbons at market rates. These contracts were not affected by ASC 606. Crude oil transportation and services revenue Our crude oil transportation and services segment revenues are primarily derived from providing transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed. Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606. Sunoco LP’s fuel distribution and marketing revenue Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to dealers, sales to distributors, unbranded wholesale revenue, commission agent revenue, rental income and other income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin, and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method. Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. Under the new standard, to determine when control transfers to the customer, the shipping terms of the contract are assessed as shipping terms are considered a primary indicator of the transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized. Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer. Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor are recognized ratably over the term of the underlying lease. Sunoco LP’s all other revenue Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided). USAC’s contract operations revenue USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years, however USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract. Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower. USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin. The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date. There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration. USAC’s retail parts and services revenue USAC’s retail parts and service revenue is earned primarily on freight and crane charges that are directly reimbursable by USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration. All other revenue Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard. Contract Balances with Customers The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability. The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services. 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 minimum fee, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. 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 $ 394 Additions 651 Revenue recognized (680) Balance, December 31, 2019 365 Additions 771 Revenue recognized (846) Balance, December 31, 2020 $ 290 The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2020 and 2019 were as follows: December 31, 2020 December 31, 2019 Contract balances: Contract asset $ 121 $ 117 Accounts receivable from contracts with customers 256 366 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 years ended December 31, 2020, 2019 and 2018 was $18 million, $17 million and $14 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 contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contracts, only the fixed component of the contracts are included in the table below. Sunoco LP distributes fuel under long-term contracts to branded distributors, branded and unbranded third-party dealers, and branded and unbranded retail fuel outlets. Sunoco LP branded supply contracts with distributors generally have both time and volume commitments that establish contract duration. These contracts have an initial term of approximately nine years, with an estimated, volume-weighted term remaining of approximately four years. As part of the asset purchase agreement with 7-Eleven, Sunoco LP and 7-Eleven and SEI Fuel (collectively, the “Distributor”) have entered into a 15-year take-or-pay fuel supply agreement in which the Distributor is required to purchase a volume of fuel that provides Sunoco LP a minimum amount of gross profit annually. Sunoco LP expects to recognize this revenue in accordance with the contract as Sunoco LP transfers control of the product to the customer. However, in case of annual shortfall Sunoco LP will recognize the amount payable by the Distributor at the sooner of the time at which the Distributor makes up the shortfall or becomes contractually or operationally unable to do so. The transaction price of the contract is variable in nature, fluctuating based on market conditions. The Partnership has elected to take the practical expedient not to estimate the amount of variable consideration allocated to wholly unsatisfied performance obligations. In some contractual arrangements, Sunoco LP grants dealers a franchise license to operate Sunoco LP’s retail stores over the life of a franchise agreement. In return for the grant of the retail store license, the dealer makes a one-time nonrefundable franchise fee payment to Sunoco LP plus sales based royalties payable to Sunoco LP at a contractual rate during the period of the franchise agreement. Under the requirements of ASC Topic 606, the franchise license is deemed to be a symbolic license for which recognition of revenue over time is the most appropriate measure of progress toward complete satisfaction of the performance obligation. Revenue from this symbolic license is recognized evenly over the life of the franchise agreement. As of December 31, 2020, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $40.35 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below: Years Ending December 31, 2021 2022 2023 Thereafter Total Revenue expected to be recognized on contracts with customers existing as of December 31, 2020 $ 5,120 $ 5,475 $ 5,051 $ 24,701 $ 40,347 Practical Expedients Utilized by the Partnership The Partnership elected the following practical expedients in accordance with Topic 606: • Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers. • Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less. • Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfie

Lease Accounting (Notes)

Lease Accounting (Notes)	12 Months Ended
	Dec. 31, 2020
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 December 31, 2020 and 2019 were as follows: December 31, 2020 2019 Operating leases: Lease right-of-use assets, net $ 863 $ 935 Operating lease current liabilities 53 60 Accrued and other current liabilities 1 1 Non-current operating lease liabilities 837 901 Finance leases: Property, plant and equipment, net $ 1 1 Lease right-of-use assets, net 3 29 Accrued and other current liabilities 1 1 Current maturities of long-term debt 1 6 Long-term debt, less current maturities 6 26 Other non-current liabilities 1 2 The components of lease expense for the years ended December 31, 2020 and 2019 were as follows: Year Ended December 31, Income Statement Location 2020 2019 Operating lease costs: Operating lease cost Cost of goods sold $ 14 $ 28 Operating lease cost Operating expenses 75 73 Operating lease cost Selling, general and administrative 17 16 Total operating lease costs 106 117 Finance lease costs: Amortization of lease assets Depreciation, depletion and amortization 3 6 Interest on lease liabilities Interest expense, net of capitalized interest 1 1 Total finance lease costs 4 7 Short-term lease cost Operating expenses 31 42 Variable lease cost Operating expenses 16 17 Lease costs, gross 157 183 Less: Sublease income Other revenue 48 47 Lease costs, net $ 109 $ 136 The weighted average remaining lease terms and weighted average discount rates as of December 31, 2020 and 2019 were as follows: December 31, 2020 2019 Weighted-average remaining lease term (years): Operating leases 22 24 Finance leases 9 5 Weighted-average discount rate (%): Operating leases 5 % 5 % Finance leases 8 % 5 % Cash flows and non-cash activity related to leases for the years ended December 31, 2020 and 2019 were as follows: Year Ended December 31, 2020 2019 Operating cash flows from operating leases $ (117) $ (159) Lease assets obtained in exchange for new finance lease liabilities — 28 Lease assets obtained in exchange for new operating lease liabilities 42 40 Maturities of lease liabilities as of December 31, 2020 are as follows: Operating leases Finance leases Total 2021 $ 99 $ 2 $ 101 2022 85 2 87 2023 79 2 81 2024 76 1 77 2025 75 1 76 Thereafter 1,140 4 1,144 Total lease payments 1,554 12 1,566 Less: present value discount 664 3 667 Present value of lease liabilities $ 890 $ 9 $ 899 Lessor Accounting The Partnership leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Our 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 years ended December 31, 2020 and 2019 was $144 million and $149 million, respectively. Future minimum operating lease payments receivable as of December 31, 2020 are as follows: Lease Payments 2021 $ 103 2022 64 2023 8 2024 3 2025 2 Thereafter 5 Total undiscounted cash flows $ 185

Derivative assets and liabiltie

Derivative assets and liabilties (Notes)	12 Months Ended
	Dec. 31, 2020
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 on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. We use 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: December 31, 2020 December 31, 2019 Notional Maturity Notional Maturity Mark-to-Market Derivatives (Trading) Natural Gas (BBtu): Fixed Swaps/Futures 1,603 2021-2022 1,483 2020 Basis Swaps IFERC/NYMEX (1) (44,225) 2021-2022 (35,208) 2020-2024 Power (Megawatt): Forwards 1,392,400 2021-2029 3,213,450 2020-2029 Futures 18,706 2021-2022 (353,527) 2020 Options – Puts 519,071 2021 51,615 2020 Options – Calls 2,343,293 2021 (2,704,330) 2020-2021 (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (29,173) 2021-2022 (18,923) 2020-2022 Swing Swaps IFERC 11,208 2021 (9,265) 2020 Fixed Swaps/Futures (53,575) 2021-2022 (3,085) 2020-2021 Forward Physical Contracts (11,861) 2021 (13,364) 2020-2021 NGL (MBbls) – Forwards/Swaps (5,840) 2021-2022 (1,300) 2020-2021 Crude (MBbls) – Forwards/Swaps — — 4,465 2020 Refined Products (MBbls) – Futures (2,765) 2021 (2,473) 2020-2021 Corn (thousand bushels) — — (1,210) 2020 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (30,113) 2021 (31,780) 2020 Fixed Swaps/Futures (30,113) 2021 (31,780) 2020 Hedged Item – Inventory 30,113 2021 31,780 2020 (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 December 31, 2020 December 31, 2019 July 2020 (2)(3) Forward-starting to pay a fixed rate of 3.52% and receive a floating rate $ — $ 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 400 400 (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. (3) The July 2020 interest rate swaps were terminated in January 2020. Credit Risk Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance. The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with 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 December 31, 2020 December 31, 2019 December 31, 2020 December 31, 2019 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 25 $ 24 $ (32) $ — 25 24 (32) — Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 90 319 (166) (350) Commodity derivatives 53 41 (71) (39) Interest rate derivatives — — (448) (399) 143 360 (685) (788) Total derivatives $ 168 $ 384 $ (717) $ (788) 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 December 31, 2020 December 31, 2019 December 31, 2020 December 31, 2019 Derivatives without offsetting agreements Derivative liabilities $ — $ — $ (448) $ (399) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 53 41 (71) (39) Broker cleared derivative contracts Other current assets (liabilities) 115 343 (198) (350) 168 384 (717) (788) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (44) (18) 44 18 Counterparty netting Other current assets (liabilities) (64) (318) 64 318 Total net derivatives $ 60 $ 48 $ (609) $ (452) We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date. The following tables summarize the amounts recognized with respect to our derivative financial instruments: Location of Gain (Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Years Ended December 31, 2020 2019 2018 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ — $ — $ (3) Location of Gain (Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2020 2019 2018 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Revenues $ — $ (3) $ — Commodity derivatives – Trading Cost of products sold 8 21 32 Commodity derivatives – Non-trading Cost of products sold (34) (100) (102) Interest rate derivatives Gains (losses) on interest rate derivatives (203) (241) 47 Total $ (229) $ (323) $ (23)

Retirement Benefits (Notes)

Retirement Benefits (Notes)	12 Months Ended
	Dec. 31, 2020
RETIREMENT BENEFITS
Pension and Other Postretirement Benefits Disclosure	RETIREMENT BENEFITS: Savings and Profit Sharing Plans We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of ETO, Lake Charles LNG, Sunoco LP and USAC. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $35 million, $66 million and $62 million to these 401(k) savings plans for the years ended December 31, 2020, 2019 and 2018, respectively. As a result of the economic conditions in 2020, effective June 8, 2020, the Partnership ceased employer matching and profit sharing contributions through December 31, 2020. The Partnership resumed all such contributions in 2021. Pension and Other Postretirement Benefit Plans Panhandle Postretirement benefits expense for the years ended December 31, 2020, 2019, and 2018 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees. Effective January 1, 2018, the plan was amended to extend coverage to a closed group of former employees based on certain criteria. ETC Sunoco ETC Sunoco has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by ETC Sunoco. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. ETC Sunoco has established a trust for its postretirement benefit liabilities. The funding of the trust eliminated substantially all of ETC Sunoco’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations. SemGroup SemGroup sponsors two defined benefit pension plans and a supplemental defined benefit pension plan (collectively, the “Semgroup Plans”) for certain employees. The Semgroup Plans are closed to new participants and do not accrue any additional benefits. Obligations and Funded Status Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: December 31, 2020 December 31, 2019 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Change in benefit obligation: Benefit obligation at beginning of period $ 52 $ 34 $ 208 $ 1 $ 37 $ 198 Service cost — — 1 — — 1 Interest cost 2 1 5 2 1 7 Benefits paid, net (2) (5) (16) (1) (7) (16) Actuarial (gain) loss and other 5 1 10 4 — 18 Settlements (2) — — (4) — — SemGroup Acquisition — — — 50 3 — Benefit obligation at end of period 55 31 208 52 34 208 Change in plan assets: Fair value of plan assets at beginning of period 43 — 270 1 — 241 Return on plan assets and other 5 — 28 6 — 35 Employer contributions 1 — 9 1 — 10 Benefits paid, net (2) — (16) (1) — (16) Settlements (2) — — (4) — — SemGroup Acquisition — — — 40 — — Fair value of plan assets at end of period 45 — 291 43 — 270 Amount underfunded (overfunded) at end of period $ 10 $ 31 $ (83) $ 9 $ 34 $ (62) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 108 $ — $ — $ 88 Current liabilities — (4) (2) — (5) (2) Non-current liabilities (10) (27) (23) (9) (29) (24) $ (10) $ (31) $ 83 $ (9) $ (34) $ 62 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain (loss) $ — $ 2 $ (18) $ — $ 1 $ (5) Prior service cost — — 21 — — 40 $ — $ 2 $ 3 $ — $ 1 $ 35 The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2020 December 31, 2019 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 55 $ 31 N/A $ 51 $ 34 N/A Accumulated benefit obligation 55 31 208 52 34 208 Fair value of plan assets 45 — 291 43 — 270 Components of Net Periodic Benefit Cost December 31, 2020 December 31, 2019 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Service cost $ — $ 1 $ — $ 1 Interest cost 3 5 3 7 Expected return on plan assets (2) (11) (2) (10) Prior service cost amortization — 19 — 26 Net periodic benefit cost $ 1 $ 14 $ 1 $ 24 Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2020 December 31, 2019 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 2.40 % 2.04 % 4.00 % 2.71 % The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2020 December 31, 2019 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.05 % 2.94 % 3.33 % 3.76 % Expected return on assets: Tax exempt accounts 4.57 % 7.00 % 3.37 % 7.00 % Taxable accounts — 4.75 % — 4.75 % The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness. The assumed health care cost trend weighted-average rates used to measure the expected cost of benefits covered by the plans are shown in the table below: December 31, 2020 2019 Health care cost trend rate 7.30 % 7.25 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.82 % 4.83 % Year that the rate reaches the ultimate trend rate 2027 2026 Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits. Plan Assets For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%. The investment strategy of ETC Sunoco funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, ETC Sunoco targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets. The fair value of the pension plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2020 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 1 $ 1 $ — $ — Mutual funds (1) 20 20 — — Fixed income securities 24 — 24 — Total $ 45 $ 21 $ 24 $ — (1) Comprised of approximately 100% equities as of December 31, 2020. Fair Value Measurements at December 31, 2019 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 1 $ 1 $ — $ — Mutual funds (1) 19 19 — — Fixed income securities 23 — 23 — Total $ 43 $ 20 $ 23 $ — (1) Comprised of approximately 100% equities as of December 31, 2019. The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2020 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 18 $ 18 $ — $ — Mutual funds (1) 202 202 — — Fixed income securities 71 — 71 — Total $ 291 $ 220 $ 71 $ — (1) Primarily comprised of approximately 59% equities, 40% fixed income securities and 1% cash as of December 31, 2020. Fair Value Measurements at December 31, 2019 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 14 $ 14 $ — $ — Mutual funds (1) 177 177 — — Fixed income securities 79 — 79 — Total $ 270 $ 191 $ 79 $ — (1) Primarily comprised of approximately 59% equities, 40% fixed income securities and 1% cash as of December 31, 2019. The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. Contributions We expect to contribute $6 million to pension plans and $8 million to other postretirement plans in 2021. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes. Benefit Payments Panhandle and ETC Sunoco’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: Years Pension Benefits - Funded Plans Pension Benefits - Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2021 $ 3 $ 5 $ 18 2022 4 4 18 2023 4 4 16 2024 4 3 15 2025 2 3 14 2026 - 2030 12 9 58 The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS: ET-ETO Promissory Note As of December 31, 2020 and 2019, ETO’s promissory note receivable from ET had an outstanding balance of $1.9 billion and $3.7 billion, respectively. ETO had a long-term intercompany payable to ET with a balance of $104 million as of December 31, 2019. The balance of the intercompany payable to ET was paid off in 2020. The outstanding promissory note receivable and intercompany payable are reflected on a net basis in the Partnership’s consolidated balance sheets. Interest income attributable to the promissory note receivable from ET, included in other, net in our consolidated statements of operations, for the years ended December 31, 2020 and 2019 was $147 million and $184 million, respectively. The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. The following table summarizes the revenues from related companies on our consolidated statements of operations: Years Ended December 31, 2020 2019 2018 Revenues from related companies $ 466 $ 492 $ 431 The following table summarizes the related company accounts receivable and accounts payable balances on our consolidated balance sheets: December 31, 2020 2019 Accounts receivable from related companies: ET $ — $ 8 FGT 12 50 Phillips 66 30 36 Traverse Rover LLC — 42 Other 37 31 Total accounts receivable from related companies $ 79 $ 167 Accounts payable to related companies: ET $ 150 $ — Other 27 31 Total accounts payable to related companies $ 177 $ 31

Reportable Segments (Notes)

Reportable Segments (Notes)	12 Months Ended
	Dec. 31, 2020
Reportable Segments [Abstract]
REPORTABLE SEGMENTS	REPORTABLE SEGMENTS: Our reportable segments 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 reflected in crude sales and gathering, transportation and other fees. 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 as a measure of segment performance. We define Segment 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 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: Years Ended December 31, 2020 2019 2018 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,312 $ 2,749 $ 3,428 Intersegment revenues 232 350 309 2,544 3,099 3,737 Interstate transportation and storage: Revenues from external customers 1,841 1,941 1,664 Intersegment revenues 20 22 18 1,861 1,963 1,682 Midstream: Revenues from external customers 1,944 2,280 2,090 Intersegment revenues 3,082 3,751 5,432 5,026 6,031 7,522 NGL and refined products transportation and services: Revenues from external customers 8,501 9,920 10,119 Intersegment revenues 2,012 1,721 1,004 10,513 11,641 11,123 Crude oil transportation and services: Revenues from external customers 11,674 18,447 17,236 Intersegment revenues 5 — 96 11,679 18,447 17,332 Investment in Sunoco LP: Revenues from external customers 10,653 16,590 16,982 Intersegment revenues 57 6 12 10,710 16,596 16,994 Investment in USAC: Revenues from external customers 655 678 495 Intersegment revenues 12 20 13 667 698 508 All other: Revenues from external customers 1,374 1,608 2,073 Intersegment revenues 464 81 155 1,838 1,689 2,228 Eliminations (5,884) (5,951) (7,039) Total revenues $ 38,954 $ 54,213 $ 54,087 Years Ended December 31, 2020 2019 2018 Cost of products sold: Intrastate transportation and storage $ 1,478 $ 1,909 $ 2,665 Midstream 2,598 3,577 5,145 NGL and refined products transportation and services 7,139 8,393 8,462 Crude oil transportation and services 8,838 14,832 14,384 Investment in Sunoco LP 9,654 15,380 15,872 Investment in USAC 82 91 67 All other 1,527 1,504 2,006 Eliminations (5,829) (5,885) (6,998) Total cost of products sold $ 25,487 $ 39,801 $ 41,603 Years Ended December 31, 2020 2019 2018 Depreciation, depletion and amortization: Intrastate transportation and storage $ 185 $ 184 $ 169 Interstate transportation and storage 411 387 334 Midstream 1,140 1,066 1,006 NGL and refined products transportation and services 667 613 466 Crude oil transportation and services 640 437 445 Investment in Sunoco LP 189 181 167 Investment in USAC 239 231 169 All other 198 37 87 Total depreciation, depletion and amortization $ 3,669 $ 3,136 $ 2,843 Years Ended December 31, 2020 2019 2018 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 18 $ 18 $ 19 Interstate transportation and storage 17 222 227 Midstream 24 20 26 NGL and refined products transportation and services 60 53 64 Crude oil transportation and services (2) (1) 6 All other 2 (10) 2 Total equity in earnings of unconsolidated affiliates $ 119 $ 302 $ 344 Years Ended December 31, 2020 2019 2018 Segment Adjusted EBITDA: Intrastate transportation and storage $ 863 $ 999 $ 927 Interstate transportation and storage 1,680 1,792 1,680 Midstream 1,670 1,602 1,627 NGL and refined products transportation and services 2,802 2,666 1,979 Crude oil transportation and services 2,258 2,898 2,385 Investment in Sunoco LP 739 665 638 Investment in USAC 414 420 289 All other 115 106 76 Total Segment Adjusted EBITDA 10,541 11,148 9,601 Depreciation, depletion and amortization (3,669) (3,136) (2,843) Interest expense, net of interest capitalized (2,323) (2,262) (1,709) Impairment losses (2,880) (74) (431) Gains (losses) on interest rate derivatives (203) (241) 47 Non-cash compensation expense (121) (113) (105) Unrealized losses on commodity risk management activities (71) (5) (11) Inventory valuation adjustments (82) 79 (85) Losses on extinguishments of debt (72) (2) (109) Adjusted EBITDA related to unconsolidated affiliates (628) (626) (655) Equity in earnings of unconsolidated affiliates 119 302 344 Impairment of investments in unconsolidated affiliates (129) — — Adjusted EBITDA related to discontinued operations — — 25 Other, net 68 244 30 Income from continuing operations before income tax expense 550 5,314 4,099 Income tax expense from continuing operations (239) (199) (5) Income from continuing operations 311 5,115 4,094 Loss from discontinued operations, net of income taxes — — (265) Net income $ 311 $ 5,115 $ 3,829 December 31, 2020 2019 2018 Segment assets: Intrastate transportation and storage $ 7,549 $ 6,648 $ 6,365 Interstate transportation and storage 17,730 18,111 15,081 Midstream 18,816 20,332 19,745 NGL and refined products transportation and services 21,578 19,145 18,267 Crude oil transportation and services 18,335 22,933 18,189 Investment in Sunoco LP 5,267 5,438 4,879 Investment in USAC 2,949 3,730 3,775 All other and eliminations 4,518 5,957 2,308 Total segment assets $ 96,742 $ 102,294 $ 88,609 Years Ended December 31, 2020 2019 2018 Additions to property, plant and equipment (1) : Intrastate transportation and storage $ 49 $ 124 $ 344 Interstate transportation and storage 150 375 812 Midstream 487 827 1,161 NGL and refined products transportation and services 2,403 2,976 2,381 Crude oil transportation and services 291 403 474 Investment in Sunoco LP 124 148 103 Investment in USAC 119 200 205 All other 136 215 150 Total additions to property, plant and equipment (1) $ 3,759 $ 5,268 $ 5,630 (1) Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis). December 31, 2020 2019 2018 Investments in unconsolidated affiliates: Intrastate transportation and storage $ 89 $ 88 $ 83 Interstate transportation and storage 2,278 2,524 2,070 Midstream 110 112 124 NGL and refined products transportation and services 509 461 243 Crude oil transportation and services 22 242 28 All other 47 27 88 Total investments in unconsolidated affiliates $ 3,055 $ 3,454 $ 2,636

Quarterly Financial Data (Notes

Quarterly Financial Data (Notes)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Data [Abstract]
QUARTERLY FINANCIAL DATA (UNAUDITED)	QUARTERLY FINANCIAL DATA (UNAUDITED): Summarized unaudited quarterly financial data is presented below. Quarters Ended March 31 June 30 September 30 (1) December 31 Total Year 2020: Revenues $ 11,627 $ 7,338 $ 9,955 $ 10,034 $ 38,954 Operating income 65 1,342 248 1,344 2,999 Net income (loss) (914) 719 (362) 868 311 Net income (loss) attributable to partners (720) 481 (530) 627 (142) (1) For the three months ended September 30, 2020, the net loss attributable to partners presented above reflects a change from the amount previously reported in the Partnership’s interim financial statements, due to an adjustment to the allocation of income between the general and limited partners and the noncontrolling interest in a less than wholly-owned subsidiary of the Partnership. Quarters Ended March 31 June 30 September 30 December 31 Total Year 2019: Revenues $ 13,121 $ 13,877 $ 13,495 $ 13,720 $ 54,213 Operating income 1,866 1,828 1,860 1,668 7,222 Income from continuing operations 1,219 1,282 1,250 1,364 5,115 Net income 1,219 1,282 1,250 1,364 5,115 Net income attributable to partners 950 1,003 977 1,080 4,010

Operations and Organization Ope

Operations and Organization Operations and Organization (Policies)	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Accounting, Policy [Policy Text Block]	The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity. The consolidated financial statements of the Partnership presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC.For prior periods herein, certain balances have been reclassified to assets and liabilities held for sale and certain revenues and expenses to discontinued operations. These reclassifications had no impact on net income or total equity.

Estimates, Significant Accoun_2

Estimates, Significant Accounting Policies and Balance Sheet Detials (Policy)	12 Months Ended
	Dec. 31, 2020
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Revenue Recognition	Disaggregation of revenue The major types of revenue within our reportable segments, are as follows: • 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; • fuel distribution and marketing; • all other; • investment in USAC; • contract operations; • retail parts and services; and • all other. Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Shell. Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed. The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal. The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. Midstream revenue Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported. The various types of revenue contracts our midstream segment enters into include: Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed. Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed. Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below: • In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed. • Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers. NGL and refined products transportation and services revenue Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGLs and other related hydrocarbons at market rates. These contracts were not affected by ASC 606. Crude oil transportation and services revenue Our crude oil transportation and services segment revenues are primarily derived from providing transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed. Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606. Sunoco LP’s fuel distribution and marketing revenue Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to dealers, sales to distributors, unbranded wholesale revenue, commission agent revenue, rental income and other income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin, and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method. Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. Under the new standard, to determine when control transfers to the customer, the shipping terms of the contract are assessed as shipping terms are considered a primary indicator of the transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized. Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer. Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor are recognized ratably over the term of the underlying lease. Sunoco LP’s all other revenue Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided). USAC’s contract operations revenue USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years, however USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract. Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower. USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin. The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date. There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration. USAC’s retail parts and services revenue USAC’s retail parts and service revenue is earned primarily on freight and crane charges that are directly reimbursable by USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration. All other revenue Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard.
Regulatory Accounting - Regulatory Assets and Liabilities	Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Cash, Cash Equivalents and Supplemental Cash Flow Information	Cash, Cash Equivalents and Supplemental Cash Flow Information 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.
Accounts Receivable	Accounts Receivable Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty.
Inventories	Inventories Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method. Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2020 and 2019, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $311 million and $229 million, respectively, and the inventory carrying value equaled or exceeded its replacement cost. For the years ended December 31, 2020, 2019 and 2018, the Partnership’s consolidated statements of operations did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. Inventories consisted of the following: December 31, 2020 2019 Natural gas, NGLs and refined products (1) $ 1,013 $ 833 Crude oil 287 251 Spare parts and other 439 448 Total inventories $ 1,739 $ 1,532 (1) Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of $82 million for the year ended December 31, 2020.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC-mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2020, the Partnership recognized a $58 million fixed asset impairment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. USAC recorded an $8 million impairment of compression equipment as a result of its evaluations of the future deployment of its idle fleet. In 2019, USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets. Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York. In 2018, USAC recognized a $9 million fixed asset impairment related to certain idle compressor assets. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the
Advances to and Investment in Affiliates	Investments in Unconsolidated AffiliatesWe own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. During the year ended December 31, 2020, the Partnership recorded an impairment of its investment in White Cliffs of $129 million due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition and related purchase price allocation in December 2019.
Other Noncurrent Assets [Policy Text Block]	Other Non-Current Assets, netOther non-current assets, net are stated at cost less accumulated amortization.
Intangible Assets Disclosure [Text Block]	Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: December 31, 2020 December 31, 2019 Gross Carrying Accumulated Gross Carrying Accumulated Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 7,513 $ (2,117) $ 7,535 $ (1,743) Patents (10 years) 48 (40) 48 (35) Trade Names (20 years) 66 (35) 66 (31) Other (5 to 20 years) 19 (15) 19 (12) Total amortizable intangible assets 7,646 (2,207) 7,668 (1,821) Non-amortizable intangible assets: Trademarks 295 — 295 — Other 12 — 12 — Total non-amortizable intangible assets 307 — 307 — Total intangible assets $ 7,953 $ (2,207) $ 7,975 $ (1,821) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2020 2019 2018 Reported in depreciation, depletion and amortization expense $ 403 $ 308 $ 321 Estimated aggregate amortization of intangible assets for the next five years is as follows: Years Ending December 31: 2021 $ 393 2022 379 2023 363 2024 349 2025 335 We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
Goodwill	Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Intrastate Interstate Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services Investment in Sunoco LP Investment in USAC All Other Total Balance, December 31, 2018 $ 10 $ 196 $ 492 $ 693 $ 1,167 $ 1,559 $ 619 $ 149 $ 4,885 Acquired — 42 — — 230 — — 35 307 Impaired — (12) (9) — — — — — (21) Other — — — — — (4) — — (4) Balance, December 31, 2019 10 226 483 693 1,397 1,555 619 184 5,167 Acquired — — — — — 9 — — 9 Impaired (10) (226) (483) — (1,279) — (619) (198) (2,815) Other — — — — (66) — — 96 30 Balance, December 31, 2020 $ — $ — $ — $ 693 $ 52 $ 1,564 $ — $ 82 $ 2,391 Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. The Partnership performed the interim impairment tests consistent with our approach for annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized goodwill impairments of $483 million related to our Ark-La-Tex and South Texas operations within the midstream segment, $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to contractually scheduled reductions in payments for the remainder of the contract term, and $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations. During the third quarter of 2020, the Partnership performed interim impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $1.28 billion related to our crude operations, $132 million related to our Energy Transfer Canada operations within the all other segment and $43 million related to our interstate operations primarily due to decreases in projected future cash flow as a result of the overall market demand decline. During the fourth quarter of 2020, the Partnership performed annual impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $10 million related to our intrastate operations, $11 million related to our PEI operations and $15 million related to our Natural Resources operations within the all other segment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. No other impairments of the Partnership’s goodwill were identified. During the third quarter of 2019, the Partnership recognized a goodwill impairment of $12 million related to the Southwest Gas operations within the interstate segment primarily due to decreases in projected future revenues and cash flows. During the fourth quarter of 2019, the Partnership recognized a goodwill impairment of $9 million related to our North Central operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows. During the fourth quarter of 2018, the Partnership recognized goodwill impairments of $378 million related to our Northeast operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. These changes in assumptions reflect delays in the construction of third-party takeaway capacity in the Northeast. The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result
Asset Retirement Obligation	Asset Retirement Obligations We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an ARO in the periods in which management can reasonably estimate the settlement dates. As of December 31, 2020 and 2019, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $270 million and $247 million, respectively. For the years ended December 31, 2020, 2019 and 2018 aggregate accretion expense related to AROs was $16 million, $5 million and $13 million, respectively. Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2020 and 2019, in most cases because the settlement dates were indeterminable. Although a number of onshore assets in our systems are subject to agreements or regulations that give rise to an ARO upon discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Our subsidiaries also have legal obligations for several other assets at previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, our subsidiaries are legally or contractually required to abandon in place or remove the asset. We believe we may have additional AROs related to pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP also has AROs related to the estimated future cost to remove underground storage tanks. Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely. As of December 31, 2020 and 2019, other non-current assets on the Partnership’s consolidated balance sheets included $34 million and $31 million, respectively, of funds that were legally restricted for the purpose of settling AROs.
Accrued and Other Current Liabilities	Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may be required when customers exceed their credit limits or do not qualify for open credit.
Redeemable Noncontrolling Interest [Text Block]	Redeemable Noncontrolling Interests Our redeemable noncontrolling interests relate to certain preferred unitholders of one of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in one of our consolidated subsidiaries that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable noncontrolling interests on our consolidated balance sheets. See Note 6 for further information.
Environmental Costs, Policy [Policy Text Block]	Environmental Remediation We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. 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 debt obligations as of December 31, 2020 was $56.13 billion and $51.37 billion, respectively. As of December 31, 2019, the aggregate fair value and carrying amount of our debt obligations was $54.66 billion and $50.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units 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 year ended December 31, 2020, no transfers were made between any levels within the fair value hierarchy.
Contributions in Aid of Construction Costs	Contributions in Aid of Construction CostsOn certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs	Shipping and Handling CostsShipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.
Costs and Expenses	Costs and Expenses Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel. We record the collection of taxes to be remitted to government authorities on a net basis, except for consumer excise taxes collected by Sunoco LP on sales of refined products and merchandise which are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income. For the years ended December 31, 2020, 2019 and 2018, excise taxes collected by Sunoco LP were $301 million, $386 million and $370 million, respectively.
Consolidation, Subsidiary Stock Issuances, Policy [Policy Text Block]	Issuances of Subsidiary UnitsWe record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interests are adjusted as a change in partners’ capital.
Income Tax, Policy [Policy Text Block]	Income Taxes ETO is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to our preferred unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Fifth Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”). As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and Internal Revenue Service (“IRS”) pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETO would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2020, 2019 and 2018, our qualifying income met the statutory requirement. The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Sunoco Property Company LLC and Aloha. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques. At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period. If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations. Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
Share-based Payment Arrangement [Policy Text Block]	Non-Cash Compensation For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of the underlying common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of the underlying common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pension and Other Postretirement Plans, Policy [Policy Text Block]	Pensions and Other Postretirement Benefit Plans The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income (Loss)	Allocation of Income For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for United States Federal income tax purposes and may not be comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Subsequent to the Energy Transfer Merger, our general partner owns a non-economic interest in us and, therefore, our net income for partners’ capital and statement of operations presentation purposes is allocated entirely to the Limited Partners.

Revenue (Policies)

Revenue (Policies)	12 Months Ended
	Dec. 31, 2020
Revenue Recognition and Deferred Revenue [Abstract]
Revenue, Remaining Performance Obligation, Provision for Loss [Policy Text Block]	Performance Obligations At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contracts, only the fixed component of the contracts are included in the table below. Sunoco LP distributes fuel under long-term contracts to branded distributors, branded and unbranded third-party dealers, and branded and unbranded retail fuel outlets. Sunoco LP branded supply contracts with distributors generally have both time and volume commitments that establish contract duration. These contracts have an initial term of approximately nine years, with an estimated, volume-weighted term remaining of approximately four years. As part of the asset purchase agreement with 7-Eleven, Sunoco LP and 7-Eleven and SEI Fuel (collectively, the “Distributor”) have entered into a 15-year take-or-pay fuel supply agreement in which the Distributor is required to purchase a volume of fuel that provides Sunoco LP a minimum amount of gross profit annually. Sunoco LP expects to recognize this revenue in accordance with the contract as Sunoco LP transfers control of the product to the customer. However, in case of annual shortfall Sunoco LP will recognize the amount payable by the Distributor at the sooner of the time at which the Distributor makes up the shortfall or becomes contractually or operationally unable to do so. The transaction price of the contract is variable in nature, fluctuating based on market conditions. The Partnership has elected to take the practical expedient not to estimate the amount of variable consideration allocated to wholly unsatisfied performance obligations. In some contractual arrangements, Sunoco LP grants dealers a franchise license to operate Sunoco LP’s retail stores over the life of a franchise agreement. In return for the grant of the retail store license, the dealer makes a one-time nonrefundable franchise fee payment to Sunoco LP plus sales based royalties payable to Sunoco LP at a contractual rate during the period of the franchise agreement. Under the requirements of ASC Topic 606, the franchise license is deemed to be a symbolic license for which recognition of revenue over time is the most appropriate measure of progress toward complete satisfaction of the performance obligation. Revenue from this symbolic license is recognized evenly over the life of the franchise agreement.
Revenue Recognition, Deferred Revenue [Policy Text Block]	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 minimum fee, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. 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 $ 394 Additions 651 Revenue recognized (680) Balance, December 31, 2019 365 Additions 771 Revenue recognized (846) Balance, December 31, 2020 $ 290
Revenue Recognition	Disaggregation of revenue The major types of revenue within our reportable segments, are as follows: • 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; • fuel distribution and marketing; • all other; • investment in USAC; • contract operations; • retail parts and services; and • all other. Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Shell. Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed. The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal. The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. Midstream revenue Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported. The various types of revenue contracts our midstream segment enters into include: Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed. Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed. Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below: • In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed. • Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers. NGL and refined products transportation and services revenue Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGLs and other related hydrocarbons at market rates. These contracts were not affected by ASC 606. Crude oil transportation and services revenue Our crude oil transportation and services segment revenues are primarily derived from providing transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed. Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606. Sunoco LP’s fuel distribution and marketing revenue Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to dealers, sales to distributors, unbranded wholesale revenue, commission agent revenue, rental income and other income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin, and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method. Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. Under the new standard, to determine when control transfers to the customer, the shipping terms of the contract are assessed as shipping terms are considered a primary indicator of the transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized. Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer. Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor are recognized ratably over the term of the underlying lease. Sunoco LP’s all other revenue Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided). USAC’s contract operations revenue USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years, however USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract. Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower. USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin. The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date. There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration. USAC’s retail parts and services revenue USAC’s retail parts and service revenue is earned primarily on freight and crane charges that are directly reimbursable by USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration. All other revenue Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard.

Lease Accounting (Policies)

Lease Accounting (Policies)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Lessee, Leases [Policy Text Block]	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 The Partnership leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Our 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 years ended December 31, 2020 and 2019 was $144 million and $149 million, respectively.

Estimates, Significant Accoun_3

Estimates, Significant Accounting Policies and Balance Sheet Detials (Tables)	12 Months Ended
	Dec. 31, 2020
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Schedule of Accounts Payable and Accrued Liabilities [Table Text Block]	Accrued and other current liabilities consisted of the following: December 31, 2020 2019 Interest payable $ 598 $ 576 Customer advances and deposits 161 123 Accrued capital expenditures 604 1,334 Accrued wages and benefits 109 217 Taxes payable other than income taxes 446 263 Exchanges payable 127 67 Other 724 756 Total accrued and other current liabilities $ 2,769 $ 3,336
Net change in operating assets and liabilities (net of acquisitions)	The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2020 2019 2018 Accounts receivable $ 1,163 $ (473) $ 506 Accounts receivable from related companies (290) (17) 128 Inventories (271) (20) 237 Other current assets 189 107 7 Other non-current assets, net (7) (155) (119) Accounts payable (1,327) 148 (769) Accounts payable to related companies 517 (92) (206) Accrued and other current liabilities 161 23 365 Other non-current liabilities 8 (134) (34) Price risk management assets and liabilities, net 69 218 (53) Net change in operating assets and liabilities, net of effects of acquisitions $ 212 $ (395) $ 62
Non-cash investing and financing activities and supplemental cash flow information	Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2020 2019 2018 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 604 $ 1,334 $ 1,030 Lease assets obtained in exchange for new lease liabilities 42 68 — Net gains (losses) from subsidiary common unit transactions — — (127) SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 2,086 $ 1,799 $ 1,537 Cash paid for income taxes (net of refunds) (64) 30 508
Inventory	Inventories consisted of the following: December 31, 2020 2019 Natural gas, NGLs and refined products (1) $ 1,013 $ 833 Crude oil 287 251 Spare parts and other 439 448 Total inventories $ 1,739 $ 1,532
Other Current Assets	Other current assets consisted of the following: December 31, 2020 2019 Deposits paid to vendors $ 75 $ 95 Prepaid expenses and other 147 196 Total other current assets $ 222 $ 291
Components and useful lives of property, plant and equipment	Components and useful lives of property, plant and equipment were as follows: December 31, 2020 2019 Land and improvements $ 1,233 $ 1,232 Buildings and improvements (1 to 45 years) 4,204 2,631 Pipelines and equipment (5 to 83 years) 69,120 64,678 Product storage and related facilities and equipment (2 to 83 years) 6,393 5,898 Right of way (20 to 83 years) 5,091 4,851 Other (1 to 48 years) 1,808 1,509 Construction work-in-process 5,771 8,495 Property, plant and equipment, gross 93,620 89,294 Less: Accumulated depreciation and depletion (18,801) (15,398) Property, plant and equipment, net $ 74,819 $ 73,896
Depreciation expense	We recognized the following amounts for the periods presented: Years Ended December 31, 2020 2019 2018 Depreciation, depletion and amortization expense $ 3,266 $ 2,828 $ 2,522 Capitalized interest 189 166 294
Other non-current assets	Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2020 2019 Crude pipeline linefill and tank bottoms $ 517 $ 496 Regulatory assets 41 42 Pension assets 103 84 Deferred charges 188 178 Restricted funds 179 178 Other 629 593 Total other non-current assets, net $ 1,657 $ 1,571 Restricted funds includes an immaterial amount of restricted cash primarily held in our wholly-owned captive insurance companies.
Components and useful lives of intangibles assets	Components and useful lives of intangible assets were as follows: December 31, 2020 December 31, 2019 Gross Carrying Accumulated Gross Carrying Accumulated Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 7,513 $ (2,117) $ 7,535 $ (1,743) Patents (10 years) 48 (40) 48 (35) Trade Names (20 years) 66 (35) 66 (31) Other (5 to 20 years) 19 (15) 19 (12) Total amortizable intangible assets 7,646 (2,207) 7,668 (1,821) Non-amortizable intangible assets: Trademarks 295 — 295 — Other 12 — 12 — Total non-amortizable intangible assets 307 — 307 — Total intangible assets $ 7,953 $ (2,207) $ 7,975 $ (1,821)
Amortization expense of intangible assets	Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2020 2019 2018 Reported in depreciation, depletion and amortization expense $ 403 $ 308 $ 321
Amortization expense, expected	Estimated aggregate amortization of intangible assets for the next five years is as follows: Years Ending December 31: 2021 $ 393 2022 379 2023 363 2024 349 2025 335
Changes in carrying amount of goodwill	Changes in the carrying amount of goodwill were as follows: Intrastate Interstate Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services Investment in Sunoco LP Investment in USAC All Other Total Balance, December 31, 2018 $ 10 $ 196 $ 492 $ 693 $ 1,167 $ 1,559 $ 619 $ 149 $ 4,885 Acquired — 42 — — 230 — — 35 307 Impaired — (12) (9) — — — — — (21) Other — — — — — (4) — — (4) Balance, December 31, 2019 10 226 483 693 1,397 1,555 619 184 5,167 Acquired — — — — — 9 — — 9 Impaired (10) (226) (483) — (1,279) — (619) (198) (2,815) Other — — — — (66) — — 96 30 Balance, December 31, 2020 $ — $ — $ — $ 693 $ 52 $ 1,564 $ — $ 82 $ 2,391 Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. The Partnership performed the interim impairment tests consistent with our approach for annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized goodwill impairments of $483 million related to our Ark-La-Tex and South Texas operations within the midstream segment, $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to contractually scheduled reductions in payments for the remainder of the contract term, and $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations. During the third quarter of 2020, the Partnership performed interim impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $1.28 billion related to our crude operations, $132 million related to our Energy Transfer Canada operations within the all other segment and $43 million related to our interstate operations primarily due to decreases in projected future cash flow as a result of the overall market demand decline. During the fourth quarter of 2020, the Partnership performed annual impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $10 million related to our intrastate operations, $11 million related to our PEI operations and $15 million related to our Natural Resources operations within the all other segment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. No other impairments of the Partnership’s goodwill were identified.
Summary of fair value of financials	The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2020 and 2019 based on inputs used to derive their fair values: Fair Value Total Fair Value Measurements at December 31, 2020 Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 12 $ 12 $ — Swing Swaps IFERC 1 — 1 Fixed Swaps/Futures 13 13 — Forward Physical Contracts 5 — 5 Power: Forwards 4 — 4 Futures 2 2 — Options – Calls 1 1 — NGLs – Forwards/Swaps 127 127 — Refined Products – Futures 3 3 — Crude – Forwards/Swaps — — — Total commodity derivatives 168 158 10 Other non-current assets 34 22 12 Total assets $ 202 $ 180 $ 22 Liabilities: Interest rate derivatives $ (448) $ — $ (448) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (11) (11) — Swing Swaps IFERC (3) — (3) Fixed Swaps/Futures (13) (13) — Forward Physical Contracts (1) — (1) Power: Forwards — — — Futures (3) (3) — NGLs – Forwards/Swaps (227) (227) — Refined Products – Futures (11) (11) — Total commodity derivatives (269) (265) (4) Total liabilities $ (717) $ (265) $ (452) Fair Value Total Fair Value Measurements at December 31, 2019 Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 17 $ 17 $ — Swing Swaps IFERC 1 — 1 Fixed Swaps/Futures 65 65 — Forward Physical Contracts 3 — 3 Power: Power – Forwards 11 — 11 Futures 4 4 — Options – Puts 1 1 — Options – Calls 1 1 — NGLs – Forwards/Swaps 260 260 — Refined Products – Futures 8 8 — Crude - Forwards/Swaps 13 13 — Total commodity derivatives 384 369 15 Other non-current assets 31 20 11 Total assets $ 415 $ 389 $ 26 Liabilities: Interest rate derivatives $ (399) $ — $ (399) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (49) (49) — Swing Swaps IFERC (1) — (1) Fixed Swaps/Futures (43) (43) — Power: Forwards (5) — (5) Futures (3) (3) — NGLs – Forwards/Swaps (278) (278) — Refined Products – Futures (10) (10) — Total commodity derivatives (389) (383) (6) Total liabilities $ (788) $ (383) $ (405)

Acquisitions, Divestitures an_2

Acquisitions, Divestitures and Related Transactions (Tables)	12 Months Ended
	Dec. 31, 2020
Disposal Groups, Including Discontinued Operations [Table Text Block]	There were no results of operations associated with discontinued operations for the years ended December 31, 2020 and 2019. The results of operations associated with discontinued operations for the year ended December 31, 2018 are presented in the following table: Year Ended December 31, 2018 REVENUES $ 349 COSTS AND EXPENSES Cost of products sold 305 Operating expenses 61 Selling, general and administrative 7 Total costs and expenses 373 OPERATING LOSS (24) OTHER EXPENSE Interest expense, net 2 Loss on extinguishment of debt 20 Other, net 61 LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (107) Income tax expense 158 LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES $ (265)
SemGroup [Member]
Summary Of Preliminary Assets And Liability Acquired	At December 5, 2019 Total current assets $ 794 Property, plant and equipment 3,891 Other non-current assets 617 Goodwill 295 Intangible assets 460 Total assets $ 6,057 Total current liabilities $ 629 Long-term debt, less current maturities (1) 2,576 Other non-current liabilities 197 Energy Transfer Canada Preferred shares 241 Total liabilities 3,643 Noncontrolling interest 822 Partners’ capital 1,592 Total liabilities and partners’ capital $ 6,057
USA Compression Partners, LP [Member]
Summary Of Preliminary Assets And Liability Acquired	Summary of Assets Acquired and Liabilities Assumed The USAC Transaction was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. The total purchase price was allocated as follows: At April 2, 2018 Total current assets (2) $ 786 Property, plant and equipment 1,332 Other non-current assets 15 Goodwill (1) 366 Intangible assets 222 Total assets $ 2,721 Total current liabilities $ 110 Long-term debt, less current maturities 1,527 Other non-current liabilities 2 Total liabilities 1,639 Noncontrolling interest 832 Partners’ capital 250 Total liabilities and partners’ capital $ 2,721 (1) None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations.

Advances to and Investments i_2

Advances to and Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2020
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Investments in and Advances to Affiliates [Table Text Block]	The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2020 and 2019 were as follows: December 31, 2020 2019 Citrus $ 1,867 $ 1,876 FEP 4 218 MEP 406 429 White Cliffs 274 436 Others 504 495 Total $ 3,055 $ 3,454 The following table presents equity in earnings (losses) of unconsolidated affiliates: Years Ended December 31, 2020 2019 2018 Citrus $ 162 $ 148 $ 141 FEP (1) (139) 59 55 MEP (6) 15 31 White Cliffs 20 4 — Other 82 76 117 Total equity in earnings of unconsolidated affiliates $ 119 $ 302 $ 344
Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block]	Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP and White Cliffs (on a 100% basis) for all periods presented, except as noted below: December 31, 2020 2019 Current assets $ 227 $ 247 Property, plant and equipment, net 7,339 7,680 Other assets 58 40 Total assets $ 7,624 $ 7,967 Current liabilities $ 600 $ 738 Non-current liabilities 3,298 3,242 Equity 3,726 3,987 Total liabilities and equity $ 7,624 $ 7,967 Years Ended December 31, 2020 2019 2018 Revenue $ 1,243 $ 1,192 $ 1,249 Operating income 6 683 723 Net income (loss) (199) 443 460 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

Debt Obligations (Tables)

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Obligations [Abstract]
Debt instruments	Our debt obligations consist of the following: December 31, 2020 2019 ETO Debt 5.50% Senior Notes due February 15, 2020 (1) $ — $ 250 5.75% Senior Notes due September 1, 2020 (1) — 400 4.15% Senior Notes due October 1, 2020 (1) — 1,050 7.50% Senior Notes due October 15, 2020 (1) — 1,135 4.40% Senior Notes due April 1, 2021 (2) 600 600 4.65% Senior Notes due June 1, 2021 (2) 800 800 5.20% Senior Notes due February 1, 2022 1,000 1,000 4.65% Senior Notes due February 15, 2022 300 300 5.875% Senior Notes due March 1, 2022 900 900 5.00% Senior Notes due October 1, 2022 700 700 3.45% Senior Notes due January 15, 2023 350 350 3.60% Senior Notes due February 1, 2023 800 800 4.25% Senior Notes due March 15, 2023 995 995 4.20% Senior Notes due September 15, 2023 500 500 4.50% Senior Notes due November 1, 2023 600 600 5.875% Senior Notes due January 15, 2024 1,127 1,127 4.90% Senior Notes due February 1, 2024 350 350 7.60% Senior Notes due February 1, 2024 277 277 4.25% Senior Notes due April 1, 2024 500 500 4.50% Senior Notes due April 15, 2024 750 750 9.00% Debentures due November 1, 2024 65 65 4.05% Senior Notes due March 15, 2025 1,000 1,000 2.90% Senior Notes due May 15, 2025 1,000 — 5.95% Senior Notes due December 1, 2025 400 400 4.75% Senior Notes due January 15, 2026 1,000 1,000 3.90% Senior Notes due July 15, 2026 550 550 4.20% Senior Notes due April 15, 2027 600 600 5.50% Senior Notes due June 1, 2027 956 956 4.00% Senior Notes due October 1, 2027 750 750 4.95% Senior Notes due June 15, 2028 1,000 1,000 5.25% Senior Notes due April 15, 2029 1,500 1,500 8.25% Senior Notes due November 15, 2029 267 267 3.75% Senior Note due May 15, 2030 1,500 — 4.90% Senior Notes due March 15, 2035 500 500 6.625% Senior Notes due October 15, 2036 400 400 5.80% Senior Notes due June 15, 2038 500 500 7.50% Senior Notes due July 1, 2038 550 550 6.85% Senior Notes due February 15, 2040 250 250 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.30% Senior Notes due April 1, 2044 700 700 5.15% Senior Notes due March 15, 2045 1,000 1,000 5.35% Senior Notes due May 15, 2045 800 800 6.125% Senior Notes due December 15, 2045 1,000 1,000 5.30% Senior Notes due April 15, 2047 900 900 5.40% Senior Notes due October 1, 2047 1,500 1,500 6.00% Senior Notes due June 15, 2048 1,000 1,000 6.25% Senior Notes due April 15, 2049 1,750 1,750 5.00% Senior Notes due May 15, 2050 2,000 — Floating Rate Junior Subordinated Notes due November 1, 2066 546 546 ETO $2.00 billion Term Loan facility due October 2022 2,000 2,000 ETO $5.00 billion Revolving Credit Facility due December 2023 3,103 4,214 Unamortized premiums, discounts and fair value adjustments, net (17) (5) Deferred debt issuance costs (215) (207) 42,654 42,120 Transwestern Debt 5.36% Senior Notes due December 9, 2020 (1) — 175 5.89% Senior Notes due May 24, 2022 150 150 5.66% Senior Notes due December 9, 2024 175 175 6.16% Senior Notes due May 24, 2037 75 75 Deferred debt issuance costs — (1) 400 574 Panhandle Debt 7.60% Senior Notes due February 1, 2024 82 82 7.00% Senior Notes due July 15, 2029 66 66 8.25% Senior Notes due November 15, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 10 11 245 246 Bakken Project Debt 3.625% Senior Notes due April 1, 2022 650 650 3.90% Senior Notes due April 1, 2024 1,000 1,000 4.625% Senior Notes due April 1, 2029 850 850 Unamortized premiums, discounts and fair value adjustments, net (3) (3) Deferred debt issuance costs (13) (16) 2,484 2,481 Sunoco LP Debt 4.875% Senior Notes Due January 15, 2023 436 1,000 5.50% Senior Notes Due February 15, 2026 800 800 6.00% Senior Notes Due April 15, 2027 600 600 5.875% Senior Notes Due March 15, 2028 400 400 4.50% Senior Notes due May 15, 2029 800 — Sunoco LP $1.50 billion Revolving Credit Facility due July 2023 — 162 Lease-related obligations 103 135 Deferred debt issuance costs (27) (26) 3,112 3,071 USAC Debt 6.875% Senior Notes due April 1, 2026 725 725 6.875% Senior Notes due September 1, 2027 750 750 USAC $1.60 billion Revolving Credit Facility due April 2023 474 403 Deferred debt issuance costs (22) (26) 1,927 1,852 SemGroup Debt HFOTCO Tax Exempt Notes due 2050 225 225 Energy Transfer Canada Revolver due February 25, 2024 57 92 Energy Transfer Canada Term Loan A due February 25, 2024 261 269 Unamortized premiums, discounts and fair value adjustments, net — 1 Deferred debt issuance costs (2) (3) 541 584 Other 3 2 Total debt 51,366 50,930 Less: Current maturities of long-term debt 21 26 Long-term debt, less current maturities $ 51,345 $ 50,904
Future maturities of long-term debt	The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $289 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: 2021 $ 1,420 2022 5,731 2023 7,287 2024 4,598 2025 2,408 Thereafter 30,211 Total $ 51,655

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2020
Schedule of Preferred Units [Table Text Block]	The following table summarizes changes in the amounts of our Series A, Series B, Series C, Series D, Series E, Series F and Series G preferred units for the years ended December 31, 2020, 2019 and 2018 were as follows: Preferred Unitholders Series A Series B Series C Series D Series E Series F Series G Total Balance, December 31, 2017 $ 944 $ 547 $ — $ — $ — $ — $ — $ 1,491 Distributions to partners (44) (27) (18) (11) — — — (100) Units issued for cash — — 436 431 — — — 867 Other, net (1) — (1) (1) — — — (3) Net income 59 36 23 15 — — — 133 Balance, December 31, 2018 958 556 440 434 — — — 2,388 Distributions to partners (59) (37) (33) (34) (34) — — (197) Units issued for cash — — — — 780 — — 780 Other, net — — — — (1) — — (1) Net income 59 37 33 34 41 — — 204 Balance, December 31, 2019 958 556 440 434 786 — — 3,174 Distributions to partners (59) (37) (33) (34) (61) (27) (64) (315) Units issued for cash — — — — — 494 1,086 1,580 Other, net — — — — — (2) (2) (4) Net income 59 37 33 34 61 31 74 329 Balance, December 31, 2020 $ 958 $ 556 $ 440 $ 434 $ 786 $ 496 $ 1,094 $ 4,764
Comprehensive Income (Loss) Note [Text Block]	The following table presents the components of AOCI, net of tax: December 31, 2020 2019 Available-for-sale securities $ 18 $ 13 Foreign currency translation adjustment 7 (5) Actuarial loss related to pensions and other postretirement benefits (7) (25) Investments in unconsolidated affiliates, net (14) (1) Subtotal 4 (18) Amounts attributable to noncontrolling interest 2 — Total AOCI, net of tax $ 6 $ (18)
Schedule of taxes related to accumulated other comprehensive income [Table Text Block]	The table below sets forth the tax amounts included in the respective components of other comprehensive income: December 31, 2020 2019 Available-for-sale securities $ (1) $ (1) Foreign currency translation adjustment 8 2 Actuarial loss relating to pension and other postretirement benefits 3 8 Total $ 10 $ 9
USA Compression Partners, LP [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows: Quarter Ended Record Date Payment Date Rate March 31, 2018 May 1, 2018 May 11, 2018 $ 0.5250 June 30, 2018 July 30, 2018 August 10, 2018 0.5250 September 30, 2018 October 29, 2018 November 9, 2018 0.5250 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 December 31, 2019 January 27, 2020 February 7, 2020 0.5250 March 31, 2020 April 27, 2020 May 8, 2020 0.5250 June 30, 2020 July 31, 2020 August 10, 2020 0.5250 September 30, 2020 October 26, 2020 November 6, 2020 0.5250 December 31, 2020 January 25, 2021 February 5, 2021 0.5250
Sunoco LP [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2017 February 6, 2018 February 14, 2018 $ 0.8255 March 31, 2018 May 7, 2018 May 15, 2018 0.8255 June 30, 2018 August 7, 2018 August 15, 2018 0.8255 September 30, 2018 November 6, 2018 November 14, 2018 0.8255 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 December 31, 2019 February 7, 2020 February 19, 2020 0.8255 March 31, 2020 May 7, 2020 May 19, 2020 0.8255 June 30, 2020 August 7, 2020 August 19, 2020 0.8255 September 30, 2020 November 6, 2020 November 19, 2020 0.8255 December 31, 2020 February 8, 2021 February 19, 2021 0.8255
Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution [Table Text Block]	The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Marginal Percentage Interest in Distributions Total Quarterly Distribution Target Amount Common Unitholders Holder of IDRs Minimum Quarterly Distribution $0.4375 100% —% First Target Distribution $0.4375 to $0.503125 100% —% Second Target Distribution $0.503125 to $0.546875 85% 15% Third Target Distribution $0.546875 to $0.656250 75% 25% Thereafter Above $0.656250 50% 50%

Unit-Based Compensation Plans_2

Unit-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2020
Deferred Compensation Arrangements [Abstract]
Share-based Compensation Arrangements by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding [Table Text Block]	The following table summarizes the activity of the Subsidiary Unit Awards: Sunoco LP USAC Number of Weighted Average Number of Weighted Average Unvested awards as of December 31, 2019 2.1 $ 29.21 1.8 $ 15.09 Awards granted 0.7 28.63 0.7 12.55 Awards vested (0.5) 30.47 (0.2) 17.27 Awards forfeited (0.2) 29.11 (0.2) 15.36 Unvested awards as of December 31, 2020 2.1 28.63 2.1 14.88
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value [Table Text Block]	The following table summarizes the weighted average grant-date fair value per unit award granted: Years Ended December 31, 2020 2019 2018 Sunoco LP $ 28.63 $ 30.70 $ 27.67 USAC 12.55 15.88 15.47

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows: Years Ended December 31, 2020 2019 2018 Current expense (benefit): Federal $ (6) $ (20) $ (7) State 32 (2) 20 Foreign 1 — — Total 27 (22) 13 Deferred expense (benefit): Federal 178 176 183 State 41 45 (191) Foreign (7) — — Total 212 221 (8) Total income tax expense $ 239 $ 199 $ 5
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Historically, our effective tax rate has differed 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. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2020, 2019 and 2018 is as follows: Years Ended December 31, 2020 2019 2018 Income tax expense at United States statutory rate $ 116 $ 1,116 $ 861 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax 54 (925) (730) Noncontrolling interests 16 — — State income taxes (net of federal income tax effects) 58 14 (125) Dividend received deduction — (3) (5) Foreign (7) — — Other 2 (3) 4 Income tax expense $ 239 $ 199 $ 5
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: December 31, 2020 2019 Deferred income tax assets: Net operating losses, alternative minimum tax credit and other carryforwards $ 1,047 $ 936 Pension and other postretirement benefits — 7 Other 34 85 Total deferred income tax assets 1,081 1,028 Valuation allowance (134) (95) Net deferred income tax assets $ 947 $ 933 Deferred income tax liabilities: Property, plant and equipment $ (263) $ (464) Investments in affiliates (3,994) (3,547) Trademarks (77) (72) Other (5) (21) Total deferred income tax liabilities (4,339) (4,104) Net deferred income taxes $ (3,392) $ (3,171)
Schedule of Unrecognized Tax Benefits Rollforward [Table Text Block]	The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2020 2019 2018 Balance at beginning of year $ 94 $ 624 $ 609 Additions attributable to tax positions taken in the current year — — 8 Additions attributable to tax positions taken in prior years — 11 7 Reduction attributable to tax positions taken in prior years — (541) — Lapse of statute (4) — — Balance at end of year $ 90 $ 94 $ 624

Regulatory Matters, Commitmen_2

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Tables)	12 Months Ended
	Dec. 31, 2020
Environmental Exit Costs by Cost [Table Text Block]	December 31, 2020 2019 Current $ 44 $ 46 Non-current 262 274 Total environmental liabilities $ 306 $ 320
Right of way (20 to 83 years)
Lessee, Operating Lease, Disclosure [Table Text Block]	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: Years Ended December 31, 2020 2019 2018 ROW expense $ 47 $ 45 $ 46

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2020
Revenue Recognition and Deferred Revenue [Abstract]
Contract with Customer, Asset and Liability [Table Text Block]	The following table summarizes the consolidated activity of our contract liabilities: Contract Liabilities Balance, December 31, 2018 $ 394 Additions 651 Revenue recognized (680) Balance, December 31, 2019 365 Additions 771 Revenue recognized (846) Balance, December 31, 2020 $ 290 The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2020 and 2019 were as follows: December 31, 2020 December 31, 2019 Contract balances: Contract asset $ 121 $ 117 Accounts receivable from contracts with customers 256 366
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]	As of December 31, 2020, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $40.35 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below: Years Ending December 31, 2021 2022 2023 Thereafter Total Revenue expected to be recognized on contracts with customers existing as of December 31, 2020 $ 5,120 $ 5,475 $ 5,051 $ 24,701 $ 40,347

Lease Accounting (Tables)

Lease Accounting (Tables)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
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 December 31, 2020 and 2019 were as follows: December 31, 2020 2019 Operating leases: Lease right-of-use assets, net $ 863 $ 935 Operating lease current liabilities 53 60 Accrued and other current liabilities 1 1 Non-current operating lease liabilities 837 901 Finance leases: Property, plant and equipment, net $ 1 1 Lease right-of-use assets, net 3 29 Accrued and other current liabilities 1 1 Current maturities of long-term debt 1 6 Long-term debt, less current maturities 6 26 Other non-current liabilities 1 2
Lease, Cost [Table Text Block]	The components of lease expense for the years ended December 31, 2020 and 2019 were as follows: Year Ended December 31, Income Statement Location 2020 2019 Operating lease costs: Operating lease cost Cost of goods sold $ 14 $ 28 Operating lease cost Operating expenses 75 73 Operating lease cost Selling, general and administrative 17 16 Total operating lease costs 106 117 Finance lease costs: Amortization of lease assets Depreciation, depletion and amortization 3 6 Interest on lease liabilities Interest expense, net of capitalized interest 1 1 Total finance lease costs 4 7 Short-term lease cost Operating expenses 31 42 Variable lease cost Operating expenses 16 17 Lease costs, gross 157 183 Less: Sublease income Other revenue 48 47 Lease costs, net $ 109 $ 136
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	The weighted average remaining lease terms and weighted average discount rates as of December 31, 2020 and 2019 were as follows: December 31, 2020 2019 Weighted-average remaining lease term (years): Operating leases 22 24 Finance leases 9 5 Weighted-average discount rate (%): Operating leases 5 % 5 % Finance leases 8 % 5 % Maturities of lease liabilities as of December 31, 2020 are as follows: Operating leases Finance leases Total 2021 $ 99 $ 2 $ 101 2022 85 2 87 2023 79 2 81 2024 76 1 77 2025 75 1 76 Thereafter 1,140 4 1,144 Total lease payments 1,554 12 1,566 Less: present value discount 664 3 667 Present value of lease liabilities $ 890 $ 9 $ 899
Schedule of additional lease information [Table Text Block]	Cash flows and non-cash activity related to leases for the years ended December 31, 2020 and 2019 were as follows: Year Ended December 31, 2020 2019 Operating cash flows from operating leases $ (117) $ (159) Lease assets obtained in exchange for new finance lease liabilities — 28 Lease assets obtained in exchange for new operating lease liabilities 42 40
Lessor, Operating Lease, Payments to be Received, Maturity [Table Text Block]	Future minimum operating lease payments receivable as of December 31, 2020 are as follows: Lease Payments 2021 $ 103 2022 64 2023 8 2024 3 2025 2 Thereafter 5 Total undiscounted cash flows $ 185

Derivative assets and liabilt_2

Derivative assets and liabilties (Tables)	12 Months Ended
	Dec. 31, 2020
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Outstanding commodity-related derivatives	The following table details our outstanding commodity-related derivatives: December 31, 2020 December 31, 2019 Notional Maturity Notional Maturity Mark-to-Market Derivatives (Trading) Natural Gas (BBtu): Fixed Swaps/Futures 1,603 2021-2022 1,483 2020 Basis Swaps IFERC/NYMEX (1) (44,225) 2021-2022 (35,208) 2020-2024 Power (Megawatt): Forwards 1,392,400 2021-2029 3,213,450 2020-2029 Futures 18,706 2021-2022 (353,527) 2020 Options – Puts 519,071 2021 51,615 2020 Options – Calls 2,343,293 2021 (2,704,330) 2020-2021 (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (29,173) 2021-2022 (18,923) 2020-2022 Swing Swaps IFERC 11,208 2021 (9,265) 2020 Fixed Swaps/Futures (53,575) 2021-2022 (3,085) 2020-2021 Forward Physical Contracts (11,861) 2021 (13,364) 2020-2021 NGL (MBbls) – Forwards/Swaps (5,840) 2021-2022 (1,300) 2020-2021 Crude (MBbls) – Forwards/Swaps — — 4,465 2020 Refined Products (MBbls) – Futures (2,765) 2021 (2,473) 2020-2021 Corn (thousand bushels) — — (1,210) 2020 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (30,113) 2021 (31,780) 2020 Fixed Swaps/Futures (30,113) 2021 (31,780) 2020 Hedged Item – Inventory 30,113 2021 31,780 2020 (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	Term Type (1) Notional Amount Outstanding December 31, 2020 December 31, 2019 July 2020 (2)(3) Forward-starting to pay a fixed rate of 3.52% and receive a floating rate $ — $ 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 400 400 (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 December 31, 2020 December 31, 2019 December 31, 2020 December 31, 2019 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 25 $ 24 $ (32) $ — 25 24 (32) — Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 90 319 (166) (350) Commodity derivatives 53 41 (71) (39) Interest rate derivatives — — (448) (399) 143 360 (685) (788) Total derivatives $ 168 $ 384 $ (717) $ (788)
Offsetting Assets Table Text Block [Table Text Block]	The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 2020 December 31, 2019 December 31, 2020 December 31, 2019 Derivatives without offsetting agreements Derivative liabilities $ — $ — $ (448) $ (399) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 53 41 (71) (39) Broker cleared derivative contracts Other current assets (liabilities) 115 343 (198) (350) 168 384 (717) (788) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (44) (18) 44 18 Counterparty netting Other current assets (liabilities) (64) (318) 64 318 Total net derivatives $ 60 $ 48 $ (609) $ (452)
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	Location of Gain (Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Years Ended December 31, 2020 2019 2018 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ — $ — $ (3)
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 Years Ended December 31, 2020 2019 2018 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Revenues $ — $ (3) $ — Commodity derivatives – Trading Cost of products sold 8 21 32 Commodity derivatives – Non-trading Cost of products sold (34) (100) (102) Interest rate derivatives Gains (losses) on interest rate derivatives (203) (241) 47 Total $ (229) $ (323) $ (23)

Retirement Benefits Retirement

Retirement Benefits Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: December 31, 2020 December 31, 2019 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Change in benefit obligation: Benefit obligation at beginning of period $ 52 $ 34 $ 208 $ 1 $ 37 $ 198 Service cost — — 1 — — 1 Interest cost 2 1 5 2 1 7 Benefits paid, net (2) (5) (16) (1) (7) (16) Actuarial (gain) loss and other 5 1 10 4 — 18 Settlements (2) — — (4) — — SemGroup Acquisition — — — 50 3 — Benefit obligation at end of period 55 31 208 52 34 208 Change in plan assets: Fair value of plan assets at beginning of period 43 — 270 1 — 241 Return on plan assets and other 5 — 28 6 — 35 Employer contributions 1 — 9 1 — 10 Benefits paid, net (2) — (16) (1) — (16) Settlements (2) — — (4) — — SemGroup Acquisition — — — 40 — — Fair value of plan assets at end of period 45 — 291 43 — 270 Amount underfunded (overfunded) at end of period $ 10 $ 31 $ (83) $ 9 $ 34 $ (62) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 108 $ — $ — $ 88 Current liabilities — (4) (2) — (5) (2) Non-current liabilities (10) (27) (23) (9) (29) (24) $ (10) $ (31) $ 83 $ (9) $ (34) $ 62 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain (loss) $ — $ 2 $ (18) $ — $ 1 $ (5) Prior service cost — — 21 — — 40 $ — $ 2 $ 3 $ — $ 1 $ 35
Schedule of Accumulated and Projected Benefit Obligations [Table Text Block]	The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2020 December 31, 2019 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 55 $ 31 N/A $ 51 $ 34 N/A Accumulated benefit obligation 55 31 208 52 34 208 Fair value of plan assets 45 — 291 43 — 270
Schedule of Net Benefit Costs [Table Text Block]	December 31, 2020 December 31, 2019 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Service cost $ — $ 1 $ — $ 1 Interest cost 3 5 3 7 Expected return on plan assets (2) (11) (2) (10) Prior service cost amortization — 19 — 26 Net periodic benefit cost $ 1 $ 14 $ 1 $ 24
Schedule of Benefit Obligations Assumptions [Table Text Block]	The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2020 December 31, 2019 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 2.40 % 2.04 % 4.00 % 2.71 % The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2020 December 31, 2019 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.05 % 2.94 % 3.33 % 3.76 % Expected return on assets: Tax exempt accounts 4.57 % 7.00 % 3.37 % 7.00 % Taxable accounts — 4.75 % — 4.75 %
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]	December 31, 2020 2019 Health care cost trend rate 7.30 % 7.25 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.82 % 4.83 % Year that the rate reaches the ultimate trend rate 2027 2026
Fair Value of Plan Assets [Table Text Block]	The fair value of the pension plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2020 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 1 $ 1 $ — $ — Mutual funds (1) 20 20 — — Fixed income securities 24 — 24 — Total $ 45 $ 21 $ 24 $ — (1) Comprised of approximately 100% equities as of December 31, 2020. Fair Value Measurements at December 31, 2019 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 1 $ 1 $ — $ — Mutual funds (1) 19 19 — — Fixed income securities 23 — 23 — Total $ 43 $ 20 $ 23 $ — (1) Comprised of approximately 100% equities as of December 31, 2019. The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2020 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 18 $ 18 $ — $ — Mutual funds (1) 202 202 — — Fixed income securities 71 — 71 — Total $ 291 $ 220 $ 71 $ — (1) Primarily comprised of approximately 59% equities, 40% fixed income securities and 1% cash as of December 31, 2020. Fair Value Measurements at December 31, 2019 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 14 $ 14 $ — $ — Mutual funds (1) 177 177 — — Fixed income securities 79 — 79 — Total $ 270 $ 191 $ 79 $ — (1) Primarily comprised of approximately 59% equities, 40% fixed income securities and 1% cash as of December 31, 2019.
Schedule of Expected Benefit Payments [Table Text Block]	Panhandle and ETC Sunoco’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: Years Pension Benefits - Funded Plans Pension Benefits - Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2021 $ 3 $ 5 $ 18 2022 4 4 18 2023 4 4 16 2024 4 3 15 2025 2 3 14 2026 - 2030 12 9 58

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Schedule Of Related Party Transactions By Related Party [Table Text Block]	The following table summarizes the revenues from related companies on our consolidated statements of operations: Years Ended December 31, 2020 2019 2018 Revenues from related companies $ 466 $ 492 $ 431 The following table summarizes the related company accounts receivable and accounts payable balances on our consolidated balance sheets: December 31, 2020 2019 Accounts receivable from related companies: ET $ — $ 8 FGT 12 50 Phillips 66 30 36 Traverse Rover LLC — 42 Other 37 31 Total accounts receivable from related companies $ 79 $ 167 Accounts payable to related companies: ET $ 150 $ — Other 27 31 Total accounts payable to related companies $ 177 $ 31

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2020
Reportable Segments [Abstract]
Reportable segments	The following tables present financial information by segment: Years Ended December 31, 2020 2019 2018 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,312 $ 2,749 $ 3,428 Intersegment revenues 232 350 309 2,544 3,099 3,737 Interstate transportation and storage: Revenues from external customers 1,841 1,941 1,664 Intersegment revenues 20 22 18 1,861 1,963 1,682 Midstream: Revenues from external customers 1,944 2,280 2,090 Intersegment revenues 3,082 3,751 5,432 5,026 6,031 7,522 NGL and refined products transportation and services: Revenues from external customers 8,501 9,920 10,119 Intersegment revenues 2,012 1,721 1,004 10,513 11,641 11,123 Crude oil transportation and services: Revenues from external customers 11,674 18,447 17,236 Intersegment revenues 5 — 96 11,679 18,447 17,332 Investment in Sunoco LP: Revenues from external customers 10,653 16,590 16,982 Intersegment revenues 57 6 12 10,710 16,596 16,994 Investment in USAC: Revenues from external customers 655 678 495 Intersegment revenues 12 20 13 667 698 508 All other: Revenues from external customers 1,374 1,608 2,073 Intersegment revenues 464 81 155 1,838 1,689 2,228 Eliminations (5,884) (5,951) (7,039) Total revenues $ 38,954 $ 54,213 $ 54,087 Years Ended December 31, 2020 2019 2018 Cost of products sold: Intrastate transportation and storage $ 1,478 $ 1,909 $ 2,665 Midstream 2,598 3,577 5,145 NGL and refined products transportation and services 7,139 8,393 8,462 Crude oil transportation and services 8,838 14,832 14,384 Investment in Sunoco LP 9,654 15,380 15,872 Investment in USAC 82 91 67 All other 1,527 1,504 2,006 Eliminations (5,829) (5,885) (6,998) Total cost of products sold $ 25,487 $ 39,801 $ 41,603 Years Ended December 31, 2020 2019 2018 Depreciation, depletion and amortization: Intrastate transportation and storage $ 185 $ 184 $ 169 Interstate transportation and storage 411 387 334 Midstream 1,140 1,066 1,006 NGL and refined products transportation and services 667 613 466 Crude oil transportation and services 640 437 445 Investment in Sunoco LP 189 181 167 Investment in USAC 239 231 169 All other 198 37 87 Total depreciation, depletion and amortization $ 3,669 $ 3,136 $ 2,843 Years Ended December 31, 2020 2019 2018 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 18 $ 18 $ 19 Interstate transportation and storage 17 222 227 Midstream 24 20 26 NGL and refined products transportation and services 60 53 64 Crude oil transportation and services (2) (1) 6 All other 2 (10) 2 Total equity in earnings of unconsolidated affiliates $ 119 $ 302 $ 344 Years Ended December 31, 2020 2019 2018 Segment Adjusted EBITDA: Intrastate transportation and storage $ 863 $ 999 $ 927 Interstate transportation and storage 1,680 1,792 1,680 Midstream 1,670 1,602 1,627 NGL and refined products transportation and services 2,802 2,666 1,979 Crude oil transportation and services 2,258 2,898 2,385 Investment in Sunoco LP 739 665 638 Investment in USAC 414 420 289 All other 115 106 76 Total Segment Adjusted EBITDA 10,541 11,148 9,601 Depreciation, depletion and amortization (3,669) (3,136) (2,843) Interest expense, net of interest capitalized (2,323) (2,262) (1,709) Impairment losses (2,880) (74) (431) Gains (losses) on interest rate derivatives (203) (241) 47 Non-cash compensation expense (121) (113) (105) Unrealized losses on commodity risk management activities (71) (5) (11) Inventory valuation adjustments (82) 79 (85) Losses on extinguishments of debt (72) (2) (109) Adjusted EBITDA related to unconsolidated affiliates (628) (626) (655) Equity in earnings of unconsolidated affiliates 119 302 344 Impairment of investments in unconsolidated affiliates (129) — — Adjusted EBITDA related to discontinued operations — — 25 Other, net 68 244 30 Income from continuing operations before income tax expense 550 5,314 4,099 Income tax expense from continuing operations (239) (199) (5) Income from continuing operations 311 5,115 4,094 Loss from discontinued operations, net of income taxes — — (265) Net income $ 311 $ 5,115 $ 3,829 December 31, 2020 2019 2018 Segment assets: Intrastate transportation and storage $ 7,549 $ 6,648 $ 6,365 Interstate transportation and storage 17,730 18,111 15,081 Midstream 18,816 20,332 19,745 NGL and refined products transportation and services 21,578 19,145 18,267 Crude oil transportation and services 18,335 22,933 18,189 Investment in Sunoco LP 5,267 5,438 4,879 Investment in USAC 2,949 3,730 3,775 All other and eliminations 4,518 5,957 2,308 Total segment assets $ 96,742 $ 102,294 $ 88,609 Years Ended December 31, 2020 2019 2018 Additions to property, plant and equipment (1) : Intrastate transportation and storage $ 49 $ 124 $ 344 Interstate transportation and storage 150 375 812 Midstream 487 827 1,161 NGL and refined products transportation and services 2,403 2,976 2,381 Crude oil transportation and services 291 403 474 Investment in Sunoco LP 124 148 103 Investment in USAC 119 200 205 All other 136 215 150 Total additions to property, plant and equipment (1) $ 3,759 $ 5,268 $ 5,630 (1) Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis). December 31, 2020 2019 2018 Investments in unconsolidated affiliates: Intrastate transportation and storage $ 89 $ 88 $ 83 Interstate transportation and storage 2,278 2,524 2,070 Midstream 110 112 124 NGL and refined products transportation and services 509 461 243 Crude oil transportation and services 22 242 28 All other 47 27 88 Total investments in unconsolidated affiliates $ 3,055 $ 3,454 $ 2,636

Quarterly Financial Data (Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information [Table Text Block]	Quarters Ended March 31 June 30 September 30 (1) December 31 Total Year 2020: Revenues $ 11,627 $ 7,338 $ 9,955 $ 10,034 $ 38,954 Operating income 65 1,342 248 1,344 2,999 Net income (loss) (914) 719 (362) 868 311 Net income (loss) attributable to partners (720) 481 (530) 627 (142) (1) For the three months ended September 30, 2020, the net loss attributable to partners presented above reflects a change from the amount previously reported in the Partnership’s interim financial statements, due to an adjustment to the allocation of income between the general and limited partners and the noncontrolling interest in a less than wholly-owned subsidiary of the Partnership. Quarters Ended March 31 June 30 September 30 December 31 Total Year 2019: Revenues $ 13,121 $ 13,877 $ 13,495 $ 13,720 $ 54,213 Operating income 1,866 1,828 1,860 1,668 7,222 Income from continuing operations 1,219 1,282 1,250 1,364 5,115 Net income 1,219 1,282 1,250 1,364 5,115 Net income attributable to partners 950 1,003 977 1,080 4,010

Operations and Organization (Na

Operations and Organization (Narrative) (Details)	1 Months Ended	12 Months Ended
	Oct. 31, 2018shares	Dec. 31, 2020shares	Dec. 31, 2019shares	Jul. 30, 2019shares
USAC [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		100.00%
Sunoco LP [Member]
Incentive Distribution Rights		100.00%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		28,500,000
USAC [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.			39,700,000	46,100,000
ETE Merger [Member]
Conversion Rate of Units in Merger, Per Unit	1.28
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

Estimates, Significant Accoun_4

Estimates, Significant Accounting Policies and Balance Sheet Detials (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended				12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Impairment losses					$ 2,880	$ 74	$ 431
Operating Lease, Right-of-Use Asset	$ 1,000			$ 964	1,000	964
Operating Lease, Liability	890				890
Asset Retirement Obligation	270			247	270	247
Tangible Asset Impairment Charges							9
Impairment losses		$ 12		9	2,815	21
Long-term Debt, Fair Value	56,130			54,660	56,130	54,660
Goodwill acquired					9	307
Goodwill	2,391			5,167	2,391	5,167	4,885
Long-term Debt	51,366			50,930	51,366	50,930
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net					0
Costs Incurred, Asset Retirement Obligation Incurred					16	5	13
Asset Retirement Obligation, Legally Restricted Assets, Fair Value	34			31	34	31
Impairment of investments in unconsolidated affiliates					129	0	0
White Cliffs [Member]
Impairment of investments in unconsolidated affiliates					$ 129
Customer relationships, contracts and agreements (3 to 46 years)
Impairment of Intangible Assets (Excluding Goodwill)				30
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives					3 years
Minimum [Member] | Other (5 to 20 years)
Useful Lives					5 years
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives					46 years
Maximum [Member] | Patents [Member]
Useful Lives					10 years
Maximum [Member] | Other (5 to 20 years)
Useful Lives					20 years
Interstate Transportation and Storage [Member]
Impairment losses					$ 58
Impairment losses		43	$ 183		226	12
Goodwill acquired					0	42
Goodwill	0			226	0	226	196
Midstream [Member]
Impairment losses			483	378	483	9
Goodwill acquired					0	0
Goodwill	0			483	0	483	492
Retail Marketing [Member]
Excise Taxes Collected					301	386	370
NGL and refined products transportation and services [Member]
Impairment losses					0	0
Goodwill acquired					0	0
Goodwill	693			693	693	693	693
Other Segments [Member]
Impairment losses	15	132	40		198	0
Goodwill acquired					0	35
Goodwill	82			184	82	184	149
Investment In Sunoco LP [Member]
Impairment losses					0	0
Goodwill acquired					9	0
Goodwill	1,564			1,555	1,564	1,555	1,559
Investment In USAC [Member]
Impairment losses			$ 619		619	0
Goodwill acquired					0	0
Goodwill	0			619	0	619	619
Crude oil transportation and services [Member]
Impairment losses		$ 1,280			1,279	0
Goodwill acquired					0	230
Goodwill	52			1,397	52	1,397	1,167
Intrastate Transportation And Storage [Member]
Impairment losses	10				10	0
Goodwill acquired					0	0
Goodwill	0			10	0	10	$ 10
Sunoco LP [Member]
Impairment losses						47
Inventory Write-down					82
Long-term Debt	3,112			$ 3,071	3,112	3,071
USAC [Member]
Impairment losses					8	$ 6
PEI | Other Segments [Member]
Impairment losses	11
Fair value exceeding carrying value by less than 20% [Member]
Goodwill	$ 368				$ 368

Estimates, Significant Accoun_5

Estimates, Significant Accounting Policies and Balance Sheet Detials (Change in Accounting Policy) (Details) - USD ($) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	[1]	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Assets [Abstract]
Other current assets	$ 222					$ 291				$ 222	$ 291
Property, Plant and Equipment, Net	74,819					73,896				74,819	73,896
Intangible assets, net	5,746					6,154				5,746	6,154
Other non-current assets, net	1,657					1,571				1,657	1,571
Liabilities and Equity [Abstract]
Other non-current liabilities	1,152					1,162				1,152	1,162
Noncontrolling interests	8,096					8,018				8,096	8,018
Costs and Expenses [Abstract]
Cost of products sold										(25,487)	(39,801)	$ (41,603)
Operating expenses										3,218	3,294	3,089
Depreciation, depletion and amortization										3,669	3,136	2,843
New Accounting Pronouncement or Change in Accounting Principle, Retrospective Adjustments [Abstract]
Operating Income (Loss)	1,344	$ 248		$ 1,342	$ 65	1,668	$ 1,860	$ 1,828	$ 1,866	2,999	7,222	5,457
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX BENEFIT										550	5,314	4,099
Net income	868	$ (362)		$ 719	$ (914)	1,364	$ 1,250	$ 1,282	$ 1,219	311	5,115	3,829
Net Income (Loss) Attributable to Parent										(142)	4,010	3,080
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest										393	5,146	3,786
Comprehensive Income (Loss), Net of Tax, Attributable to Parent										(60)	4,041	3,037
Inventory valuation adjustments										82	(79)	85
Increase (Decrease) in Operating Capital										(212)	395	(62)
Inventories	1,739					1,532				1,739	1,532
Property, Plant and Equipment, Net	74,819					73,896				74,819	73,896
Operating Lease, Right-of-Use Asset	1,000					964				1,000	964
Operating lease current liabilities	53					60				53	60
Accrued and other current liabilities	2,769					3,336				2,769	3,336
Current maturities of long-term debt	21					26				21	26
Long-term debt, less current maturities	51,345					50,904				51,345	50,904
Non-current operating lease liabilities	837					901				837	901
Assets, Current	6,325					7,485				6,325	7,485
Total assets	96,742					102,294				96,742	102,294	88,609
Partners' Capital	$ 24,854					27,382				24,854	27,382
Previously Reported [Member]
Assets [Abstract]
Other non-current assets, net						1,075					1,075
Costs and Expenses [Abstract]
Cost of products sold											(39,727)	(41,658)
New Accounting Pronouncement or Change in Accounting Principle, Retrospective Adjustments [Abstract]
Operating Income (Loss)											7,296	5,402
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX BENEFIT											5,388	4,044
Net income											5,189	3,774
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest											5,220	3,731
Comprehensive Income (Loss), Net of Tax, Attributable to Parent											4,115	2,982
Increase (Decrease) in Operating Capital											(469)	117
Inventories						1,935					1,935
Assets, Current						7,888					7,888
Total assets						102,201					102,201
Partners' Capital						27,289					27,289
Revision of Prior Period, Change in Accounting Principle, Adjustment [Member]
Assets [Abstract]
Other non-current assets, net						496					496
New Accounting Pronouncement or Change in Accounting Principle, Retrospective Adjustments [Abstract]
Inventories						(403)					(403)
Assets, Current						(403)					(403)
Total assets						93					93
Partners' Capital						$ 93					93
Change in Inventory Accounting Policy [Member]
Costs and Expenses [Abstract]
Cost of products sold											(74)	(55)
New Accounting Pronouncement or Change in Accounting Principle, Retrospective Adjustments [Abstract]
Operating Income (Loss)											(74)	55
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX BENEFIT											(74)	55
Net income											(74)	55
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest											(74)	55
Comprehensive Income (Loss), Net of Tax, Attributable to Parent											(74)	55
Increase (Decrease) in Operating Capital											74	(55)
Natural gas sales
Revenues [Abstract]
Revenue from Contract with Customer, Including Assessed Tax										2,633	3,295	4,452
NGL sales
Revenues [Abstract]
Revenue from Contract with Customer, Including Assessed Tax										6,797	8,290	9,986
Crude sales
Revenues [Abstract]
Revenue from Contract with Customer, Including Assessed Tax										9,442	15,917	14,425
Gathering, transportation and other fees
Revenues [Abstract]
Revenue from Contract with Customer, Including Assessed Tax										8,982	9,086	6,797
Refined product sales
Revenues [Abstract]
Revenue from Contract with Customer, Including Assessed Tax										10,514	16,752	17,458
Other
Revenues [Abstract]
Revenue from Contract with Customer, Including Assessed Tax										$ 586	$ 873	$ 969
[1]	For the three months ended September 30, 2020, the net loss attributable to partners presented above reflects a change from the amount previously reported in the Partnership’s interim financial statements, due to an adjustment to the allocation of income between the general and limited partners and the noncontrolling interest in a less than wholly-owned subsidiary of the Partnership.

Estimates, Significant Accoun_6

Estimates, Significant Accounting Policies and Balance Sheet Detials (Net change in operating assets and liabilities (net of acquisitions) included in cash flows) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Accounts receivable	$ 1,163	$ (473)	$ 506
Accounts receivable from related companies	(290)	(17)	128
Inventories	(271)	(20)	237
Other current assets	189	107	7
Other non-current assets, net	(7)	(155)	(119)
Accounts payable	(1,327)	148	(769)
Accounts payable to related companies	517	(92)	(206)
Accrued and other current liabilities	161	23	365
Other non-current liabilities	8	(134)	(34)
Price risk management assets and liabilities, net	69	218	(53)
Net change in operating assets and liabilities, net of effects of acquisitions	$ 212	$ (395)	$ 62

Estimates, Significant Accoun_7

Estimates, Significant Accounting Policies and Balance Sheet Detials (Non-cash investing and financing activities and supplemental cash flow information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures		$ 1,334	$ 1,030
Right-of-Use Assets Obtained in Exchange for Liabilities	$ 42	68	0
Net gains (losses) from subsidiary common unit transactions	0	0	(127)
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	2,086	1,799	1,537
Proceeds from Income Tax Refunds	$ (64)
Cash paid for income taxes (net of refunds)		$ 30	$ 508

Estimates, Significant Accoun_8

Estimates, Significant Accounting Policies and Balance Sheet Detials (Inventory) (Details) - USD ($) $ in Millions		Dec. 31, 2020	Dec. 31, 2019
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Natural gas, NGLs and refined products (1)	[1]	$ 1,013	$ 833
Crude oil		287	251
Spare parts and other		439	448
Total inventories		$ 1,739	$ 1,532
[1]	Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of $82 million for the year ended December 31, 2020.

Estimates, Significant Accoun_9

Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Deposits paid to vendors	$ 75	$ 95
Prepaid expenses and other	147	196
Total other current assets	$ 222	$ 291

Estimates, Significant Accou_10

Estimates, Significant Accounting Policies and Balance Sheet Detials (Components and useful lives of property, plant and equipment) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment, Gross	$ 93,620	$ 89,294
Less - Accumulated depreciation	(18,801)	(15,398)
Property, plant and equipment, net	74,819	73,896
Land and improvements
Property, Plant and Equipment, Gross	1,233	1,232
Buildings and improvements (1 to 45 years)
Property, Plant and Equipment, Gross	4,204	2,631
Pipelines and equipment (5 to 83 years)
Property, Plant and Equipment, Gross	69,120	64,678
Bulk Storage Equipment And Facilities [Member]
Property, Plant and Equipment, Gross	6,393	5,898
Right of way (20 to 83 years)
Property, Plant and Equipment, Gross	5,091	4,851
Other (1 to 48 years)
Property, Plant and Equipment, Gross	1,808	1,509
Construction Work-In-Process [Member]
Property, Plant and Equipment, Gross	$ 5,771	$ 8,495
Minimum [Member] | Buildings and improvements (1 to 45 years)
Property, plant and equipment useful life, minimum in years	1 year
Minimum [Member] | Pipelines and equipment (5 to 83 years)
Property, plant and equipment useful life, minimum in years	5 years
Minimum [Member] | Bulk Storage Equipment And Facilities [Member]
Property, plant and equipment useful life, minimum in years	2 years
Minimum [Member] | Right of way (20 to 83 years)
Property, plant and equipment useful life, minimum in years	20 years
Minimum [Member] | Other (1 to 48 years)
Property, plant and equipment useful life, minimum in years	1 year
Maximum [Member] | Buildings and improvements (1 to 45 years)
Property, plant and equipment useful life, minimum in years	45 years
Maximum [Member] | Pipelines and equipment (5 to 83 years)
Property, plant and equipment useful life, minimum in years	83 years
Maximum [Member] | Right of way (20 to 83 years)
Property, plant and equipment useful life, minimum in years	83 years
Maximum [Member] | Other (1 to 48 years)
Property, plant and equipment useful life, minimum in years	48 years

Estimates, Significant Accou_11

Estimates, Significant Accounting Policies and Balance Sheet Detials (Schedule of Property, Plant and Equipment Depreciation and Capitalized Interest Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Depreciation, depletion and amortization expense	$ 3,266	$ 2,828	$ 2,522
Capitalized interest	$ 189	$ 166	$ 294

Estimates, Significant Accou_12

Estimates, Significant Accounting Policies and Balance Sheet Detials (Other Non-Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
Regulatory assets	$ 41	$ 42
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Plan Assets	103	84
Deferred charges	188	178
Restricted funds	179	178
Other	629	593
Total other non-current assets, net	1,657	1,571
Energy Related Inventory, Crude Oil and Natural Gas Liquids	$ 517	$ 496

Estimates, Significant Accou_13

Estimates, Significant Accounting Policies and Balance Sheet Detials (Intangible assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Gross Carrying Amount	$ 7,953	$ 7,975
Accumulated Amortization	(2,207)	(1,821)
Trademarks [Member]
Gross Carrying Amount	295	295
Accumulated Amortization	0	0
Customer relationships, contracts and agreements (3 to 46 years)
Gross Carrying Amount	7,513	7,535
Accumulated Amortization	(2,117)	(1,743)
Patents (10 years)
Gross Carrying Amount	48	48
Accumulated Amortization	(40)	(35)
Trade Names (20 years)
Gross Carrying Amount	66	66
Accumulated Amortization	(35)	(31)
Other (5 to 20 years)
Gross Carrying Amount	19	19
Accumulated Amortization	(15)	(12)
Other non-amortizable intangible assets [Member]
Gross Carrying Amount	12	12
Accumulated Amortization	0	0
Total Amortizable Intangible Assets [Member]
Gross Carrying Amount	7,646	7,668
Accumulated Amortization	(2,207)	(1,821)
Non-amortizable intangible assets [Member]
Gross Carrying Amount	307	307
Accumulated Amortization	$ 0	$ 0
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives	46 years
Maximum [Member] | Patents (10 years)
Useful Lives	10 years
Maximum [Member] | Trade Names (20 years)
Useful Lives	20 years
Maximum [Member] | Other (5 to 20 years)
Useful Lives	20 years
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Useful Lives	3 years
Minimum [Member] | Other (5 to 20 years)
Useful Lives	5 years

Estimates, Significant Accou_14

Estimates, Significant Accounting Policies and Balance Sheet Detials (Amortization expense of intangible assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Depreciation And Amortization [Member]
Reported in depreciation, depletion and amortization expense	$ 403	$ 308	$ 321

Estimates, Significant Accou_15

Estimates, Significant Accounting Policies and Balance Sheet Detials (Estimated aggregate amortization expense) (Details) $ in Millions	Dec. 31, 2020USD ($)
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL
2021	$ 393
2022	379
2023	363
2024	349
2025	$ 335

Estimates, Significant Accou_16

Estimates, Significant Accounting Policies and Balance Sheet Detials (Changes in the carrying amount of goodwill) (Details) - USD ($) $ in Millions	3 Months Ended				12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Goodwill, Beginning Balance			$ 5,167		$ 5,167	$ 4,885
Goodwill acquired					9	307
Impairment losses		$ (12)		$ (9)	(2,815)	(21)
Other					30	(4)
Goodwill, Ending Balance	$ 2,391			5,167	2,391	5,167
Intrastate Transportation And Storage [Member]
Goodwill, Beginning Balance			10		10	10
Goodwill acquired					0	0
Impairment losses	(10)				(10)	0
Other					0	0
Goodwill, Ending Balance	0			10	0	10
Interstate Transportation and Storage [Member]
Goodwill, Beginning Balance			226		226	196
Goodwill acquired					0	42
Impairment losses		(43)	(183)		(226)	(12)
Other					0	0
Goodwill, Ending Balance	0			226	0	226
Midstream [Member]
Goodwill, Beginning Balance			483		483	492
Goodwill acquired					0	0
Impairment losses			(483)	(378)	(483)	(9)
Other					0	0
Goodwill, Ending Balance	0			483	0	483
Other Segments [Member]
Goodwill, Beginning Balance			184		184	149
Goodwill acquired					0	35
Impairment losses	(15)	(132)	(40)		(198)	0
Other					96	0
Goodwill, Ending Balance	82			184	82	184
NGL and refined products transportation and services [Member]
Goodwill, Beginning Balance			693		693	693
Goodwill acquired					0	0
Impairment losses					0	0
Other					0	0
Goodwill, Ending Balance	693			693	693	693
Crude oil transportation and services [Member]
Goodwill, Beginning Balance			1,397		1,397	1,167
Goodwill acquired					0	230
Impairment losses		$ (1,280)			(1,279)	0
Other					(66)	0
Goodwill, Ending Balance	52			1,397	52	1,397
Investment In Sunoco LP [Member]
Goodwill, Beginning Balance			1,555		1,555	1,559
Goodwill acquired					9	0
Impairment losses					0	0
Other					0	(4)
Goodwill, Ending Balance	1,564			1,555	1,564	1,555
Investment In USAC [Member]
Goodwill, Beginning Balance			619		619	619
Goodwill acquired					0	0
Impairment losses			$ (619)		(619)	0
Other					0	0
Goodwill, Ending Balance	$ 0			$ 619	$ 0	$ 619

Estimates, Significant Accou_17

Estimates, Significant Accounting Policies and Balance Sheet Detials (Accrued and Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Other Information [Abstract]
Interest payable	$ 598	$ 576
Customer advances and deposits	161	123
Accrued capital expenditures	604	1,334
Accrued wages and benefits	109	217
Taxes payable other than income taxes	446	263
Exchanges payable	127	67
Other	724	756
Total accrued and other current liabilities	$ 2,769	$ 3,336

Estimates, Significant Accou_18

Estimates, Significant Accounting Policies and Balance Sheet Detials (Assets and liabilities measured and recorded at fair value on a recurring basis) (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Price Risk Derivative Assets, at Fair Value	$ 168	$ 384
Other Assets, Fair Value Disclosure	34	31
Interest rate derivatives, Liabilities	(448)	(399)
Price Risk Derivative Liabilities, at Fair Value	(269)	(389)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	717	788
Assets, Fair Value Disclosure	202	415
Options - Calls [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value	1	1
Forward Physical Contracts [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Liabilities, at Fair Value	(1)
Future [Member] | Commodity Derivatives - Refined Products [Member]
Price Risk Derivative Assets, at Fair Value	3	8
Price Risk Derivative Liabilities, at Fair Value	(11)	(10)
Future [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value	2	4
Price Risk Derivative Liabilities, at Fair Value	(3)	(3)
Forwards Swaps [Member] | Commodity Derivatives - NGLs [Member]
Price Risk Derivative Assets, at Fair Value	127	260
Price Risk Derivative Liabilities, at Fair Value	(227)	(278)
Forwards Swaps [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value	4	11
Price Risk Derivative Liabilities, at Fair Value	0	(5)
Forwards Swaps [Member] | Commodity Derivatives - Crude [Member]
Price Risk Derivative Assets, at Fair Value	0	13
Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	5	3
Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	12	17
Price Risk Derivative Liabilities, at Fair Value	(11)	(49)
Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	1	1
Price Risk Derivative Liabilities, at Fair Value	(3)	(1)
Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	13	65
Price Risk Derivative Liabilities, at Fair Value	(13)	(43)
Put Option [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value		1
Fair Value, Inputs, Level 1 [Member]
Price Risk Derivative Assets, at Fair Value	158	369
Other Assets, Fair Value Disclosure	22	20
Interest rate derivatives, Liabilities	0	0
Price Risk Derivative Liabilities, at Fair Value	(265)	(383)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	265	383
Assets, Fair Value Disclosure	180	389
Fair Value, Inputs, Level 1 [Member] | Options - Calls [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value	1	1
Fair Value, Inputs, Level 1 [Member] | Forward Physical Contracts [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Liabilities, at Fair Value	0
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Refined Products [Member]
Price Risk Derivative Assets, at Fair Value	3	8
Price Risk Derivative Liabilities, at Fair Value	(11)	(10)
Fair Value, Inputs, Level 1 [Member] | Future [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value	2	4
Price Risk Derivative Liabilities, at Fair Value	(3)	(3)
Fair Value, Inputs, Level 1 [Member] | Forwards Swaps [Member] | Commodity Derivatives - NGLs [Member]
Price Risk Derivative Assets, at Fair Value	127	260
Price Risk Derivative Liabilities, at Fair Value	(227)	(278)
Fair Value, Inputs, Level 1 [Member] | Forwards Swaps [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 1 [Member] | Forwards Swaps [Member] | Commodity Derivatives - Crude [Member]
Price Risk Derivative Assets, at Fair Value	0	13
Fair Value, Inputs, Level 1 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Fair Value, Inputs, Level 1 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	12	17
Price Risk Derivative Liabilities, at Fair Value	(11)	(49)
Fair Value, Inputs, Level 1 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 1 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	13	65
Price Risk Derivative Liabilities, at Fair Value	(13)	(43)
Fair Value, Inputs, Level 1 [Member] | Put Option [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value		1
Fair Value, Inputs, Level 2 [Member]
Price Risk Derivative Assets, at Fair Value	10	15
Other Assets, Fair Value Disclosure	12	11
Interest rate derivatives, Liabilities	(448)	(399)
Price Risk Derivative Liabilities, at Fair Value	(4)	(6)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	452	405
Assets, Fair Value Disclosure	22	26
Fair Value, Inputs, Level 2 [Member] | Options - Calls [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Forward Physical Contracts [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Liabilities, at Fair Value	(1)
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Refined Products [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Future [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Forwards Swaps [Member] | Commodity Derivatives - NGLs [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Forwards Swaps [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value	4	11
Price Risk Derivative Liabilities, at Fair Value	0	(5)
Fair Value, Inputs, Level 2 [Member] | Forwards Swaps [Member] | Commodity Derivatives - Crude [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Forward Physical Swaps [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	5	3
Fair Value, Inputs, Level 2 [Member] | Basis Swaps IFERC/NYMEX [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Inputs, Level 2 [Member] | Swing Swaps IFERC [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	1	1
Price Risk Derivative Liabilities, at Fair Value	(3)	(1)
Fair Value, Inputs, Level 2 [Member] | Fixed Swaps Futures [Member] | Commodity Derivatives - Natural Gas [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	$ 0	0
Fair Value, Inputs, Level 2 [Member] | Put Option [Member] | Commodity Derivatives - Power [Member]
Price Risk Derivative Assets, at Fair Value		$ 0

Estimates, Significant Accou_19

Estimates, Significant Accounting Policies and Balance Sheet Detials (Costs and expenses) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Retail Marketing [Member]
Excise Taxes Collected	$ 301	$ 386	$ 370

Acquisitions, Divestitures an_3

Acquisitions, Divestitures and Related Transactions (Current Transactions) (Details) - USD ($) $ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Oct. 31, 2018

Apr. 30, 2018

Jan. 22, 2018

Dec. 31, 2020

Sep. 30, 2020

Jun. 30, 2020

Mar. 31, 2020

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Dec. 05, 2019

Business Acquisition [Line Items]

Revenues

$ 10,034

$ 9,955

[1]

$ 7,338

$ 11,627

$ 13,720

$ 13,495

$ 13,877

$ 13,121

$ 38,954

$ 54,213

$ 54,087

Impairment losses

12

9

2,815

21

Inventory Valuation Reserves

$ 311

311

229

Impairment losses

2,880

74

431

Interstate Transportation and Storage [Member]

Business Acquisition [Line Items]

Revenues

1,861

1,963

$ 1,682

Impairment losses

$ 43

$ 183

226

12

Impairment losses

58

USAC Transaction [Member]

Business Acquisition [Line Items]

Business Combination, Consideration Transferred

$ 1,700

Payments to Acquire Businesses, Gross

$ 1,230

SemGroup [Member]

Business Acquisition [Line Items]

Impairment losses

244

Long-term debt, less current maturities (1)

$ 2,576

Other Asset Impairment Charges

$ 129

SemGroup [Member] | Senior Notes

Business Acquisition [Line Items]

Long-term debt, less current maturities (1)

1,375

SemGroup [Member] | Subsidiaries

Business Acquisition [Line Items]

Long-term debt, less current maturities (1)

$ 593

ET Merger - Sunoco LP Exchange | ET | Sunoco LP common units

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

2,263,158

ET Merger - Sunoco LP Exchange | ET | ETO common units

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

2,874,275

ET Merger - Sunoco LP Exchange | ET | Sunoco GP [Member]

Business Acquisition [Line Items]

Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest

100.00%

ET Merger - Sunoco LP Exchange | ETO [Member] | ETO common units

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

42,812,389

ET Merger - USAC Exchange | ET | USAC common Units

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

12,466,912

ET Merger - USAC Exchange | ET | USAC GP [Member]

Business Acquisition [Line Items]

Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest

100.00%

ET Merger - USAC Exchange | ETO [Member] | ETO common units

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

16,134,903

ET Merger - Lake Charles Exchange | ET | Lake Charles LNG limited partner interest

Business Acquisition [Line Items]

Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest

100.00%

ET Merger - Lake Charles Exchange | ET | Energy Transfer LNG Export LLC, ET Crude Oil Terminals LLC, & ETC Illinois LLC limited partner interest

Business Acquisition [Line Items]

Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest

60.00%

ET Merger - Lake Charles Exchange | ETO [Member] | ETO common units

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

37,557,815

7-Eleven [Member]

Business Acquisition [Line Items]

Revenues

$ 199

Sunoco LP [Member]

Business Acquisition [Line Items]

Impairment losses

47

USA Compression Partners, LP [Member] | USAC Transaction [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

19,191,351

USA Compression Partners, LP [Member] | USAC Transaction [Member] | Class B Units [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

6,397,965

USAC [Member]

Business Acquisition [Line Items]

Impairment losses

$ 8

$ 6

ET | USA Compression Partners, LP [Member] | USAC Transaction [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

12,466,912

Equity Issued in Business Combination, Fair Value Disclosure

$ 250

USAC GP [Member] | USA Compression Partners, LP [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

8,000,000

[1]

For the three months ended September 30, 2020, the net loss attributable to partners presented above reflects a change from the amount previously reported in the Partnership’s interim financial statements, due to an adjustment to the allocation of income between the general and limited partners and the noncontrolling interest in a less than wholly-owned subsidiary of the Partnership.

Acquisitions, Divestitures an_4

Acquisitions, Divestitures and Related Transactions (Previous Transactions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Capital contributions from noncontrolling interest	$ 222	$ 348	$ 649
Intangible assets, net	5,746	6,154
Property, plant and equipment	93,620	89,294
REVENUES			349
Cost of products sold			305
Operating expenses			61
Selling, general and administrative			7
Disposal Group, Including Discontinued Operations, Total Costs and Expenses			373
Disposal Group, Including Discontinued Operation, Operating Income (Loss)			(24)
Interest expense, net			2
Loss on extinguishment of debt			20
Other, net			61
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax			(107)
Income tax expense			158
Loss from discontinued operations, net of income taxes	$ 0	$ 0	$ (265)

Acquisitions, Divestitures an_5

Acquisitions, Divestitures and Related Transactions (Summary of Preliminary Assets And LiabilityAcquired) (Details) - USD ($) $ in Millions		Dec. 05, 2019	Dec. 31, 2020	Dec. 31, 2019	Apr. 02, 2018
Partners' Capital			$ 24,854	$ 27,382
Liabilities and Equity			$ 96,742	$ 102,294
SemGroup [Member]
Property, plant and equipment		$ 3,891
Other non-current assets		617
Goodwill		295
Total assets		6,057
Total current liabilities		629
Long-term debt, less current maturities (1)		2,576
Other non-current liabilities		197
Noncontrolling interest		822
Total liabilities		3,643
Total current assets		794
Intangible assets		460
Business Combination, Consideration Transferred, Including Equity Interest in Acquiree Held Prior to Combination		1,592
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		6,057
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities		$ 241
USA Compression Partners, LP [Member]
Property, plant and equipment					$ 1,332
Other non-current assets					15
Goodwill	[1]				366
Total assets					2,721
Total current liabilities					110
Long-term debt, less current maturities (1)					1,527
Other non-current liabilities					2
Noncontrolling interest					832
Partners' Capital					250
Total liabilities					1,639
Total current assets					786
Intangible assets					222
Liabilities and Equity					$ 2,721
[1]	None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations.

Acquisitions, Divestitures an_6

Acquisitions, Divestitures and Related Transactions Selected Financial Data (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
REVENUES			$ 349
Cost of products sold			305
Total costs and expenses			373
OPERATING LOSS			(24)
Interest expense, net			2
Loss on extinguishment of debt			20
Other, net			61
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE			(107)
Income tax expense			158
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$ 0	$ 0	(265)
Operating expenses			$ 61

Advances to and Investments i_3

Advances to and Investments in Unconsolidated Affiliates (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Investments [Line Items]
Impairment of investments in unconsolidated affiliates	$ 129	$ 0	$ 0
Impairment losses	2,880	74	431
Advances to and investments in unconsolidated affiliates	3,055	3,454	2,636
Goodwill	2,391	5,167	$ 4,885
FEP [Member]
Schedule of Investments [Line Items]
Impairment losses	208
Advances to and investments in unconsolidated affiliates	4	218
White Cliffs [Member]
Schedule of Investments [Line Items]
Impairment of investments in unconsolidated affiliates	129
Advances to and investments in unconsolidated affiliates	$ 274	436
FGT
Schedule of Investments [Line Items]
Percentage Ownership Operating Facility	100.00%
Citrus [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Business Acquisition, Percentage of Voting Interests Acquired	50.00%
FEP [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
MEP [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Sunoco LP [Member]
Schedule of Investments [Line Items]
Impairment losses		$ 47

Advances to and Investments i_4

Advances to and Investments in Unconsolidated Affiliates (Investments in Unconsolidated Affiliates) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	$ 119	$ 302	$ 344
Advances to and investments in unconsolidated affiliates	3,055	3,454	2,636
Citrus [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	162	148	141
Advances to and investments in unconsolidated affiliates	1,867	1,876
FEP [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	(139)	59	55
Advances to and investments in unconsolidated affiliates	4	218
MEP [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	(6)	15	31
Advances to and investments in unconsolidated affiliates	406	429
Other Affiliates [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	82	76	117
Advances to and investments in unconsolidated affiliates	504	495
White Cliffs [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	20	4	$ 0
Advances to and investments in unconsolidated affiliates	$ 274	$ 436

Advances to and Investments i_5

Advances to and Investments in Unconsolidated Affiliates (Summarized Financial Information) (Details) - USD ($) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	[1]	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Investments in and Advances to Affiliates [Line Items]
Net income	$ 868	$ (362)		$ 719	$ (914)	$ 1,364	$ 1,250	$ 1,282	$ 1,219	$ 311	$ 5,115	$ 3,829
Assets, Current	6,325					7,485				6,325	7,485
Total assets	96,742					102,294				96,742	102,294	88,609
Liabilities, Current	6,067					7,719				6,067	7,719
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	32,950					37,425				32,950	37,425	36,788	$ 37,079
Liabilities and Equity	96,742					102,294				96,742	102,294
Revenues	10,034	$ 9,955		$ 7,338	$ 11,627	13,720	$ 13,495	$ 13,877	$ 13,121	38,954	54,213	54,087
Equity Method Investments [Member]
Investments in and Advances to Affiliates [Line Items]
Property, plant and equipment, net	7,339					7,680				7,339	7,680
Net income										(199)	443	460
Assets, Current	227					247				227	247
Assets, Noncurrent	58					40				58	40
Total assets	7,624					7,967				7,624	7,967
Liabilities, Current	600					738				600	738
Liabilities, Noncurrent	3,298					3,242				3,298	3,242
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,726					3,987				3,726	3,987
Liabilities and Equity	$ 7,624					$ 7,967				7,624	7,967
Revenues										1,243	1,192	1,249
Operating income										$ 6	$ 683	$ 723
[1]	For the three months ended September 30, 2020, the net loss attributable to partners presented above reflects a change from the amount previously reported in the Partnership’s interim financial statements, due to an adjustment to the allocation of income between the general and limited partners and the noncontrolling interest in a less than wholly-owned subsidiary of the Partnership.

Debt Obligations (Narrative) (D

Debt Obligations (Narrative) (Details) $ in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2020CAD ($)	Jan. 31, 2020USD ($)	Oct. 31, 2019USD ($)
Unamortized Discounts, Premiums, Fair Value Adjustments and Deferred Debt Issuance Costs		$ (289)
Long-term Debt		51,366	$ 50,930
Proceeds from borrowings		24,440	22,583	$ 28,538
Repayments of Long-term Debt		$ 24,081	18,881	$ 27,297
Supplementary Leverage Ratio		4.31			4.31
ETO [Member]
Long-term Debt		$ 42,654	42,120
Leverage Ratio Maximum		5
Maximum Leverage Ratio Permitted		5.5
Transwestern [Member]
Long-term Debt		$ 400	574
Panhandle [Member]
Long-term Debt		245	246
Sunoco LP [Member]
Long-term Debt		3,112	3,071
USA Compression Partners, LP [Member]
Long-term Debt		1,927	1,852
Revolving credit facility balance outstanding		474	403
Bakken Project [Member]
Long-term Debt		2,484	2,481
SemCAMS [Member]
Line of Credit Facility, Maximum Borrowing Capacity		412
Line of Credit Facility, Remaining Borrowing Capacity		196
Long-term Construction Loan		236
SemCAMS [Member] | Canada, Dollars
Line of Credit Facility, Maximum Borrowing Capacity					$ 525
Line of Credit Facility, Remaining Borrowing Capacity					250
Long-term Construction Loan					$ 300
2.9% Senior Notes due 2025 [Member]
Senior note principal amount						$ 1,000
Senior note interest rate						2.90%
3.75% Senior Notes due 2030 [Member]
Senior note principal amount						$ 1,500
Senior note interest rate						3.75%
5.0% Senior Notes due 2050 [Member]
Senior note principal amount						$ 2,000
Senior note interest rate						5.00%
5.75% Senior Notes due September 1, 2020 | ETO [Member]
Senior note principal amount	[1]	$ 0	400
Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member]
Debt Instrument, Covenant Description		Sunoco LP’s Credit Facility requires Sunoco LP to maintain a Net Leverage Ratio of not more than 5.5 to 1. The maximum Net Leverage Ratio is subject to upwards adjustment of not more than 6.0 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in certain specified acquisitions of not less than $50 million (as permitted under Sunoco LP’s Credit Facility agreement). The Sunoco LP Credit Facility also requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in the Sunoco LP’s Credit Facility agreement) of not less than 2.25 to 1.
Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member] | Sunoco LP [Member]
Revolving credit facility balance outstanding		$ 0	162
Line of Credit Facility, Current Borrowing Capacity		1,500
Letters of Credit Outstanding, Amount		8
Line of Credit Facility, Remaining Borrowing Capacity		$ 1,500
USAC Credit Facility, due 2023 [Member]
Debt Instrument, Covenant Description		a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.75 to 1 through the end of the fiscal quarter ending December 31, 2020 and (ii) 5.5 to 1 for the fiscal quarters ending March 31, 2021 and June 30, 2021, (iii) 5.25 to 1 for the fiscal quarters ending September 30, 2021 and December 31, 2021 and (iv) 5.0 to 1 thereafter, subject to a provision for increases to such thresholds, in the case of any fiscal quarter ending September 30, 2021 or thereafter, by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs, provided that, in any event, such ratio shall not exceed 5.5 to 1.
Minimum interest coverage ratio		2.5			2.5
USAC Credit Facility, due 2023 [Member] | USA Compression Partners, LP [Member]
Line of Credit Facility, Current Borrowing Capacity		$ 1,600
USAC Credit Facility, due 2023 [Member] | USAC [Member]
Revolving credit facility balance outstanding		$ 474
Weighted average interest rate on the total amount outstanding		3.27%			3.27%
Letters of Credit Outstanding, Amount		$ 0
Line of Credit Facility, Remaining Borrowing Capacity		1,100
4.5% Senior Notes due 2024 [Member] | ETO [Member]
Senior note principal amount		750	750
5.25% Senior Notes due 2029 [Member] | ETO [Member]
Senior note principal amount		1,500	1,500
6.25% Senior Notes due 2049 [Member] | ETO [Member]
Senior note principal amount		1,750	1,750
4.25% Senior Notes due April 1, 2024 | ETO [Member]
Senior note principal amount		500	500
5.30% Senior Notes due April 1, 2044 | ETO [Member]
Senior note principal amount		700	700
3.45% Senior Notes due January 15, 2023 | ETO [Member]
Senior note principal amount		350	350
4.95% Senior Notes due January 15, 2043 | ETO [Member]
Senior note principal amount		350	350
3.60% Senior Notes due February 1, 2023 | ETO [Member]
Senior note principal amount		800	800
5.15% Senior Notes due February 1, 2043 | ETO [Member]
Senior note principal amount		450	450
5.35% Senior Notes due May 15, 2045 | ETO [Member]
Senior note principal amount		800	800
5.95% Senior Notes due December 1, 2025 | ETO [Member]
Senior note principal amount		400	400
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETO [Member]
Junior Subordinated Notes		546	546
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member]
Junior Subordinated Notes		54	54
ETP Credit Facility due December 2022 [Member] | ETO [Member]
Revolving credit facility balance outstanding		3,103	4,214
Long-term Commercial Paper, Noncurrent		$ 1,660
Weighted average interest rate on the total amount outstanding		1.12%			1.12%
Line of Credit Facility, Current Borrowing Capacity		$ 5,000
Letters of Credit Outstanding, Amount		109
Line of Credit Facility, Remaining Borrowing Capacity		1,790
3.90% Senior Notes due July 15, 2026 | ETO [Member]
Senior note principal amount		550	550
Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETO [Member]
Revolving credit facility balance outstanding		0
Line of Credit Facility, Maximum Borrowing Capacity		1,000
4.20% Senior Notes due 2023 [Member] | ETO [Member]
Senior note principal amount		500	500
4.95% Senior Notes due 2028 [Member] | ETO [Member]
Senior note principal amount		1,000	1,000
5.80% Senior Notes due 2038 [Member] | ETO [Member]
Senior note principal amount		500	500
6.0% Senior Notes due 2048 [Member] | ETO [Member]
Senior note principal amount		1,000	1,000
4.875% senior notes due 2023 [Member] | Sunoco LP [Member]
Senior note principal amount		436	1,000
5.500% senior notes due 2026 [Member] | Sunoco LP [Member]
Senior note principal amount		800	800
5.875% senior notes due 2028 [Member] | Sunoco LP [Member]
Senior note principal amount		400	400
6.875% Senior notes due April 2026 [Member] | USA Compression Partners, LP [Member]
Senior note principal amount		725	725
4.250% Senior Notes due 2023 | ETO [Member]
Senior note principal amount		995	995
5.875% Senior Notes due 2024 | ETO [Member]
Senior note principal amount		1,127	1,127
5.500% Senior Notes due 2027 | ETO [Member]
Senior note principal amount		956	956
3.625% Senior Notes due 2022 [Member] | Bakken Project [Member]
Senior note principal amount		650	650
3.90% Senior Notes due 2024 [Member] | Bakken Project [Member]
Senior note principal amount		1,000	1,000
4.625% Senior Notes due 2029 [Member] | Bakken Project [Member]
Senior note principal amount		850	850
ETO Term Loan [Member] | ETO [Member]
Revolving credit facility balance outstanding		$ 2,000	2,000
Weighted average interest rate on the total amount outstanding		1.15%			1.15%
Line of Credit Facility, Maximum Borrowing Capacity							$ 2,000
4.15% Senior Notes due October 1, 2020 [Member] | ETO [Member]
Senior note principal amount	[1]	$ 0	1,050
7.5% Senior Notes due October 15, 2020 [Member] | ETO [Member]
Senior note principal amount	[1]	0	1,135
5.50% Senior Notes due February 15, 2020 | ETO [Member]
Senior note principal amount	[1]	0	250
5.36% Senior Notes due December 9, 2020 | Transwestern [Member]
Senior note principal amount		0	175
SemCAMS Senior secured term loan [Member] | SemCAMS [Member]
Senior note principal amount		$ 275
SemCAMS Senior secured term loan [Member] | SemCAMS [Member] | Canada, Dollars
Senior note principal amount					$ 350
4.50% Senior Notes due 2029 [Member] | Sunoco LP [Member]
Senior note principal amount			$ 800
Maximum [Member] | ETP Credit Facility due December 2022 [Member] | ETO [Member]
Line of Credit Facility, Commitment Fee Percentage		0.30%
Maximum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETO [Member]
Line of Credit Facility, Commitment Fee Percentage		0.225%
Minimum [Member] | ETP Credit Facility due December 2022 [Member] | ETO [Member]
Line of Credit Facility, Commitment Fee Percentage		0.125%
Minimum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETO [Member]
Line of Credit Facility, Commitment Fee Percentage		0.125%
Accordion feature [Member] | USAC Credit Facility, due 2023 [Member] | USA Compression Partners, LP [Member]
Revolving credit facility balance outstanding		$ 400
Accordion feature [Member] | ETP Credit Facility due December 2022 [Member] | ETO [Member]
Line of Credit Facility, Current Borrowing Capacity		$ 6,000
Eurodollar [Member] | Maximum [Member]
Debt Instrument, Basis Spread on Variable Rate		2.00%
Eurodollar [Member] | Maximum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETO [Member]
Debt Instrument, Basis Spread on Variable Rate		2.00%
Eurodollar [Member] | Minimum [Member] | ETP Credit Facility due December 2022 [Member] | ETO [Member]
Debt Instrument, Basis Spread on Variable Rate		1.125%
Eurodollar [Member] | Minimum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETO [Member]
Debt Instrument, Basis Spread on Variable Rate		1.50%
Base Rate Loans [Member] | Maximum [Member] | ETP Credit Facility due December 2022 [Member] | ETO [Member]
Debt Instrument, Basis Spread on Variable Rate		1.00%
Base Rate Loans [Member] | Maximum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETO [Member]
Debt Instrument, Basis Spread on Variable Rate		1.00%
Base Rate Loans [Member] | Minimum [Member] | ETP Credit Facility due December 2022 [Member] | ETO [Member]
Debt Instrument, Basis Spread on Variable Rate		0.125%
Base Rate Loans [Member] | Minimum [Member] | Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETO [Member]
Debt Instrument, Basis Spread on Variable Rate		0.50%
[1]	As of December 31, 2019, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The notes were redeemed in January 2020.

Debt Obligations (Debt Instrume

Debt Obligations (Debt Instruments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Long-term Debt		$ 51,366	$ 50,930
Other		3	2
Less: Current maturities of long-term debt		(21)	(26)
Long-term debt, less current maturities		51,345	50,904
ETO [Member]
Unamortized premiums, discounts and fair value adjustments, net		(17)	(5)
Deferred Finance Costs, Noncurrent, Net		(215)	(207)
Long-term Debt		42,654	42,120
Transwestern [Member]
Deferred Finance Costs, Noncurrent, Net		0	(1)
Long-term Debt		400	574
Panhandle [Member]
Unamortized premiums, discounts and fair value adjustments, net		10	11
Long-term Debt		245	246
Bakken Project [Member]
Deferred Finance Costs, Noncurrent, Net		(13)	(16)
Long-term Debt		2,484	2,481
Sunoco LP [Member]
Capital Lease Obligations		103	135
Deferred Finance Costs, Noncurrent, Net		(27)	(26)
Long-term Debt		3,112	3,071
USA Compression Partners, LP [Member]
Revolving credit facilities		474	403
Deferred Finance Costs, Noncurrent, Net		(22)	(26)
Long-term Debt		$ 1,927	1,852
Long-term Debt, Description		USAC $1.60 billion Revolving Credit Facility due April 2023
SemGroup [Member]
Unamortized premiums, discounts and fair value adjustments, net		$ 0	1
Deferred Finance Costs, Noncurrent, Net		(2)	(3)
Long-term Debt		541	584
6.875% Senior Notes due September 2027 [Member] | USA Compression Partners, LP [Member]
Senior Notes		$ 750	750
Long-term Debt, Description		6.875% Senior Notes due September 1, 2027
4.15% Senior Notes due October 1, 2020 | ETO [Member]
Senior Notes	[1]	$ 0	1,050
Long-term Debt, Description		4.15% Senior Notes due October 1, 2020 (1)
7.5% Senior Notes due October 15, 2020 [Member] | ETO [Member]
Senior Notes	[1]	$ 0	1,135
Long-term Debt, Description		7.50% Senior Notes due October 15, 2020 (1)
4.65% Senior Notes due June 1, 2021 | ETO [Member]
Senior Notes	[2]	$ 800	800
Long-term Debt, Description		4.65% Senior Notes due June 1, 2021 (2)
5.20% Senior Notes due February 1, 2022 | ETO [Member]
Senior Notes		$ 1,000	1,000
Long-term Debt, Description		5.20% Senior Notes due February 1, 2022
3.60% Senior Notes due February 1, 2023 | ETO [Member]
Senior Notes		$ 800	800
Long-term Debt, Description		3.60% Senior Notes due February 1, 2023
4.250% Senior Notes due 2023 | ETO [Member]
Senior Notes		$ 995	995
Long-term Debt, Description		4.25% Senior Notes due March 15, 2023
4.20% Senior Notes due 2023 [Member] | ETO [Member]
Senior Notes		$ 500	500
Long-term Debt, Description		4.20% Senior Notes due September 15, 2023
4.90% Senior Notes due February 1, 2024 | ETO [Member]
Senior Notes		$ 350	350
Long-term Debt, Description		4.90% Senior Notes due February 1, 2024
7.60% Senior Notes due February 1, 2024 | ETO [Member]
Senior Notes		$ 277	277
Long-term Debt, Description		7.60% Senior Notes due February 1, 2024
7.60% Senior Notes due February 1, 2024 | Panhandle [Member]
Senior Notes		$ 82	82
Long-term Debt, Description		7.60% Senior Notes due February 1, 2024
5.875% Senior Notes due 2024 | ETO [Member]
Senior Notes		$ 1,127	1,127
Long-term Debt, Description		5.875% Senior Notes due January 15, 2024
4.05% Senior Notes due March 15, 2025 | ETO [Member]
Senior Notes		$ 1,000	1,000
Long-term Debt, Description		4.05% Senior Notes due March 15, 2025
4.75% Senior Notes due January 15, 2026 | ETO [Member]
Senior Notes		$ 1,000	1,000
Long-term Debt, Description		4.75% Senior Notes due January 15, 2026
4.20% Senior Notes due April 2027 [Member] | ETO [Member]
Senior Notes		$ 600	600
Long-term Debt, Description		4.20% Senior Notes due April 15, 2027
5.500% Senior Notes due 2027 | ETO [Member]
Senior Notes		$ 956	956
Long-term Debt, Description		5.50% Senior Notes due June 1, 2027
8.25% Senior Notes due November 15, 2029 | ETO [Member]
Senior Notes		$ 267	267
Long-term Debt, Description		8.25% Senior Notes due November 15, 2029
8.25% Senior Notes due November 15, 2029 | Panhandle [Member]
Senior Notes		$ 33	33
Long-term Debt, Description		8.25% Senior Notes due November 15, 2029
4.90% Senior Notes due March 15, 2035 | ETO [Member]
Senior Notes		$ 500	500
Long-term Debt, Description		4.90% Senior Notes due March 15, 2035
6.625% Senior Notes due October 15, 2036 | ETO [Member]
Senior Notes		$ 400	400
Long-term Debt, Description		6.625% Senior Notes due October 15, 2036
5.80% Senior Notes due 2038 [Member] | ETO [Member]
Senior Notes		$ 500	500
Long-term Debt, Description		5.80% Senior Notes due June 15, 2038
7.50% Senior Notes due July 1, 2038 | ETO [Member]
Senior Notes		$ 550	550
Long-term Debt, Description		7.50% Senior Notes due July 1, 2038
6.05% Senior Notes due June 1, 2041 | ETO [Member]
Senior Notes		$ 700	700
Long-term Debt, Description		6.05% Senior Notes due June 1, 2041
6.50% Senior Notes due February 1, 2042 | ETO [Member]
Senior Notes		$ 1,000	1,000
Long-term Debt, Description		6.50% Senior Notes due February 1, 2042
5.15% Senior Notes due February 1, 2043 | ETO [Member]
Senior Notes		$ 450	450
Long-term Debt, Description		5.15% Senior Notes due February 1, 2043
5.95% Senior Notes due October 1, 2043 | ETO [Member]
Senior Notes		$ 450	450
Long-term Debt, Description		5.95% Senior Notes due October 1, 2043
5.15% Senior Notes due March 15, 2045 | ETO [Member]
Senior Notes		$ 1,000	1,000
Long-term Debt, Description		5.15% Senior Notes due March 15, 2045
6.125% Senior Notes due December 15, 2045 | ETO [Member]
Senior Notes		$ 1,000	1,000
Long-term Debt, Description		6.125% Senior Notes due December 15, 2045
5.30% Senior Notes due April 2047 [Member] | ETO [Member]
Senior Notes		$ 900	900
Long-term Debt, Description		5.30% Senior Notes due April 15, 2047
Floating Rate Junior Subordinated Notes due November 1, 2066 | ETO [Member]
Junior Subordinated Notes		$ 546	546
Long-term Debt, Description		Floating Rate Junior Subordinated Notes due November 1, 2066
Floating Rate Junior Subordinated Notes due November 1, 2066 | Panhandle [Member]
Junior Subordinated Notes		$ 54	54
Long-term Debt, Description		Floating Rate Junior Subordinated Notes due November 1, 2066
ETO Term Loan [Member] | ETO [Member]
Revolving credit facilities		$ 2,000	2,000
Long-term Debt, Description		ETO $2.00 billion Term Loan facility due October 2022
3.625% Senior Notes due 2022 [Member] | Bakken Project [Member]
Senior Notes		$ 650	650
Long-term Debt, Description		3.625% Senior Notes due April 1, 2022
3.90% Senior Notes due 2024 [Member] | Bakken Project [Member]
Senior Notes		$ 1,000	1,000
Long-term Debt, Description		3.90% Senior Notes due April 1, 2024
4.625% Senior Notes due 2029 [Member] | Bakken Project [Member]
Senior Notes		$ 850	850
Long-term Debt, Description		4.625% Senior Notes due April 1, 2029
ETP Credit Facility due December 2022 [Member] | ETO [Member]
Revolving credit facilities		$ 3,103	4,214
Long-term Debt, Description		ETO $5.00 billion Revolving Credit Facility due December 2023
5.36% Senior Notes due December 9, 2020 | Transwestern [Member]
Senior Notes		$ 0	175
Long-term Debt, Description		5.36% Senior Notes due December 9, 2020 (1)
5.89% Senior Notes due May 24, 2022 | Transwestern [Member]
Senior Notes		$ 150	150
Long-term Debt, Description		5.89% Senior Notes due May 24, 2022
5.66% Senior Notes due December 9, 2024 | Transwestern [Member]
Senior Notes		$ 175	175
Long-term Debt, Description		5.66% Senior Notes due December 9, 2024
7.00% Senior Notes due July 15, 2029 | Panhandle [Member]
Senior Notes		$ 66	66
Long-term Debt, Description		7.00% Senior Notes due July 15, 2029
9.00% Debentures due November 1, 2024 | ETO [Member]
Subordinated Debt		$ 65	65
Long-term Debt, Description		9.00% Debentures due November 1, 2024
5.50% Senior Notes due February 15, 2020 | ETO [Member]
Senior Notes	[1]	$ 0	250
Long-term Debt, Description		5.50% Senior Notes due February 15, 2020 (1)
4.40% Senior Notes due April 1, 2021 | ETO [Member]
Senior Notes	[2]	$ 600	600
Long-term Debt, Description		4.40% Senior Notes due April 1, 2021 (2)
4.65% Senior Notes due February 15, 2022 | ETO [Member]
Senior Notes		$ 300	300
Long-term Debt, Description		4.65% Senior Notes due February 15, 2022
3.45% Senior Notes due January 15, 2023 | ETO [Member]
Senior Notes		$ 350	350
Long-term Debt, Description		3.45% Senior Notes due January 15, 2023
4.25% Senior Notes due April 1, 2024 | ETO [Member]
Senior Notes		$ 500	500
Long-term Debt, Description		4.25% Senior Notes due April 1, 2024
4.5% Senior Notes due 2024 [Member] | ETO [Member]
Senior Notes		$ 750	750
Long-term Debt, Description		4.50% Senior Notes due April 15, 2024
5.95% Senior Notes due December 1, 2025 | ETO [Member]
Senior Notes		$ 400	400
Long-term Debt, Description		5.95% Senior Notes due December 1, 2025
3.90% Senior Notes due July 15, 2026 | ETO [Member]
Senior Notes		$ 550	550
Long-term Debt, Description		3.90% Senior Notes due July 15, 2026
4.00% Senior Notes due October 1, 2027 [Member] | ETO [Member]
Senior Notes		$ 750	750
Long-term Debt, Description		4.00% Senior Notes due October 1, 2027
4.95% Senior Notes due 2028 [Member] | ETO [Member]
Senior Notes		$ 1,000	1,000
Long-term Debt, Description		4.95% Senior Notes due June 15, 2028
5.25% Senior Notes due 2029 [Member] | ETO [Member]
Senior Notes		$ 1,500	1,500
Long-term Debt, Description		5.25% Senior Notes due April 15, 2029
6.85% Senior Notes due February 15, 2040 | ETO [Member]
Senior Notes		$ 250	250
Long-term Debt, Description		6.85% Senior Notes due February 15, 2040
6.10% Senior Notes due February 15, 2042 | ETO [Member]
Senior Notes		$ 300	300
Long-term Debt, Description		6.10% Senior Notes due February 15, 2042
4.95% Senior Notes due January 15, 2043 | ETO [Member]
Senior Notes		$ 350	350
Long-term Debt, Description		4.95% Senior Notes due January 15, 2043
5.30% Senior Notes due April 1, 2044 | ETO [Member]
Senior Notes		$ 700	700
Long-term Debt, Description		5.30% Senior Notes due April 1, 2044
5.35% Senior Notes due May 15, 2045 | ETO [Member]
Senior Notes		$ 800	800
Long-term Debt, Description		5.35% Senior Notes due May 15, 2045
5.40% Senior Notes due October 1, 2047 [Member] | ETO [Member]
Senior Notes		$ 1,500	1,500
Long-term Debt, Description		5.40% Senior Notes due October 1, 2047
6.0% Senior Notes due 2048 [Member] | ETO [Member]
Senior Notes		$ 1,000	1,000
Long-term Debt, Description		6.00% Senior Notes due June 15, 2048
6.25% Senior Notes due 2049 [Member] | ETO [Member]
Senior Notes		$ 1,750	1,750
Long-term Debt, Description		6.25% Senior Notes due April 15, 2049
5.75% Senior Notes due September 1, 2020 | ETO [Member]
Senior Notes	[1]	$ 0	400
Long-term Debt, Description		5.75% Senior Notes due September 1, 2020 (1)
5.875% Senior Notes due March 1, 2022 | ETO [Member]
Senior Notes		$ 900	900
Long-term Debt, Description		5.875% Senior Notes due March 1, 2022
5.00% Senior Notes due October 1, 2022 | ETO [Member]
Senior Notes		$ 700	700
Long-term Debt, Description		5.00% Senior Notes due October 1, 2022
4.50% Senior Notes due November 1, 2023 | ETO [Member]
Senior Notes		$ 600	600
Long-term Debt, Description		4.50% Senior Notes due November 1, 2023
Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | ETO [Member]
Revolving credit facilities		$ 0
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]
Unamortized premiums, discounts and fair value adjustments, net		(3)	(3)
4.875% senior notes due 2023 [Member] | Sunoco LP [Member]
Senior Notes		$ 436	1,000
Long-term Debt, Description		4.875% Senior Notes Due January 15, 2023
5.500% senior notes due 2026 [Member] | Sunoco LP [Member]
Senior Notes		$ 800	800
Long-term Debt, Description		5.50% Senior Notes Due February 15, 2026
6.00% Senior Notes due April 15, 2027 [Member] | Sunoco LP [Member]
Senior Notes		$ 600	600
Long-term Debt, Description		6.00% Senior Notes Due April 15, 2027
5.875% senior notes due 2028 [Member] | Sunoco LP [Member]
Senior Notes		$ 400	400
Long-term Debt, Description		5.875% Senior Notes Due March 15, 2028
Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member] | Sunoco LP [Member]
Revolving credit facilities		$ 0	162
Long-term Debt, Description		Sunoco LP $1.50 billion Revolving Credit Facility due July 2023
HFOTCO Tax Exempt Notes due 2050 [Member] | SemGroup [Member]
Senior Notes		$ 225	225
Long-term Debt, Description		HFOTCO Tax Exempt Notes due 2050
Energy Transfer Canada Revolver [Member] | SemGroup [Member]
Revolving credit facilities		$ 57	92
Long-term Debt, Description		Energy Transfer Canada Revolver due February 25, 2024
Energy Transfer Canada Term Loan [Member] | SemGroup [Member]
Revolving credit facilities		$ 261	269
Long-term Debt, Description		Energy Transfer Canada Term Loan A due February 25, 2024
6.875% Senior notes due April 2026 [Member] | USA Compression Partners, LP [Member]
Senior Notes		$ 725	725
Long-term Debt, Description		6.875% Senior Notes due April 1, 2026
4.50% Senior Notes due May 15, 2029 [Member] | Sunoco LP [Member]
Senior Notes		$ 800	0
Long-term Debt, Description		4.50% Senior Notes due May 15, 2029
2.9% Senior Notes due May 15, 2025 [Member] | ETO [Member]
Senior Notes		$ 1,000	0
Long-term Debt, Description		2.90% Senior Notes due May 15, 2025
3.75 Senior Notes due May 15, 2030 [Member] | ETO [Member]
Senior Notes		$ 1,500	0
Long-term Debt, Description		3.75% Senior Note due May 15, 2030
5.00% Senior Notes due May 15, 2050 [Member] | ETO [Member]
Senior Notes		$ 2,000	0
Long-term Debt, Description		5.00% Senior Notes due May 15, 2050
6.16% Senior Notes due May 24, 2037 | Transwestern [Member]
Senior Notes		$ 75	$ 75
Long-term Debt, Description		6.16% Senior Notes due May 24, 2037
[1]	As of December 31, 2019, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The notes were redeemed in January 2020.
[2]	As of December 31, 2020, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.

Debt Obligations (Future maturi

Debt Obligations (Future maturities of long-term debt) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Obligations [Abstract]
2021	$ 1,420
2022	5,731
2023	7,287
2024	4,598
2025	2,408
Thereafter	30,211
Long-term Debt	51,366	$ 50,930
Long-term Debt, Gross	$ 51,655

Redeemable Noncontrolling Int_2

Redeemable Noncontrolling Interest (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 31, 2021	Apr. 02, 2018
Redeemable noncontrolling interests		$ 762	$ 739
Preferred units issued for cash		1,580	$ 780	$ 867
Subsequent Event [Member]
Preferred Stock, Redemption Price Per Share					$ 864
Canada, Dollars | Subsequent Event [Member]
Preferred Stock, Redemption Price Per Share					$ 1,100
USAC [Member]
Redeemable noncontrolling interests		477
ETO [Member]
Redeemable noncontrolling interests		15
SemCAMS [Member]
Redeemable noncontrolling interests		$ 270
Preferred Stock, Shares Outstanding		300,000
Preferred Units [Member] | USAC [Member]
Preferred Units, Issued						500,000
Shares Issued, Price Per Share						$ 1,000
Preferred units issued for cash	$ 500
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 24.375
Preferred Units [Member] | SemCAMS [Member]
Preferred Units, Issued		344,419

Equity (Narrative) (Details)

Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 01, 2020	Jul. 31, 2019	Apr. 30, 2019	Jul. 31, 2018	Apr. 30, 2018	Nov. 30, 2017	Jun. 30, 2020	Dec. 31, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 31, 2021	Jan. 31, 2020	Jul. 30, 2019	Apr. 02, 2018
Common units issued for cash									$ 0	$ 0	$ 58
Partners' Capital Account, Sale of Units									1,580	780	925
Payments for Repurchase of Common Stock									$ 0	0	24
Series A Preferred Units [Member]
Preferred Units, Outstanding									950,000
Partners' Capital Account, Sale of Units									$ 0	0	0
Series B Preferred Units [Member]
Preferred Units, Outstanding									550,000
Partners' Capital Account, Sale of Units									$ 0	0	0
Series C Preferred Units
Preferred Units, Outstanding									18,000,000
Partners' Capital Account, Sale of Units									$ 0	0	436
Series D Preferred Units
Preferred Units, Outstanding									17,800,000
Partners' Capital Account, Sale of Units									$ 0	0	431
Series E Preferred Units [Member]
Preferred Units, Outstanding									32,000,000
Partners' Capital Account, Sale of Units									$ 0	780	0
Series F Preferred Units [Member]
Preferred Units, Outstanding									500,000
Partners' Capital Account, Sale of Units									$ 494	0	0
Series G Preferred Units [Member]
Preferred Units, Outstanding									1,100,000
Partners' Capital Account, Sale of Units									$ 1,086	0	0
Sunoco LP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.									28,500,000
Payments for Repurchase of Common Stock									$ 0	$ 0	300
USAC [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.										39,700,000				46,100,000
Limited Partners' Capital Account, Units Outstanding									97,000,000
Stock Issued During Period, Value, Dividend Reinvestment Plan									$ 1.9	$ 1
Stock Issued During Period, Shares, Dividend Reinvestment Plan									188,695	60,584
Accumulated Other Comprehensive Income (Loss)
Partners' Capital Account, Sale of Units									$ 0	$ 0	$ 0
Series G Preferred Units [Member]
Preferred Units, Issued									1,100,000	0
Preferred Units, Outstanding									1,100,000	0
Class K Units [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.									101,500,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit								$ 0.67275
Cash Distributions, Percent									1.50%
Class L Units [Member]
Cash Distributions, Percent									7.65%
Class M Units [Member]
Preferred Stock, Dividend Rate, Percentage									8.00%
Series A Preferred Units [Member]
Preferred Stock, Dividend Rate, Percentage						6.25%
Shares Issued, Price Per Share						$ 1,000
Preferred Units, Issued									950,000	950,000
Preferred Units, Liquidation Spread, Percent						4.028%
Preferred Units, Outstanding									950,000	950,000
Series C Preferred Units
Preferred Stock, Dividend Rate, Percentage					7.375%
Shares Issued, Price Per Share					$ 25
Preferred Units, Issued									18,000,000	18,000,000
Preferred Units, Liquidation Spread, Percent					4.53%
Preferred Units, Outstanding									18,000,000	18,000,000
Series B Preferred Units [Member]
Preferred Stock, Dividend Rate, Percentage						6.625%
Shares Issued, Price Per Share						$ 1,000
Preferred Units, Issued									550,000	550,000
Preferred Units, Liquidation Spread, Percent						4.155%
Preferred Units, Outstanding									550,000	550,000
Series D Preferred Units
Preferred Stock, Dividend Rate, Percentage				7.625%
Shares Issued, Price Per Share				$ 25		$ 25
Preferred Units, Issued									17,800,000	17,800,000
Preferred Units, Liquidation Spread, Percent				4.738%
Preferred Units, Outstanding									17,800,000	17,800,000
Series E Preferred Units [Member]
Preferred Stock, Dividend Rate, Percentage			7.60%
Shares Issued, Price Per Share			$ 25
Preferred Units, Issued									32,000,000	0
Preferred Units, Liquidation Spread, Percent			5.161%
Preferred Units, Outstanding									32,000,000	0
Series F Preferred Units [Member]
Preferred Units, Issued									500,000	0
Preferred Units, Outstanding									500,000	0
Class B Units [Member] | USAC [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.										6,400,000
Partners' Capital Account, Units, Converted		6,397,965
Class N Units [Member]
Preferred Stock, Dividend Rate, Percentage									1.50%
Distribution Made to Limited Partner, Distributions Declared, Per Unit							$ 0.2375
USAC [Member]
Stock Issued During Period, Shares, Conversion of Units		6,397,965
Strike price of $17.03 [Member] | USAC [Member]
Class of Warrant or Right, Number of Securities Called by Warrants or Rights															5,000,000
Class of Warrant or Right, Exercise Price of Warrants or Rights															$ 17.03
Strike price of $19.59 [Member] | USAC [Member]
Class of Warrant or Right, Number of Securities Called by Warrants or Rights															10,000,000
Class of Warrant or Right, Exercise Price of Warrants or Rights															$ 19.59
Equity Distribution Program [Member] | Sunoco LP [Member]
Partners' Capital Account, Units, Sale of Units									0
Equity Distribution Agreements, Value of Units Available to be Issued									$ 295
Subsequent Event [Member]
Preferred Stock, Redemption Price Per Share												$ 864
Subsequent Event [Member] | Series G Preferred Units [Member]
Preferred Stock, Dividend Rate, Percentage	7.125%
Shares Issued, Price Per Share													$ 1,000
Preferred Units, Issued													1,100,000
Preferred Units, Liquidation Spread, Percent													5.306%
Subsequent Event [Member] | Series F Preferred Units [Member]
Preferred Stock, Dividend Rate, Percentage	6.75%
Shares Issued, Price Per Share													$ 1,000
Preferred Units, Issued													500,000
Preferred Units, Liquidation Spread, Percent													5.134%

Equity (Accumulated other compr

Equity (Accumulated other comprehensive income, net of tax) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Equity [Abstract]
AOCI, Debt Securities, Available-for-sale, Adjustment, after Tax	$ 18	$ 13
Foreign currency translation adjustment	7	(5)
Actuarial gain (loss) related to pensions and other postretirement benefits	(7)	(25)
AOCI attributable to equity method investments	(14)	(1)
Total AOCI, net of tax	6	(18)
AOCI Including Portion Attributable to Noncontrolling Interest, Tax	4	(18)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Noncontrolling Interest	$ 2	$ 0

Equity (Tax amounts attributabl

Equity (Tax amounts attributable to Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Equity [Abstract]
Other Comprehensive Income (Loss), Securities, Available-for-sale, Tax	$ (1)	$ (1)
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax	8	2
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	3	8
Other Comprehensive Income (Loss), Tax	$ 10	$ 9

Equity Distribution Targets (De

Equity Distribution Targets (Details)	3 Months Ended
	Dec. 31, 2019
Minimum Quarterly Distribution [Member]
Distribution Payment Targets	$0.4375
Minimum Quarterly Distribution [Member] | IDRs [Member]
Distribution Payment Targets	—%
First Target Distribution [Member]
Distribution Payment Targets	$0.4375 to $0.503125
First Target Distribution [Member] | IDRs [Member]
Distribution Payment Targets	—%
Second Target Distribution [Member]
Distribution Payment Targets	$0.503125 to $0.546875
Second Target Distribution [Member] | IDRs [Member]
Distribution Payment Targets	15%
Third Target Distribution [Member]
Distribution Payment Targets	$0.546875 to $0.656250
Third Target Distribution [Member] | IDRs [Member]
Distribution Payment Targets	25%
Thereafter [Member]
Distribution Payment Targets	Above $0.656250
Thereafter [Member] | IDRs [Member]
Distribution Payment Targets	50%

Equity Distributions on Preferr

Equity Distributions on Preferred Units (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended															12 Months Ended
		Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019		Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018		Jun. 30, 2018		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 32,950					$ 37,425					$ 36,788					$ 32,950	$ 37,425	$ 36,788	$ 37,079
Distributions to partners																	(5,265)	(6,284)	(4,556)
Partners' Capital Account, Sale of Units																	1,580	780	925
Other, net																	18	(10)	35
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest																	262	5,064	3,790
Series D Preferred Units
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 434					$ 434					$ 434					434	434	434	0
Distributions to partners																	(34)	(34)	(11)
Partners' Capital Account, Sale of Units																	0	0	431
Other, net																	0	0	(1)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest																	34	34	15
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.4766	$ 0.4766	$ 0.4766	$ 0.4766		$ 0.4766	$ 0.4766	$ 0.4766		$ 0.4766	$ 0.4766	$ 0.5931	[1]	$ 0
Series C Preferred Units
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 440					$ 440					$ 440					440	440	440	0
Distributions to partners																	(33)	(33)	(18)
Partners' Capital Account, Sale of Units																	0	0	436
Other, net																	0	0	(1)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest																	33	33	23
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.4609	0.4609	0.4609	0.4609		$ 0.4609	0.4609	0.4609		0.4609	$ 0.4609	0.4609		0.5634	[1]
Series B Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 556					$ 556					$ 556					556	556	556	547
Distributions to partners																	(37)	(37)	(27)
Partners' Capital Account, Sale of Units																	0	0	0
Other, net																	0	0	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest																	37	37	36
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[2]	$ 33.1250	0	33.1250	0		$ 33.1250	0	33.1250		0	$ 33.1250	0		33.1250
Series A Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 958					$ 958					$ 958					958	958	958	944
Distributions to partners																	(59)	(59)	(44)
Partners' Capital Account, Sale of Units																	0	0	0
Other, net																	0	0	(1)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest																	59	59	59
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[2]	$ 31.2500	0	31.2500	0		$ 31.2500	0	31.2500		0	$ 31.2500	0		31.2500
Series E Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 786					$ 786					$ 0					786	786	0	0
Distributions to partners																	(61)	(34)	0
Partners' Capital Account, Sale of Units																	0	780	0
Other, net																	0	(1)	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest																	61	41	0
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.4750	0.4750	0.4750	0.4750		$ 0.4750	0.4750	0.5806	[1]	0	$ 0	0		0
Series F Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 496					$ 0					$ 0					496	0	0	0
Distributions to partners																	(27)	0	0
Partners' Capital Account, Sale of Units																	494	0	0
Other, net																	(2)	0	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest																	31	0	0
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[2]	$ 0	33.75	0	21.19	[1]	$ 0	0	0		0	$ 0	0		0
Series G Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 1,094					$ 0					$ 0					1,094	0	0	0
Distributions to partners																	(64)	0	0
Partners' Capital Account, Sale of Units																	1,086	0	0
Other, net																	(2)	0	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest																	74	0	0
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[2]	$ 0	$ 35.625	$ 0	$ 22.36	[1]	$ 0	$ 0	$ 0		$ 0	$ 0	$ 0		$ 0
Preferred Units [Member]
Class of Stock [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest		$ 4,764					$ 3,174					$ 2,388					4,764	3,174	2,388	$ 1,491
Distributions to partners																	(315)	(197)	(100)
Partners' Capital Account, Sale of Units																	1,580	780	867
Other, net																	(4)	(1)	(3)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest																	$ 329	$ 204	$ 133
[1]	Represent prorated initial distributions.
[2]	ETO Series A Preferred Unit, ETO Series B Preferred Unit, ETO Series F Preferred Unit and ETO Series G Preferred Unit distributions are paid on a semi-annual basis.

Equity Quarterly Distribution o

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

3 Months Ended

Dec. 31, 2020

Sep. 30, 2020

Jun. 30, 2020

Mar. 31, 2020

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Minimum Quarterly Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

$0.4375

First Target Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

$0.4375 to $0.503125

Second Target Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

$0.503125 to $0.546875

Third Target Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

$0.546875 to $0.656250

Thereafter [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

Above $0.656250

Sunoco LP [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.8255

$ 0.8255

$ 0.8255

$ 0.8255

$ 0.8255

$ 0.8255

$ 0.8255

$ 0.8255

$ 0.8255

$ 0.8255

$ 0.8255

$ 0.8255

$ 0.8255

USAC [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.5250

$ 0.5250

$ 0.5250

$ 0.5250

$ 0.5250

$ 0.5250

$ 0.5250

$ 0.5250

$ 0.5250

$ 0.5250

$ 0.5250

$ 0.5250

IDRs [Member] | Minimum Quarterly Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

—%

IDRs [Member] | First Target Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

—%

IDRs [Member] | Second Target Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

15%

IDRs [Member] | Third Target Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

25%

IDRs [Member] | Thereafter [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

50%

Limited Partner [Member] | Minimum Quarterly Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

100%

Limited Partner [Member] | First Target Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

100%

Limited Partner [Member] | Second Target Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

85%

Limited Partner [Member] | Third Target Distribution [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

75%

Limited Partner [Member] | Thereafter [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Payment Targets

50%

Unit-Based Compensation Plans_3

Unit-Based Compensation Plans (Narrative) (Details) - Subsidiary Unit Based Compensation [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Total fair value of awards vested	$ 16	$ 17	$ 22
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 39
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Terms	3 years 7 months 6 days

Unit-Based Compensation Plans S

Unit-Based Compensation Plans Subsidiary unit award rollforward (Details) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Sunoco LP Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	2.1	2.1
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 28.63	$ 29.21
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	0.7
Awards granted	$ 28.63	$ 30.70	$ 27.67
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(0.5)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 30.47
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 29.11
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	0.2
USAC Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	2.1	1.8
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 14.88	$ 15.09
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	0.7
Awards granted	$ 12.55	$ 15.88	$ 15.47
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(0.2)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 17.27
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 15.36
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	0.2

Income Taxes Narrative (Details

Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Oct. 31, 2019
Income Tax Contingency [Line Items]
Deferred Tax Liabilities, Gross	$ 4,339	$ 4,104
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, Ater Tax	48
Unrecognized Tax Benefits, Interest on Income Taxes Expense	7
Income Tax Examination, Penalties and Interest Accrued	10
Operating Loss Carryforwards	787
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	1,300
Net operating losses, alternative minimum tax credit and other carryforwards	1,047	936
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	90
Deferred Tax Assets, Valuation Allowance	134	95
State	32	$ (2)	$ 20
Tax Credit Carryforward, Valuation Allowance	89
ETP Holdco and other corporate subsidiaries [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	3,730
Corporate Subsidiaries [Member]
Income Tax Contingency [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	174
Deferred Tax Asset, Interest Carryforward	129
Corporate Subsidiaries [Member] | Canada, Dollars
Income Tax Contingency [Line Items]
Tax Credit Carryforward, Valuation Allowance	45
Sunoco, Inc. [Member]
Income Tax Contingency [Line Items]
Estimated Litigation Liability				$ 530
Sunoco Property Company LLC [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	0
Sunoco LP [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	121
Net of federal tax [Member]
Income Tax Contingency [Line Items]
State	53
CANADA
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	7
Pennsylvania Constitution [Member]
Income Tax Contingency [Line Items]
State	67
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	34
Pennsylvania Constitution [Member] | Net of federal tax [Member]
Income Tax Contingency [Line Items]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	$ 27

Income Taxes Compoenents of Fed

Income Taxes Compoenents of Federal and State Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current expense (benefit):
Federal	$ (6)	$ (20)	$ (7)
State	32	(2)	20
Current expense (benefit) - Total	27	(22)	13
Deferred expense (benefit):
Federal	178	176	183
State	41	45	(191)
Deferred expense (benefit) - Total	212	221	(8)
Income tax expense	239	199	5
Deferred Foreign Income Tax Expense (Benefit)	(7)	0	0
Current Foreign Tax Expense (Benefit)	$ 1	$ 0	$ 0

Income Taxes Statutory Income T

Income Taxes Statutory Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income tax expense at United States statutory rate	$ 116	$ 1,116	$ 861
Partnership earnings not subject to tax	54	(925)	(730)
Noncontrolling interests	16	0	0
Foreign	58	14	(125)
Dividend received deduction	0	(3)	(5)
Other	2	(3)	4
Income tax expense	239	199	5
Deferred Foreign Income Tax Expense (Benefit)	$ (7)	$ 0	$ 0

Income Taxes Tax Effects of Tem

Income Taxes Tax Effects of Temporary Differences (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred income tax assets:
Net operating losses, alternative minimum tax credit and other carryforwards	$ 1,047	$ 936
Pension and other postretirement benefits	0	7
Other	34	85
Total deferred income tax assets	1,081	1,028
Valuation allowance	(134)	(95)
Net deferred income tax assets	947	933
Deferred income tax liabilities:
Property, plant and equipment	(263)	(464)
Investments in affiliates	(3,994)	(3,547)
Trademarks	77	72
Other	(5)	(21)
Total deferred income tax liabilities	(4,339)	(4,104)
Net deferred income taxes	$ (3,392)	$ (3,171)

Income Taxes Components of Net

Income Taxes Components of Net Deferred Income Tax (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	$ 263	$ 464
Trademarks	77	72
Deferred Tax Liabilities, Investment in Noncontrolled Affiliates	3,994	3,547
Deferred Tax Liabilities, Other	5	21
Net operating losses, alternative minimum tax credit and other carryforwards	1,047	936
Pension and other postretirement benefits	0	7
Other	34	85
Deferred Tax Assets, Gross	1,081	1,028
Valuation allowance	(134)	(95)
Deferred Tax Assets, Net	947	933
Deferred Tax Liabilities, Gross	$ (4,339)	$ (4,104)

Income Taxes Changes in Unrecog

Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Balance at beginning of year	$ 94	$ 624	$ 609
Additions attributable to tax positions taken in the current year	0	0	8
Additions attributable to tax positions taken in prior years	0	11	7
Reduction attributable to tax positions taken in prior years	0	(541)	0
Lapse of statute	(4)	0	0
Balance at end of year	$ 90	$ 94	$ 624

Regulatory Matters, Commitmen_3

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Narrative) (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2020	Mar. 31, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
ROW expense			$ 47,000,000	$ 45,000,000	$ 46,000,000
Site Contingency, Number of Sites Needing Remediation			35
Loss Contingency, Damages Awarded, Value			$ 80,700,000
Accrual for Environmental Loss Contingencies			306,000,000	320,000,000
Payments for Environmental Liabilities			29,000,000	39,000,000
Long-term Debt			51,366,000,000	50,930,000,000
Loss Contingency, Range of Possible Loss, Portion Not Accrued			80,000,000
Operating Loss Carryforwards			787,000,000
Payments for Legal Settlements	$ 74,800,000	$ 5,400,000
CANADA
Operating Loss Carryforwards			7,000,000
PES [Member]
Repayment of Notes Receivable from Related Parties			12,000,000
Loans and Leases Receivable, Allowance			63,000,000
Sunoco LP [Member]
Long-term Debt			3,112,000,000	3,071,000,000
Operating Loss Carryforwards			$ 121,000,000
Senior Notes Tendered, Percentage			56.00%
Corporate Subsidiaries [Member]
Deferred Tax Asset, Interest Carryforward			$ 129,000,000
PES [Member]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest			7.40%
Debt Instrument, Debt Default, Amount			$ 75,000,000
Related To Deductibles [Member]
Loss Contingency Accrual, at Carrying Value			77,000,000	120,000,000
Civil Penalty [Member]
Loss Contingency, Damages Awarded, Value			28,600,000
Community Environmental Project [Member]
Loss Contingency, Damages Awarded, Value			2,000,000
Punitive Damages [Member]
Loss Contingency, Damages Awarded, Value			75,000,000
4.875% senior notes due 2023 [Member] | Sunoco LP [Member]
Senior Notes			436,000,000	1,000,000,000
5.500% senior notes due 2026 [Member] | Sunoco LP [Member]
Senior Notes			800,000,000	800,000,000
5.875% senior notes due 2028 [Member] | Sunoco LP [Member]
Senior Notes			$ 400,000,000	$ 400,000,000

Regulatory Matters, Commitmen_4

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Rent Expense and Future minimum lease commitments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
ROW expense	$ 47	$ 45	$ 46

Regulatory Matters, Commitmen_5

Regulatory Matters, Commitments, Contingencies and Environmental Matters (Liabilities Related to Environmental Matters) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Environmental Remediation Obligations [Abstract]
Accrued Environmental Loss Contingencies, Current	$ 44	$ 46
Accrued Environmental Loss Contingencies, Noncurrent	262	274
Accrual for Environmental Loss Contingencies	$ 306	$ 320

Revenue Narrative (Details)

Revenue Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue, Remaining Performance Obligation, Amount	$ 40,347
Sunoco LP [Member]
Capitalized Contract Cost, Amortization	$ 18	$ 17	$ 14

Revenue Contract Balances (Deta

Revenue Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2019	Jan. 01, 2018
Revenue from External Customer [Line Items]
Increase (Decrease) in Accounts Receivable	$ (1,163)	$ 473	$ (506)
Contract with Customer, Liability	290	365			$ 394
Deferred Revenue, Additions	771	651
Contract with Customer, Liability, Revenue Recognized	$ (846)	(680)
Sunoco LP [Member]
Revenue from External Customer [Line Items]
Contract with Customer, Asset, after Allowance for Credit Loss		117		$ 121
Receivables from Customers		$ 366		$ 256

Revenue Future Obligations (Det

Revenue Future Obligations (Details) $ in Millions	Dec. 31, 2020USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 40,347
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	5,120
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	5,475
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-12-31
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	5,051
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-12-31
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 24,701

Lease Accounting Lessee Account

Lease Accounting Lessee Accounting (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 99
Net Cash Provided by (Used in) Operating Activities	$ 7,869	$ 8,298	$ 7,559
Operating Lease, Weighted Average Remaining Lease Term	22 years	24 years
Operating Lease, Cost	$ 106	$ 117
Operating Lease, Right-of-Use Asset	1,000	964
Operating lease current liabilities	53	60
Accrued and other current liabilities	2,769	3,336
Current maturities of long-term debt	21	26
Non-current operating lease liabilities	837	901
Property, Plant and Equipment, Net	74,819	73,896
Long-term debt, less current maturities	51,345	50,904
Other non-current liabilities	1,152	1,162
Finance Lease, Interest Expense	1	1
Lease, Cost	109	136
Lease, Cost, Gross	$ 157	$ 183
Finance Lease, Weighted Average Remaining Lease Term	9 years	5 years
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	$ 0	$ 28
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	42	40
Finance Lease, Liability, Payments, Remainder of Fiscal Year	2
Lease Liabilities, Remainder of Year	101
Lessee, Operating Lease, Liability, Payments, Due Year Two	85
Finance Lease, Liability, Payments, Due Year Two	2
Lease Liabilities, Due Year Two	87
Lessee, Operating Lease, Liability, Payments, Due Year Three	79
Finance Lease, Liability, Payments, Due Year Three	2
Lease Liabilities, Due Year Three	81
Lessee, Operating Lease, Liability, Payments, Due Year Four	76
Finance Lease, Liability, Payments, Due Year Four	1
Lease Liabilities, Due Year Four	77
Lessee, Operating Lease, Liability, Payments, Due Year Five	75
Finance Lease, Liability, Payments, Due Year Five	1
Lease Liabilities, Due Year Five	76
Lessee, Operating Lease, Liability, Payments, Due after Year Five	1,140
Finance Lease, Liability, Payments, Due after Year Five	4
Lease Liabilities, Due After Five Years	1,144
Lessee, Operating Lease, Liability, Payments, Due	1,554
Finance Lease, Liability, Payment, Due	12
Lease Liabilities, Due	1,566
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	664
Finance Lease, Liability, Undiscounted Excess Amount	3
Lease Liability, Undiscounted Excess Amount	667
Operating Lease, Liability	890
Finance Lease, Liability	9
Lease, Liabilities	899
Operating Leases [Member]
Net Cash Provided by (Used in) Operating Activities	(117)	(159)
Operating Lease, Right-of-Use Asset	863	935
Operating lease current liabilities	53	60
Accrued and other current liabilities	1	1
Non-current operating lease liabilities	837	901
Finance Leases [Member]
Accrued and other current liabilities	1	1
Current maturities of long-term debt	1	6
Property, Plant and Equipment, Net	1	1
Finance Lease, Right-of-Use Asset	3	29
Long-term debt, less current maturities	6	26
Other non-current liabilities	1	2
Lease, Cost	$ 4	7
Real Estate [Member]
Lessee, Operating Lease, Term of Contract	40 years
Maximum [Member]
Lessee, Operating Lease, Renewal Term	20 years
Maximum [Member] | Equipment [Member]
Lessee, Operating Lease, Term of Contract	15 years
Minimum [Member]
Lessee, Operating Lease, Renewal Term	1 year
Minimum [Member] | Equipment [Member]
Lessee, Operating Lease, Term of Contract	5 years
Cost of Goods and Service Benchmark [Member]
Operating Lease, Cost	$ 14	28
Operating Expense [Member]
Operating Lease, Cost	75	73
Short-term Lease, Cost	31	42
Variable Lease, Cost	16	17
Selling, General and Administrative Expenses [Member]
Operating Lease, Cost	17	16
Depreciation And Amortization [Member]
Finance Lease, Right-of-Use Asset, Amortization	3	6
Other Revenue [Member]
Sublease Income	$ 48	$ 47
ETO [Member]
Operating Lease, Weighted Average Discount Rate, Percent	5.00%	5.00%
Finance Lease, Weighted Average Discount Rate, Percent	8.00%	5.00%

Lease Accounting Lessor Account

Lease Accounting Lessor Accounting (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Lessor, Operating Lease, Payments to be Received, Next Twelve Months	$ 103
Lessor, Operating Lease, Payments to be Received, Two Years	64
Lessor, Operating Lease, Payments to be Received, Three Years	8
Lessor, Operating Lease, Payments to be Received, Four Years	3
Lessor, Operating Lease, Payments to be Received, Five Years	2
Lessor, Operating Lease, Payments to be Received, Thereafter	5
Lessor, Operating Lease, Payments to be Received	185
Rental Income, Nonoperating	$ 144	$ 149

Derivative assets and liabilt_3

Derivative assets and liabilties (Outstanding commodity-related derivatives) (Details)		Dec. 31, 2020BBtuMWMB_blsbarrelsbushels	Dec. 31, 2019barrelsMMbtuBBtuMWbushels
Natural Gas [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount		(53,575)	(3,085)
Natural Gas [Member] | Fixed Swaps Futures [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Derivative, Nonmonetary Notional Amount		(1,603)	(1,483)
Natural Gas [Member] | Fixed Swaps Futures [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount		(30,113)	(31,780)
Natural Gas [Member] | Forward Physical Contracts [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount		(11,861)	(13,364)
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount		(29,173)	(18,923)
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount	[1]	(44,225)	(35,208)
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount		(30,113)	(31,780)
Natural Gas [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Long [Member]
Derivative, Nonmonetary Notional Amount		(11,208)
Natural Gas [Member] | Swing Swaps IFERC [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount			(9,265)
Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Long [Member]
Derivative, Nonmonetary Notional Amount		(30,113)	(31,780)
Power [Member] | Call Option [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Derivative, Nonmonetary Notional Amount | MW		(2,343,293)
Power [Member] | Call Option [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount | MW			(2,704,330)
Power [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Derivative, Nonmonetary Notional Amount | MW		(1,392,400)	(3,213,450)
Power [Member] | Future [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Derivative, Nonmonetary Notional Amount | MW		(18,706)
Power [Member] | Future [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount | MW			(353,527)
Power [Member] | Put Option [Member] | Mark to Market Derivatives [Member] | Trading [Member] | Long [Member]
Derivative, Nonmonetary Notional Amount | MW		(519,071)	(51,615)
Natural Gas Liquids [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount		(5,840)	(1,300)
Crude Oil [Member] | Forward Swaps [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Long [Member]
Derivative, Nonmonetary Notional Amount | barrels		0	(4,465)
Refined Products [Member] | Future [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount		(2,765)	(2,473)
Corn [Member] | Future [Member] | Mark to Market Derivatives [Member] | Non Trading [Member] | Short [Member]
Derivative, Nonmonetary Notional Amount | bushels		0	(1,210)
[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 liabilt_4

Derivative assets and liabilties (Interest rate swaps outstanding) (Details) - Forward-Starting Swaps [Member] - Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
July 2020 [Member]
Description of Interest Rate Derivative Activities	[1],[2],[3]	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate
Derivative, Notional Amount	[2],[3]	$ 0	$ 400
July 2021 [Member]
Description of Interest Rate Derivative Activities	[1],[2]	Forward-starting to pay a fixed rate of 3.55% and receive a floating rate
Derivative, Notional Amount	[2]	$ 400	400
July 2022 [Member]
Description of Interest Rate Derivative Activities	[1],[2]	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
Derivative, Notional Amount	[2]	$ 400	$ 400
[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.
[3]	The July 2020 interest rate swaps were terminated in January 2020.

Derivative assets and liabilt_5

Derivative assets and liabilties (Fair Value of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Total derivative assets	$ 168	$ 384
Total derivative liabilities	(717)	(788)
Derivative Asset, Fair Value, Net	60	48
Derivative Liability, Fair Value, Net	609	452
Designated as Hedging Instrument [Member]
Total derivative assets	25	24
Total derivative liabilities	(32)	0
Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) [Member]
Total derivative assets	25	24
Total derivative liabilities	(32)	0
Not Designated as Hedging Instrument [Member]
Total derivative assets	143	360
Total derivative liabilities	(685)	(788)
Not Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits) [Member]
Total derivative assets	90	319
Total derivative liabilities	(166)	(350)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivative assets	53	41
Total derivative liabilities	(71)	(39)
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivative assets	0	0
Total derivative liabilities	$ (448)	$ (399)

Derivative assets and liabilt_6

Derivative assets and liabilties (Netting table) (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 168	$ 384
Derivative Liability, Fair Value, Gross Liability	(717)	(788)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(44)	(18)
Derivative Liability, Fair Value, Amount Offset Against Collateral	44	18
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(64)	(318)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	64	318
Derivative Asset, Fair Value, Net	60	48
Derivative Liability, Fair Value, Net	(609)	(452)
Without offsetting agreements [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(448)	(399)
OTC Contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	53	41
Derivative Liability, Fair Value, Gross Liability	(71)	(39)
Broker cleared derivative contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	115	343
Derivative Liability, Fair Value, Gross Liability	$ (198)	$ (350)

Derivative assets and liabilt_7

Derivative assets and liabilties (Partnership's derivative assets and liabilities, recognized OCI on derivatives (effective portion)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cost of Sales [Member] | Commodity [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 0	$ 0	$ (3)

Derivative assets and liabilt_8

Derivative assets and liabilties (Partnership's derivative assets and liabilities, amount of gain/(loss) reclassified from AOCI into income (effective portion)) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Amount of Gain (Loss) Recognized In Income On Derivatives	$ (229)	$ (323)	$ (23)
Gains (losses) on interest rate derivatives	(203)	(241)	47
Commodity [Member] | Cost of Sales [Member]
Amount of Gain (Loss) Recognized in Income on Ineffective Portion	0	0	(3)
Trading [Member] | Commodity [Member] | Cost of Sales [Member]
Amount of Gain (Loss) Recognized In Income On Derivatives	8	21	32
Trading [Member] | Commodity [Member] | Trading Revenue
Amount of Gain (Loss) Recognized In Income On Derivatives	0	(3)	0
Non Trading [Member] | Commodity [Member] | Cost of Sales [Member]
Amount of Gain (Loss) Recognized In Income On Derivatives	$ (34)	$ (100)	$ (102)

Retirement Benefits (Narratives

Retirement Benefits (Narratives) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to the 401(k) savings plan	$ 35	$ 66	$ 62
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Large Cap US Equitiies	100.00%	100.00%
Current portion of expected future benefit	$ 6
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Large Cap US Equitiies	59.00%	59.00%
Fixed Income Securities	40.00%	40.00%
Cash Fund Investments	1.00%	1.00%
Current portion of expected future benefit	$ 8
Minimum [Member] | Equity [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Investment Policy and Strategy, Description	25.00%
Minimum [Member] | Fixed Income Investments [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Investment Policy and Strategy, Description	65.00%
Maximum [Member] | Equity [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Investment Policy and Strategy, Description	35.00%
Maximum [Member] | Fixed Income Investments [Member] | Panhandle [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Investment Policy and Strategy, Description	75.00%

Retirement Benefits Obligations

Retirement Benefits Obligations and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Interest cost	$ 3	$ 3
Benefit obligation		52
Defined Benefit Plan, Service Cost	0	0
Fair value of plan assets	45	43
Amount underfunded		9
Other Postretirement Benefit Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(16)	(16)
Interest cost	5	7
Actuarial (gain) loss and other	10	18
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Settlement	0	0
Defined Benefit Plan, Benefit Obligation, Business Combination	0	0
Benefits paid, net	(16)	(16)
Defined Benefit Plan, Plan Assets, Payment for Settlement	0	0
Defined Benefit Plan, Plan Assets, Business Combination	0	0
Return on plan assets and other	28	35
Employer contributions	9	10
Benefit obligation	208	208	$ 198
Defined Benefit Plan, Service Cost	1	1
Fair value of plan assets	291	270	241
Amount underfunded	(83)	(62)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	108	88
Current liabilities	(2)	(2)
Non-current liabilities	(23)	(24)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	83	62
Net actuarial gain (loss)	(18)	(5)
Prior service cost	21	40
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	3	35
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	55	51
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(2)	(1)
Interest cost	2	2
Actuarial (gain) loss and other	5	4
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Settlement	(2)	(4)
Defined Benefit Plan, Benefit Obligation, Business Combination	0	50
Benefits paid, net	(2)	(1)
Defined Benefit Plan, Plan Assets, Payment for Settlement	(2)	(4)
Defined Benefit Plan, Plan Assets, Business Combination	0	40
Return on plan assets and other	5	6
Employer contributions	1	1
Benefit obligation	55	52	1
Defined Benefit Plan, Service Cost	0
Fair value of plan assets	45	43	1
Amount underfunded	10
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Current liabilities	0	0
Non-current liabilities	(10)	(9)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	(10)	(9)
Net actuarial gain (loss)	0	0
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	0	0
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	31	34
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(5)	(7)
Interest cost	1	1
Actuarial (gain) loss and other	1	0
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Settlement	0	0
Defined Benefit Plan, Benefit Obligation, Business Combination	0	3
Benefits paid, net	0	0
Defined Benefit Plan, Plan Assets, Payment for Settlement	0	0
Defined Benefit Plan, Plan Assets, Business Combination	0	0
Return on plan assets and other	0	0
Employer contributions	0	0
Benefit obligation	31	34	37
Defined Benefit Plan, Service Cost	0	0
Fair value of plan assets		0	$ 0
Amount underfunded	31	34
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Current liabilities	(4)	(5)
Non-current liabilities	(27)	(29)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	(31)	(34)
Net actuarial gain (loss)	2	1
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	2	1
Unfunded Plans [Member] | Change in Plan Assets [Member] | Pension Plans, Defined Benefit [Member]
Change in benefit obligation and Plan Assets:
Fair value of plan assets	$ 0	$ 0

Retirement Benefits Summary for

Retirement Benefits Summary for Plans with an Accumulated Benefit Obligation in Excess of Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Accumulated Benefit Obligation	$ 208	$ 208
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets	291	270
Funded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	55	51
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Accumulated Benefit Obligation	55	52
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets	45	43
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	31	34
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Accumulated Benefit Obligation	31	34
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets	$ 0	$ 0

Retirement Benefits Components

Retirement Benefits Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	$ 0	$ 0
Interest cost	3	3
Expected return on plan assets	(2)	(2)
Prior service cost amortization	0	0
Net periodic benefit cost	1	1
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	1	1
Interest cost	5	7
Expected return on plan assets	(11)	(10)
Prior service cost amortization	19	26
Net periodic benefit cost	$ 14	$ 24

Retirement Benefits Weighted-Av

Retirement Benefits Weighted-Average Assumptions Used in Determining Benefit Obligations (Details)	Dec. 31, 2020	Dec. 31, 2019
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.40%	4.00%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.04%	2.71%

Retirement Benefits Assumed Hea

Retirement Benefits Assumed Health Care Cost Trend Rates (Details)	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year	7.30%	7.25%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	4.82%	4.83%

Retirement Benefits Schedule Of

Retirement Benefits Schedule Of Weighted-Average Assumptions To Determine Defined Benefit Plans And Postretirement Benefit Plans Expense (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.05%	3.33%
Expected long term return on assets, tax exempt accounts	4.57%	3.37%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	2.94%	3.76%
Expected long term return on assets, tax exempt accounts	7.00%	7.00%
Expected long term return on assets, taxable accounts	4.75%	4.75%

Retirement Benefits Fair Value

Retirement Benefits Fair Value of Plan Assets (Details) - USD ($) $ in Millions		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		$ 291	$ 270	$ 241
Large Cap US Equitiies		59.00%	59.00%
Fixed Income Securities		40.00%	40.00%
Cash Fund Investments		1.00%	1.00%
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		$ 45	$ 43
Large Cap US Equitiies		100.00%	100.00%
Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		$ 18	$ 14
Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		1
Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets	[1]	202	177
Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets	[2]	20	19
Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		71	79
Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		24	23
Cash and Cash Equivalents [Domain] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			1
Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		220	191
Fair Value, Inputs, Level 1 [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		21	20
Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		18	14
Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		1
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		202	177
Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		20	19
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Domain] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			1
Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		71	79
Fair Value, Inputs, Level 2 [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		24	23
Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 2 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		71	79
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		24	23
Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Domain] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			0
Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 3 [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 3 [Member] | Mutual Fund [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets		$ 0	0
Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Domain] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets			$ 0
[1]	Primarily comprised of approximately 59% equities, 40% fixed income securities and 1% cash as of December 31, 2020.
[2]	Comprised of approximately 100% equities as of December 31, 2020.

Retirement Benefits Expected Fu

Retirement Benefits Expected Future Benefit Payments (Details) $ in Millions	Dec. 31, 2020USD ($)
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2021	$ 18
2022	18
2023	16
2024	15
2025	14
Thereafter	58
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2021	8
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2021	6
Unfunded Plans [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2021	5
2022	4
2023	4
2024	3
2025	3
Thereafter	9
Defined Benefit Plan, Funded Plan [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2021	3
2022	4
2023	4
2024	4
2025	2
Thereafter	$ 12

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
ET
Related Party Transaction [Line Items]
Notes Receivable, Related Parties	$ (1,900)	$ (3,700)
ETO [Member]
Related Party Transaction [Line Items]
Notes Receivable, Related Parties		(104)
SemGroup Intercompany Promissory Note [Member]
Related Party Transaction [Line Items]
Interest Income, Related Party	$ 147	$ 184

Related Party Transactions Rela

Related Party Transactions Related Party - Affiliated Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Revenues from related companies	$ 466	$ 492	$ 431

Related Party Transactions Re_2

Related Party Transactions Related Party - Affiliate AR and Affiliate AP (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	$ 79	$ 167
Accounts Payable, Related Parties, Current	177	31
ET
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	0	8
Accounts Payable, Related Parties, Current	150	0
FGT
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	12	50
Other
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	37	31
Accounts Payable, Related Parties, Current	27	31
Phillips 66 Company [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	30	36
Traverse Rover LLC [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	$ 0	$ 42

Reportable Segments (Segment Ad

Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020		Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Adjusted EBITDA										$ 10,541	$ 11,148	$ 9,601
Depreciation, depletion and amortization										(3,669)	(3,136)	(2,843)
Interest expense, net of interest capitalized										(2,323)	(2,262)	(1,709)
Impairment losses										2,880	74	431
Impairment losses		$ (12)				$ (9)				(2,815)	(21)
Gains (losses) on interest rate derivatives										(203)	(241)	47
Non-cash compensation expense										(121)	(113)	(105)
Unrealized losses on commodity risk management activities										(71)	(5)	(11)
Inventory valuation adjustments										(82)	79	(85)
Losses on extinguishments of debt										(72)	(2)	(109)
Adjusted EBITDA related to unconsolidated affiliates										(628)	(626)	(655)
Equity in earnings of unconsolidated affiliates										119	302	344
Impairment of investments in unconsolidated affiliates										129	0	0
Adjusted EBITDA attributable to discontinued operations										0	0	25
Other, net										68	244	30
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE										550	5,314	4,099
Income tax expense (benefit) from continuing operations										(239)	(199)	(5)
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent						1,364	$ 1,250	$ 1,282	$ 1,219	311	5,115	4,094
Loss from discontinued operations, net of income taxes										0	0	(265)
Net income	$ 868	(362)	[1]	$ 719	$ (914)	1,364	1,250	1,282	1,219	311	5,115	3,829
Revenues	(10,034)	(9,955)	[1]	$ (7,338)	(11,627)	(13,720)	$ (13,495)	$ (13,877)	$ (13,121)	(38,954)	(54,213)	(54,087)
Intersegment Eliminations [Member]
Revenues										(5,884)	(5,951)	(7,039)
Intrastate Transportation And Storage [Member]
Segment Adjusted EBITDA										863	999	927
Depreciation, depletion and amortization										(185)	(184)	(169)
Impairment losses	(10)									(10)	0
Equity in earnings of unconsolidated affiliates										18	18	19
Revenues										(2,544)	(3,099)	(3,737)
Interstate Transportation and Storage [Member]
Segment Adjusted EBITDA										1,680	1,792	1,680
Depreciation, depletion and amortization										(411)	(387)	(334)
Impairment losses										58
Impairment losses		(43)			(183)					(226)	(12)
Equity in earnings of unconsolidated affiliates										17	222	227
Revenues										(1,861)	(1,963)	(1,682)
Midstream [Member]
Segment Adjusted EBITDA										1,670	1,602	1,627
Depreciation, depletion and amortization										(1,140)	(1,066)	(1,006)
Impairment losses					(483)	$ (378)				(483)	(9)
Equity in earnings of unconsolidated affiliates										24	20	26
Revenues										(5,026)	(6,031)	(7,522)
NGL and refined products transportation and services [Member]
Segment Adjusted EBITDA										2,802	2,666	1,979
Depreciation, depletion and amortization										(667)	(613)	(466)
Impairment losses										0	0
Equity in earnings of unconsolidated affiliates										60	53	64
Revenues										(10,513)	(11,641)	(11,123)
Crude oil transportation and services [Member]
Segment Adjusted EBITDA										2,258	2,898	2,385
Depreciation, depletion and amortization										(640)	(437)	(445)
Impairment losses		(1,280)								(1,279)	0
Equity in earnings of unconsolidated affiliates										(2)	(1)	6
Revenues										(11,679)	(18,447)	(17,332)
Investment In Sunoco LP [Member]
Segment Adjusted EBITDA										739	665	638
Depreciation, depletion and amortization										(189)	(181)	(167)
Impairment losses										0	0
Revenues										(10,710)	(16,596)	(16,994)
Investment In USAC [Member]
Segment Adjusted EBITDA										414	420	289
Depreciation, depletion and amortization										(239)	(231)	(169)
Impairment losses					(619)					(619)	0
Revenues										(667)	(698)	(508)
Other Segments [Member]
Segment Adjusted EBITDA										115	106	76
Depreciation, depletion and amortization										(198)	(37)	(87)
Impairment losses	$ (15)	$ (132)			$ (40)					(198)	0
Equity in earnings of unconsolidated affiliates										2	(10)	2
Revenues										$ (1,838)	$ (1,689)	$ (2,228)
[1]	For the three months ended September 30, 2020, the net loss attributable to partners presented above reflects a change from the amount previously reported in the Partnership’s interim financial statements, due to an adjustment to the allocation of income between the general and limited partners and the noncontrolling interest in a less than wholly-owned subsidiary of the Partnership.

Reportable Segments (Financial

Reportable Segments (Financial Information by Segment) (Details) - USD ($) $ in Millions		3 Months Ended									12 Months Ended
		Dec. 31, 2020	Sep. 30, 2020	[2]	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Advances to and investments in unconsolidated affiliates		$ 3,055					$ 3,454				$ 3,055	$ 3,454	$ 2,636
Property, Plant and Equipment, Additions	[1]										3,759	5,268	5,630
Total assets		96,742					102,294				96,742	102,294	88,609
Equity in earnings of unconsolidated affiliates											119	302	344
Depreciation, depletion and amortization											3,669	3,136	2,843
Cost of products sold											25,487	39,801	41,603
Revenues		10,034	$ 9,955		$ 7,338	$ 11,627	13,720	$ 13,495	$ 13,877	$ 13,121	38,954	54,213	54,087
Intersegment Eliminations [Member]
Cost of products sold											5,829	5,885	6,998
Revenues											5,884	5,951	7,039
Intrastate Transportation And Storage [Member]
Advances to and investments in unconsolidated affiliates		89					88				89	88	83
Property, Plant and Equipment, Additions	[1]										49	124	344
Total assets		7,549					6,648				7,549	6,648	6,365
Equity in earnings of unconsolidated affiliates											18	18	19
Depreciation, depletion and amortization											185	184	169
Cost of products sold											1,478	1,909	2,665
Revenues											2,544	3,099	3,737
Interstate Transportation and Storage [Member]
Advances to and investments in unconsolidated affiliates		2,278					2,524				2,278	2,524	2,070
Property, Plant and Equipment, Additions	[1]										150	375	812
Total assets		17,730					18,111				17,730	18,111	15,081
Equity in earnings of unconsolidated affiliates											17	222	227
Depreciation, depletion and amortization											411	387	334
Revenues											1,861	1,963	1,682
Midstream [Member]
Advances to and investments in unconsolidated affiliates		110					112				110	112	124
Property, Plant and Equipment, Additions	[1]										487	827	1,161
Total assets		18,816					20,332				18,816	20,332	19,745
Equity in earnings of unconsolidated affiliates											24	20	26
Depreciation, depletion and amortization											1,140	1,066	1,006
Cost of products sold											2,598	3,577	5,145
Revenues											5,026	6,031	7,522
NGL and refined products transportation and services [Member]
Advances to and investments in unconsolidated affiliates		509					461				509	461	243
Property, Plant and Equipment, Additions	[1]										2,403	2,976	2,381
Total assets		21,578					19,145				21,578	19,145	18,267
Equity in earnings of unconsolidated affiliates											60	53	64
Depreciation, depletion and amortization											667	613	466
Cost of products sold											7,139	8,393	8,462
Revenues											10,513	11,641	11,123
Crude oil transportation and services [Member]
Advances to and investments in unconsolidated affiliates		22					242				22	242	28
Property, Plant and Equipment, Additions	[1]										291	403	474
Total assets		18,335					22,933				18,335	22,933	18,189
Equity in earnings of unconsolidated affiliates											(2)	(1)	6
Depreciation, depletion and amortization											640	437	445
Cost of products sold											8,838	14,832	14,384
Revenues											11,679	18,447	17,332
Other Segments [Member]
Advances to and investments in unconsolidated affiliates		47					27				47	27	88
Property, Plant and Equipment, Additions	[1]										136	215	150
Total assets		4,518					5,957				4,518	5,957	2,308
Equity in earnings of unconsolidated affiliates											2	(10)	2
Depreciation, depletion and amortization											198	37	87
Cost of products sold											1,527	1,504	2,006
Revenues											1,838	1,689	2,228
Investment In Sunoco LP [Member]
Property, Plant and Equipment, Additions	[1]										124	148	103
Total assets		5,267					5,438				5,267	5,438	4,879
Depreciation, depletion and amortization											189	181	167
Cost of products sold											9,654	15,380	15,872
Revenues											10,710	16,596	16,994
Investment In USAC [Member]
Property, Plant and Equipment, Additions	[1]										119	200	205
Total assets		$ 2,949					$ 3,730				2,949	3,730	3,775
Depreciation, depletion and amortization											239	231	169
Cost of products sold											82	91	67
Revenues											667	698	508
External Customers [Member] | Intrastate Transportation And Storage [Member]
Revenues											2,312	2,749	3,428
External Customers [Member] | Interstate Transportation and Storage [Member]
Revenues											1,841	1,941	1,664
External Customers [Member] | Midstream [Member]
Revenues											1,944	2,280	2,090
External Customers [Member] | NGL and refined products transportation and services [Member]
Revenues											8,501	9,920	10,119
External Customers [Member] | Crude oil transportation and services [Member]
Revenues											11,674	18,447	17,236
External Customers [Member] | Other Segments [Member]
Revenues											1,374	1,608	2,073
External Customers [Member] | Investment In Sunoco LP [Member]
Revenues											10,653	16,590	16,982
External Customers [Member] | Investment In USAC [Member]
Revenues											655	678	495
Intersegment [Member] | Intrastate Transportation And Storage [Member]
Revenues											232	350	309
Intersegment [Member] | Interstate Transportation and Storage [Member]
Revenues											20	22	18
Intersegment [Member] | Midstream [Member]
Revenues											3,082	3,751	5,432
Intersegment [Member] | NGL and refined products transportation and services [Member]
Revenues											2,012	1,721	1,004
Intersegment [Member] | Crude oil transportation and services [Member]
Revenues											5	0	96
Intersegment [Member] | Other Segments [Member]
Revenues											464	81	155
Intersegment [Member] | Investment In Sunoco LP [Member]
Revenues											57	6	12
Intersegment [Member] | Investment In USAC [Member]
Revenues											$ 12	$ 20	$ 13
[1]	Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis).
[2]	For the three months ended September 30, 2020, the net loss attributable to partners presented above reflects a change from the amount previously reported in the Partnership’s interim financial statements, due to an adjustment to the allocation of income between the general and limited partners and the noncontrolling interest in a less than wholly-owned subsidiary of the Partnership.

Quarterly Financial Data Quarte

Quarterly Financial Data Quarterly Financial Data Table (Details) - USD ($) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	[1]	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Quarterly Financial Data [Abstract]
Revenues	$ 10,034	$ 9,955		$ 7,338	$ 11,627	$ 13,720	$ 13,495	$ 13,877	$ 13,121	$ 38,954	$ 54,213	$ 54,087
Operating income	1,344	248		1,342	65	1,668	1,860	1,828	1,866	2,999	7,222	5,457
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent						1,364	1,250	1,282	1,219	311	5,115	4,094
Net income (loss)	868	(362)		719	(914)	1,364	1,250	1,282	1,219	311	5,115	$ 3,829
Net income (loss) attributable to partners	$ 627	$ (530)		$ 481	$ (720)	$ 1,080	$ 977	$ 1,003	$ 950	$ (142)	$ 4,010
[1]	For the three months ended September 30, 2020, the net loss attributable to partners presented above reflects a change from the amount previously reported in the Partnership’s interim financial statements, due to an adjustment to the allocation of income between the general and limited partners and the noncontrolling interest in a less than wholly-owned subsidiary of the Partnership.