Energy Transfer (ET) 10-K 21 Feb 20 2019 FY Annual report Financial data

Cover Page Cover Page

Cover Page Cover Page - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Feb. 13, 2020	Jun. 30, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-32740
Entity Registrant Name	ENERGY TRANSFER LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	30-0108820
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
Title of 12(b) Security	Common Units
Trading Symbol	ET
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 30,570
Entity Common Stock, Shares Outstanding		2,689,897,793
Documents Incorporated by Reference	None
Entity Central Index Key	0001276187
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
ASSETS
Cash and cash equivalents	$ 291	$ 419
Accounts receivable, net	5,038	4,009
Accounts receivable from related companies	159	111
Inventories	1,935	1,677
Income taxes receivable	146	73
Derivative assets	23	111
Other current assets	275	350
Total current assets	7,867	6,750
Property, plant and equipment	89,790	79,776
Accumulated depreciation and depletion	(15,597)	(12,813)
Property, Plant and Equipment, Net	74,193	66,963
Advances to and investments in unconsolidated affiliates	3,460	2,642
Lease, Right of Use Asset, Net	964
Operating Lease, Right-of-Use Asset	1,000	0
Other non-current assets, net	1,075	1,006
Intangible assets, net	6,154	6,000
Goodwill	5,167	4,885
Total assets	98,880	88,246
LIABILITIES AND EQUITY
Accounts payable	4,118	3,493
Accounts payable to related companies	31	59
Derivative liabilities	147	185
Operating Lease, Liability, Current	60	0
Accrued and other current liabilities	3,342	2,918
Current maturities of long-term debt	26	2,655
Total current liabilities	7,724	9,310
Long-term debt, less current maturities	51,028	43,373
Non-current derivative liabilities	273	104
Operating Lease, Liability, Noncurrent	901	0
Deferred income taxes	3,208	2,926
Other non-current liabilities	1,162	1,184
Commitments and contingencies
Redeemable noncontrolling interests	739	499
Partners' Capital
General Partner	(4)	(5)
Limited Partners:
Common Unitholders (2,689,580,631 and 2,619,368,605 units authorized, issued and outstanding as of December 31, 2019 and 2018, respectively)	21,842	20,606
Accumulated other comprehensive loss	(11)	(42)
Total partners’ capital	21,827	20,559
Noncontrolling interests	12,018	10,291
Total equity	33,845	30,850
Total liabilities and equity	$ 98,880	$ 88,246

Consolidated Balance Sheets Bal

Consolidated Balance Sheets Balance Sheet (Paranthetical)	Dec. 31, 2018shares
Class of Stock [Line Items]
Authorized	2,619,368,605
Issued	2,619,368,605
Outstanding	2,619,368,605

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
REVENUES:
Total revenues	$ 54,213	$ 54,087	$ 40,523
COSTS AND EXPENSES:
Cost of Goods and Services Sold	39,727	41,658	30,966
Operating expenses	3,294	3,089	2,644
Depreciation, depletion and amortization	3,147	2,859	2,554
Selling, general and administrative	694	702	599
Impairment losses	74	431	1,039
Total costs and expenses	46,936	48,739	37,802
OPERATING INCOME	7,277	5,348	2,721
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(2,331)	(2,055)	(1,922)
Equity in earnings of unconsolidated affiliates	302	344	144
Impairment of investments in unconsolidated affiliates	0	0	(313)
Losses on extinguishments of debt	(18)	(112)	(89)
Gains (losses) on interest rate derivatives	(241)	47	(37)
Other, net	105	62	206
Income from continuing operations before income tax (expense) benefit	5,094	3,634	710
Income tax expense (benefit) from continuing operations	195	4	(1,833)
INCOME FROM CONTINUING OPERATIONS	4,899	3,630	2,543
Loss from discontinued operations	0	(265)	(177)
NET INCOME	4,899	3,365	2,366
Less: Net income attributable to noncontrolling interests	1,256	1,632	1,412
Less: Net income attributable to redeemable noncontrolling interests	51	39	0
NET INCOME ATTRIBUTABLE TO PARTNERS	3,592	1,694	954
General Partner’s interest in net income	4	3	2
Convertible Unitholders’ interest in net income	0	33	37
Limited Partners’ interest in net income	$ 3,588	$ 1,658	$ 915
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT (USD $ per unit):
Basic	$ 1.37	$ 1.17	$ 0.86
Diluted	1.36	1.16	0.84
NET INCOME PER LIMITED PARTNER UNIT (USD $ per Unit):
Basic	1.37	1.16	0.85
Diluted	$ 1.36	$ 1.15	$ 0.83
Refined product sales
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	$ 16,752	$ 17,458	$ 11,166
Crude sales
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	15,917	14,425	10,706
Natural gas sales
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	3,295	4,452	4,172
Gathering, transportation and other fees
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	9,086	6,797	4,435
NGL sales
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	8,290	9,986	7,781
Other
REVENUES:
Revenue from Contract with Customer, Including Assessed Tax	$ 873	$ 969	$ 2,263

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net income	$ 4,899	$ 3,365	$ 2,366
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	11	(4)	6
Actuarial gain (loss) relating to pension and other postretirement benefits	24	(43)	(12)
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax, Portion Attributable to Parent	6	0	0
Change in other comprehensive income from unconsolidated affiliates	(10)	4	1
Other comprehensive income (loss), net of tax, total	31	(43)	(5)
Comprehensive income	4,930	3,322	2,361
Less: Comprehensive income attributable to noncontrolling interests	1,256	1,632	1,407
Less: Comprehensive income attributable to redeemable noncontrolling interests	51	39	0
Comprehensive income attributable to partners	$ 3,623	$ 1,651	$ 954

Consolidated Statement Of Equit

Consolidated Statement Of Equity - USD ($) $ in Millions	Total	General Partner [Member]	AOCI Attributable to Parent [Member]	Limited Partner [Member]	Series A Convertible Preferred Units [Member]	Noncontrolling Interest [Member]	PennTex Acquisition [Member]General Partner [Member]	PennTex Acquisition [Member]AOCI Attributable to Parent [Member]	PennTex Acquisition [Member]Limited Partner [Member]	PennTex Acquisition [Member]Series A Convertible Preferred Units [Member]	PennTex Acquisition [Member]Noncontrolling Interest [Member]	Sale of Bakken Pipeline interest [Member]	Sale of Bakken Pipeline interest [Member]General Partner [Member]	Sale of Bakken Pipeline interest [Member]AOCI Attributable to Parent [Member]	Sale of Bakken Pipeline interest [Member]Limited Partner [Member]	Sale of Bakken Pipeline interest [Member]Series A Convertible Preferred Units [Member]	Sale of Bakken Pipeline interest [Member]Noncontrolling Interest [Member]	Sale of Rover Pipeline interest [Member]	Sale of Rover Pipeline interest [Member]General Partner [Member]	Sale of Rover Pipeline interest [Member]AOCI Attributable to Parent [Member]	Sale of Rover Pipeline interest [Member]Limited Partner [Member]	Sale of Rover Pipeline interest [Member]Series A Convertible Preferred Units [Member]	Sale of Rover Pipeline interest [Member]Noncontrolling Interest [Member]
Balance at Dec. 31, 2016	$ 22,431	$ (3)	$ 0	$ (1,871)	$ 180	$ 24,125
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(1,010)	(2)	0	(1,008)	0	0
Distributions to noncontrolling interest	(2,999)	0	0	0	0	(2,999)
Distributions reinvested	0	0	0	234	(234)	0
Units repurchased under buyback program	0
Partners' Capital Account, Sale of Units	568	0	0	568	0	0
Subsidiary unit transactions	3,235	0	0	(55)	(1)	3,291
Capital contributions received from noncontrolling interest	2,202	0	0	0	0	2,202
Other, net	(6)	0	0	0	0	(6)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	(280)						$ 0	$ 0	$ (2)	$ 0	$ (278)
Acquisition and disposition of noncontrolling interest												$ (2,000)	$ 0	$ 0	$ (42)	$ 0	$ (1,958)	$ (1,478)	$ 0	$ 0	$ (2)	$ 0	$ (1,476)
Other comprehensive income, net of tax	(5)	0	0	0	0	(5)
Net income	2,366	2	0	915	37	1,412
Balance at Dec. 31, 2017	29,980	(3)	0	(1,643)	450	31,176
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(1,684)	(3)	0	(1,681)	0	0
Distributions to noncontrolling interest	(3,117)	0	0	0	0	(3,117)
Distributions reinvested	0	0	0	115	(115)
Units repurchased under buyback program	0
Subsidiary unit transactions	924	0	0	1	0	923
Capital contributions received from noncontrolling interest	649	0	0	0	0	649
Non-cash compensation expense, net of units tendered by employees for tax withholdings	0	0	0	21,869	0	(21,869)
Other, net	61	(2)	1	47	(2)	17
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	(24)	0	0	(119)	(7)	102
Other comprehensive income, net of tax	(43)	0	(43)	0	0	0
Net income	3,365
Noncontrolling Interest, Increase from Business Combination	832	0	0	0	0	832
Stock Issued During Period, Value, Conversion of Units	0	0	0	589	(589)	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	3,326	3	0	1,658	33	1,632
Balance at Dec. 31, 2018	30,850	(5)	(42)	20,606	0	10,291
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative Effect of New Accounting Principle in Period of Adoption	(54)	0	0	0	0	(54)
Distributions to partners	(3,054)	(3)	0	(3,051)	0	0
Distributions to noncontrolling interest	(1,597)	0	0	0	0	(1,597)
Units repurchased under buyback program	(25)	0	0	(25)	0	0
Subsidiary unit transactions	780	0	0	0	0	780
Capital contributions received from noncontrolling interest	348	0	0	0	0	348
Non-cash compensation expense, net of units tendered by employees for tax withholdings	1,471	0	0	652	0	819
Other, net	100	0	0	72	0	28
Acquisition and disposition of noncontrolling interest	(93)	0	0	0	0	(93)
Other comprehensive income, net of tax	31	0	31	0	0	0
Net income	4,899
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	4,848	4	0	3,588	0	1,256
Balance at Dec. 31, 2019	$ 33,845	$ (4)	$ (11)	$ 21,842	$ 0	$ 12,018

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 4,899	$ 3,365	$ 2,366
Reconciliation of net income to net cash provided by operating activities:
Loss from discontinued operations	0	265	177
Depreciation, depletion and amortization	3,147	2,859	2,554
Deferred income taxes	(217)	7	1,871
Inventory valuation adjustments	(79)	85	(24)
Non-cash compensation expense	113	105	99
Impairment losses	74	431	1,039
Impairment of investments in unconsolidated affiliates	0	0	313
Losses on extinguishments of debt	18	112	89
Distributions On Unvested Unit Awards	38	38	35
Proceeds from Equity Method Investment, Distribution	290	328	297
Other non-cash	(182)	(56)	239
Equity in earnings of unconsolidated affiliates	(302)	(344)	(144)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	(518)	289	(192)
Net Cash Provided by (Used in) Operating Activities, Continuing Operations	8,003	7,506	4,429
INVESTING ACTIVITIES:
Cash received for sale of noncontrolling interest	93	0	0
Cash Acquired from Acquisition	0	461	0
Cash paid for acquisitions, net of cash received	(7)	(429)	(303)
Capital expenditures, excluding allowance for equity funds used during construction	(5,960)	(7,407)	(8,444)
Contributions in aid of construction costs	80	109	31
Contributions to unconsolidated affiliates	(523)	(26)	(268)
Distributions from unconsolidated affiliates in excess of cumulative earnings	98	69	135
Proceeds from the sale of other assets	54	87	48
Other	18	61	(3)
Net Cash Provided by (Used in) Investing Activities, Continuing Operations	(6,934)	(7,075)	(5,606)
FINANCING ACTIVITIES:
Proceeds from borrowings	22,583	29,001	31,608
Repayments of long-term debt	(20,101)	(28,948)	(31,268)
Cash received from affiliate notes	0	0	(255)
Proceeds from Issuance of Common Limited Partners Units	0	0	568
Subsidiary units issued for cash	780	1,402	3,235
Distributions to partners	(3,054)	(1,684)	(1,010)
Distributions to noncontrolling interests	(1,597)	(3,117)	(2,961)
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	0	24	0
Redemption of preferred units	0	0	(53)
Debt issuance costs	(117)	(171)	(131)
Capital contributions from noncontrolling interests	348	649	1,214
Units repurchased under buyback program	(25)	0	0
Payments for Repurchase of Common Units by Subsidiary	0	24	0
Other, net	(14)	(166)	6
Net cash provided by (used in) financing activities	(1,197)	(3,082)	953
Cash Provided by (Used in) Operating Activities, Discontinued Operations	0	(484)	136
Cash Provided by (Used in) Investing Activities, Discontinued Operations	0	3,207	(38)
Increase (Decrease) in Assets Held-for-sale	0	11	(5)
Net increase in cash and cash equivalents of discontinued operations	0	2,734	93
Increase (decrease) in cash and cash equivalents	(128)	83	(131)
Cash and cash equivalents, beginning of period	419	336	467
Cash and cash equivalents, end of period	291	419	336
Bakken Pipeline [Member]
INVESTING ACTIVITIES:
Proceeds from Divestiture of Interest in Joint Venture	0	0	2,000
Rover Pipeline LLC [Member]
INVESTING ACTIVITIES:
Proceeds from Divestiture of Interest in Joint Venture	0	0	1,478
SemGroup [Member]
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	787	0	0
PennTex [Member]
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	$ 0	$ 0	$ 280

Operations And Organization

Operations And Organization	12 Months Ended
	Dec. 31, 2019
Operations And Organization [Abstract]
Operations And Organization	OPERATIONS AND BASIS OF PRESENTATION : The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ET”). References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis. In October 2018, we completed the merger of ETO with a wholly-owned subsidiary of ET in a unit-for-unit exchange (the “Energy Transfer Merger”). In connection with the transaction, 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. Following the closing of the Energy Transfer Merger, Energy Transfer Partners, L.P. was renamed Energy Transfer Operating, L.P. In addition, Energy Transfer Equity, L.P. was renamed Energy Transfer LP, and its common units began trading on the NYSE under the “ET” ticker symbol on Friday, October 19, 2018. Immediately prior to the closing of the Energy Transfer Merger, the following also occurred: • the IDRs in Energy Transfer Partners, L.P. were converted into 1,168,205,710 common units; • the general partner interest in ETO was converted to a non-economic general partner interest and ETO issued 18,448,341 ETO common units to ETP GP; • ET contributed its 2,263,158 Sunoco LP common units to ETO in exchange for 2,874,275 ETO common units and 100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETO in exchange for 42,812,389 ETO common units; • ET contributed its 12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETO in exchange for 16,134,903 ETO common units; and • ET contributed its 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC (collectively, “Lake Charles LNG and Other”) to ETO in exchange for 37,557,815 ETO common units. Subsequent to the Energy Transfer Merger, substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in Sunoco LP and USAC. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ET’s subsidiaries. Our financial statements reflect the following reportable segments: • intrastate transportation and storage ; • interstate transportation and storage ; • midstream ; • NGL and refined products transportation and services ; • crude oil transportation and services ; • investment in Sunoco LP ; • investment in USAC ; and • corporate and other, including the following: • activities of the Parent Company; and • certain operations and investments that are not separately reflected as reportable segments. 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 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 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, 2019 , 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, 2019 , our interest in USAC consisted of 100% o f the general partner and 46.1 million common units. Basis of Presentation. The consolidated financial statements of Energy Transfer LP presented herein for the years ended December 31, 2019, 2018 and 2017 , have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. The consolidated financial statements of ET presented herein include the results of operations of: • the Parent Company; • our controlled subsidiary, Energy Transfer Operating, L.P.; and • Energy Transfer Partners GP, L.P. (“ETP GP”), the general partner of ETO, and Energy Transfer Partners, L.L.C. (“ETP LLC”), the general partner of ETP GP.

Estimates, Significant Accounti

Estimates, Significant Accounting Policies and Balance Sheet Detail	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Estimates, Significant Accounting Policies and Balance Sheet Detail	ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL : 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. Lease Accounting In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842) , which has amended the FASB Accounting Standards Codification (“ASC”) and introduced Topic 842, Leases. On January 1, 2019, the Partnership has adopted ASC Topic 842 (“Topic 842”), which is effective for interim and annual reporting periods beginning on or after December 15, 2018. Topic 842 requires entities to recognize lease assets and liabilities on the balance sheet for all leases with a term of more than one year, including operating leases, which historically were not recorded on the balance sheet in accordance with the prior standard. To adopt Topic 842, the Partnership recognized a cumulative catch-up adjustment to the opening balance sheet as of January 1, 2019 related to certain leases that existed as of that date. As permitted, we have not retrospectively modified our consolidated financial statements for comparative purposes. The adoption of the standard had a material impact on our consolidated balance sheet, but did not have an impact on our consolidated statements of operations, comprehensive income or cash flows. As a result of adoption, we have recorded additional net right-of-use (“ROU”) lease assets and lease liabilities of approximately $888 million and $888 million, respectively, as of January 1, 2019. In addition, we have updated our business processes, systems, and internal controls to support the on-going reporting requirements under the new standard. To adopt Topic 842, the Partnership elected the package of practical expedients permitted under the transition guidance within the standard. The expedient package allowed us not to reassess whether existing contracts contained a lease, the lease classification of existing leases and initial direct cost for existing leases. In addition to the package of practical expedients, the Partnership has elected not to capitalize amounts pertaining to leases with terms less than twelve months, to use the portfolio approach to determine discount rates, not to separate non-lease components from lease components and not to apply the use of hindsight to the active lease population. Cumulative-effect adjustments made to the opening balance sheet at January 1, 2019 were as follows: Balance at December 31, 2018, as previously reported Adjustments due to Topic 842 (Leases) Balance at January 1, 2019 Assets: Property, plant and equipment, net $ 66,963 $ (1 ) $ 66,962 Lease right-of-use assets, net — 889 889 Liabilities: Operating lease current liabilities $ — $ 71 $ 71 Accrued and other current liabilities 2,918 (1 ) 2,917 Current maturities of long-term debt 2,655 1 2,656 Long-term debt, less current maturities 43,373 6 43,379 Non-current operating lease liabilities — 823 823 Other non-current liabilities 1,184 (12 ) 1,172 Additional disclosures related to lease accounting are included in Note 13 . 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, 2019 2018 2017 Accounts receivable $ (473 ) $ 541 $ (948 ) Accounts receivable from related companies (69 ) 162 24 Inventories (117 ) 282 58 Other current assets 117 7 38 Other non-current assets, net (78 ) (92 ) 84 Accounts payable 146 (766 ) 712 Accounts payable to related companies (32 ) (202 ) (178 ) Accrued and other current liabilities (44 ) 382 (97 ) Other non-current liabilities (186 ) 28 106 Derivative assets and liabilities, net 218 (53 ) 9 Net change in operating assets and liabilities, net of effects of acquisitions $ (518 ) $ 289 $ (192 ) Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2019 2018 2017 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 1,334 $ 1,030 $ 1,060 Lease assets obtained in exchange for new lease liabilities 68 — — Net losses from subsidiary common unit transactions — (126 ) (56 ) NON-CASH FINANCING ACTIVITIES: Contribution of assets from noncontrolling interests $ — $ — $ 988 SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 1,932 $ 1,870 $ 1,914 Cash paid for income taxes 31 508 50 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 doubtful accounts 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. Increases 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. Inventories consisted of the following: December 31, 2019 2018 Natural gas, NGLs and refined products (1) $ 833 $ 833 Crude oil 654 506 Spare parts and other 448 338 Total inventories $ 1,935 $ 1,677 (1) Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of $85 million as of December 31, 2018. 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, 2019 2018 Deposits paid to vendors $ 95 $ 141 Prepaid expenses and other 180 209 Total other current assets $ 275 $ 350 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 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. In 2017, the Partnership recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore 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, 2019 2018 Land and improvements $ 1,264 $ 1,168 Buildings and improvements (1 to 45 years) 2,632 2,664 Pipelines and equipment (5 to 83 years) 64,678 58,783 Product storage and related facilities (2 to 83 years) 5,898 4,978 Right of way (20 to 83 years) 4,859 4,533 Other (1 to 48 years) 1,964 1,583 Construction work-in-process 8,495 6,067 89,790 79,776 Less – Accumulated depreciation and depletion (15,597 ) (12,813 ) Property, plant and equipment, net $ 74,193 $ 66,963 We recognized the following amounts for the periods presented: Years Ended December 31, 2019 2018 2017 Depreciation, depletion and amortization expense $ 2,839 $ 2,538 $ 2,204 Capitalized interest 166 294 286 Advances to and 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. 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, 2019 2018 Regulatory assets $ 42 $ 43 Pension assets 84 68 Deferred charges 178 173 Restricted funds 178 178 Other 593 544 Total other non-current assets, net $ 1,075 $ 1,006 Restricted funds include 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, 2019 December 31, 2018 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 7,535 $ (1,743 ) $ 7,106 $ (1,493 ) Patents (10 years) 48 (35 ) 48 (30 ) Trade names (20 years) 66 (31 ) 66 (28 ) Other (5 to 20 years) 19 (12 ) 33 (9 ) Total amortizable intangible assets 7,668 (1,821 ) 7,253 (1,560 ) Non-amortizable intangible assets: Trademarks 295 — 295 — Other 12 — 12 — Total non-amortizable intangible assets 307 — 307 — Total intangible assets $ 7,975 $ (1,821 ) $ 7,560 $ (1,560 ) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2019 2018 2017 Reported in depreciation, depletion and amortization expense $ 308 $ 321 $ 344 Estimated aggregate amortization expense of intangible assets for the next five years was as follows: Years Ending December 31: 2020 $ 394 2021 390 2022 360 2023 320 2024 307 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 primarily due to decreases in projected future revenues and cash flows from the date the intangible assets were originally recorded. Sunoco LP performed impairment tests on its indefinite-lived intangible assets during the fourth quarter of 2017 and recognized a total of $17 million in impairment charges on their contractual rights and liquor licenses 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, 2017 $ 10 $ 196 $ 870 $ 693 $ 1,167 $ 1,430 $ — $ 402 $ 4,768 Acquired — — — — — 129 366 — 495 CDM Contribution — — — — — — 253 (253 ) — Impaired — — (378 ) — — — — — (378 ) Other — — — — — — — — — 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 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 fourth quarter of 2019, $265 million goodwill was recorded in conjunction with the acquisition of SemGroup. 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. During the fourth quarter of 2017, the Partnership recognized goodwill impairments of $262 million in the interstate transportation and storage segment, $79 million in the NGL and refined products transportation and services segment and $452 million in the all other segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. Sunoco LP recognized goodwill impairments of $387 million , of which $102 million was allocated to continuing operations , primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. In connection with aforementioned impairments, the Partnership determined the fair value of our reporting units using 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 determined 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 determined 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 estimated 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 $5.17 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2019 , approximately $380 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. Except for certain amounts discussed below, management was not able to reasonably measure the fair value of AROs as of December 31, 2019 and 2018 , in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s 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. ETC Sunoco has legal AROs for several other assets at its 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, ETC Sunoco is legally or contractually required to abandon in place or remove the asset. We believe we may have additional AROs related to ETC Sunoco’s 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 has AROs related to the estimated future cost to remove underground storage tanks. As of December 31, 2019 and 2018 , other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $247 million and $193 million , respectively. For the years ended December 31, 2019, 2018 and 2017 aggregate accretion expense related to AROs was $5 million , $13 million and $9 million , respectively. 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. Other non-current assets on the Partnership’s consolidated balance sheet included $31 million and $26 million of legally restricted funds for the purpose of settling AROs as of December 31, 2019 and 2018 , respectively. Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: December 31, 2019 2018 Interest payable $ 579 $ 571 Customer advances and deposits 123 128 Accrued capital expenditures 1,334 1,030 Accrued wages and benefits 217 283 Taxes payable other than income taxes 263 256 Exchanges payable 67 112 Other 759 538 Total accrued and other current liabilities $ 3,342 $ 2,918 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 sheet. See Note 7 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, 2019 was $54.79 billion and $51.05 billion , respectively. As of December 31, 2018 , the aggregate fair value and carrying amount of our debt obligations was $45.06 billion and $46.03 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, 2019 , no transfers were made between any levels within the fair value hierarchy. 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, 2019 and 2018 based on inputs used to derive their fair values: 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: 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 ) Fair Value Total Fair Value Measurements at December 31, 2018 Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 42 $ 42 $ — Swing Swaps IFERC 52 8 44 Fixed Swaps/Futures 97 97 — Forward Physical Contracts 20 — 20 Power: Power – Forwards 48 — 48 Futures 1 1 — Options – Calls 1 1 — NGLs – Forwards/Swaps 291 291 — Refined Products – Futures 7 7 — Crude - Forwards/Swaps 1 1 — Total commodity derivatives 560 448 112 Other non-current assets 26 17 9 Total assets $ 586 $ 465 $ 1

Acquisitions and Related Transa

Acquisitions and Related Transactions	12 Months Ended
	Dec. 31, 2019
Acquisitions and Dispositions [Abstract]
Acquisitions and Related Transactions	ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS : 2019 and 2020 Transactions SemGroup Acquisition and ET Contribution of SemGroup Assets to ETO On December 5, 2019, ET completed the acquisition of SemGroup pursuant to the terms of the Agreement and Plan of Merger, dated as of September 15, 2019 (the “Merger Agreement”). Under the terms of the Merger Agreement, a wholly owned subsidiary of ET merged with and into SemGroup (the “SemGroup Transaction”), with SemGroup surviving the Merger. At the effective time of the SemGroup Transaction on December 5, 2019, each share of class A common stock, par value $0.01 per share, of SemGroup issued and outstanding immediately prior to the effective time was converted into the right to receive (i) $6.80 in cash, without interest, and (ii) 0.7275 ET Common Units representing limited partner interests in ET. Each share of Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.01 per share, of SemGroup that was issued and outstanding as of immediately prior to the effective time was redeemed by SemGroup for cash at a price per share equal to 101% of the liquidation preference. During the first quarter of 2020, ET contributed certain SemGroup assets to ETO through sale and contribution transactions. Summary of Assets Acquired and Liabilities Assumed The SemGroup merger 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 purchase price allocation below is preliminary, as management is currently evaluating certain tax-related assumptions. The total purchase price was allocated as follows: At December 5, 2019 Total current assets $ 794 Property, plant and equipment 3,914 Other non-current assets 623 Goodwill (1) 265 Intangible assets 460 Total assets 6,056 Total current liabilities 629 Long-term debt, less current maturities (2) 2,576 Other non-current liabilities 196 SemCAMS Preferred shares 241 Total liabilities 3,642 Noncontrolling interest 822 Total consideration (3) 1,592 Cash received (4) 153 Total consideration, net of cash received $ 1,439 (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 SemGroup’s operations. (2) 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 were redeemed in total in December 2019, subsequent to the close of the SemGroup Transaction, utilizing proceeds from an intercompany promissory note from ETO. (3) Total consideration includes (i) cash paid to SemGroup shareholders, (ii) fair value of ET Common Units issued in the acquisition and (iii) cash paid to redeem SemGroup’s preferred shares. (4) Cash received represents cash and cash equivalents held by SemGroup 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. 2018 Transactions 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. Prior to the USAC acquisition, the CDM entities were indirect wholly-owned subsidiaries of ETO. Beginning April 2018, ETE’s consolidated financial statements reflected USAC as a consolidated subsidiary. 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 $ 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 Total consideration 250 Cash received (2) 711 Total consideration, net of cash received (2) $ (461 ) (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) Cash received represents cash and cash equivalents 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. Also, the related accounts receivable from such sales are no longer eliminated from the Partnership’s consolidated balance sheets and are reported as accounts receivable. In connection with the 7-Eleven Transaction, Sunoco LP entered into a Distributor Motor Fuel Agreement dated as of January 23, 2018 (“Supply Agreement”), with 7-Eleven and SEI Fuel (collectively, “Distributor”). The Supply Agreement consists of a 15-year take-or-pay fuel supply arrangement under which Sunoco LP has agreed to supply approximately 2.0 billion gallons of fuel annually plus additional aggregate growth volumes of up to 500 million gallons to be added incrementally over the first four years. For the period from January 1, 2018 through January 22, 2018 and the years ended December 31, 2017 , Sunoco LP recorded sales to the sites that were subsequently sold to 7-Eleven of $199 million and $3.2 billion , respectively, which were eliminated in consolidation. Sunoco LP received payments on trade receivables of $3.7 billion and $3.4 billion , respectively, from 7-Eleven for the years ended December 31, 2019 and December 31, 2018 subsequent to the closing of the sale. The Partnership has concluded that it meets the accounting requirements for reporting the financial position, results of operations and cash flows of Sunoco LP’s retail divestment as discontinued operations. There were no results of operations associated with discontinued operations for the year ended December 31, 2019 . The results of operations associated with discontinued operations for the years ended December 31, 2018 and 2017 are presented in the following table: Years Ended December 31, 2018 2017 REVENUES $ 349 $ 6,964 COSTS AND EXPENSES Cost of products sold 305 5,806 Operating expenses 61 763 Depreciation, depletion and amortization — 34 Selling, general and administrative 7 168 Impairment losses — 285 Total costs and expenses 373 7,056 OPERATING LOSS (24 ) (92 ) OTHER EXPENSE Interest expense, net 2 36 Loss on extinguishment of debt 20 — Other, net 61 1 LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (107 ) (129 ) Income tax expense 158 48 LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES $ (265 ) $ (177 ) LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES ATTRIBUTABLE TO ET $ (10 ) $ (6 ) 2017 Transactions Rover Contribution Agreement In October 2017, ETO completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETO exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETO and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETO for its pro rata share of the Rover construction costs incurred by ETO through the closing date, along with the payment of additional amounts subject to certain adjustments. ETO and Sunoco Logistics Merger As discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed the Sunoco Logistics Merger. Permian Express Partners In February 2017, the Partnership formed PEP, a strategic joint venture with ExxonMobil. The Partnership contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment. In July 2017, ETO contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETO’s ownership interest in PEP to approximately 88% . ETO maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity. Bakken Equity Sale In February 2017, Bakken Holdings Company LLC, an entity in which ETO indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETO continues to consolidate Dakota Access and ETCO subsequent to this transaction.

Advances to and Investments in

Advances to and Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2019
Investment In Affiliates [Abstract]
Investments In Affiliates	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES : Citrus ETO owns 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 ETO has a 50% interest in FEP which owns 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. ETO’s investment in FEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures . The Partnership recorded an impairment of its investment in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor. MEP ETO owns a 50% interest in MEP, which owns approximately 500 miles of 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. ETO’s investment in MEP is reflected in the interstate transportation and storage segment. The carrying values of the Partnership’s investments advances to and in unconsolidated affiliates as of December 31, 2019 and 2018 were as follows: December 31, 2019 2018 Citrus $ 1,876 $ 1,737 FEP 218 107 MEP 429 225 Others 937 573 Total $ 3,460 $ 2,642 The following table presents equity in earnings (losses) of unconsolidated affiliates: Years Ended December 31, 2019 2018 2017 Citrus $ 148 $ 141 $ 144 FEP 59 55 53 MEP 15 31 38 Other 80 117 (91 ) Total equity in earnings of unconsolidated affiliates $ 302 $ 344 $ 144 Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, and MEP (on a 100% basis) for all periods presented, except as noted below: December 31, 2019 2018 Current assets $ 247 $ 212 Property, plant and equipment, net 7,680 7,800 Other assets 40 39 Total assets $ 7,967 $ 8,051 Current liabilities $ 738 $ 1,534 Non-current liabilities 3,242 3,439 Equity 3,987 3,078 Total liabilities and equity $ 7,967 $ 8,051 Years Ended December 31, 2019 2018 (1) 2017 Revenue $ 1,192 $ 1,249 $ 1,358 Operating income 683 723 407 Net income 443 460 145 (1) Selected income data related to HPC for the year ended December 31, 2018 reflects HPC’s results for January 1, 2018 through March 31, 2018. HPC was fully consolidated beginning April 1, 2018 as discussed above. In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

Net Income Per Limited Partner

Net Income Per Limited Partner Unit	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Net Income Per Limited Partner Unit	NET INCOME PER LIMITED PARTNER UNIT : Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversion of the ET Series A Convertible Preferred Units, as discussed in Note 8 . For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ET’s limited partner unit ownership in ETO or Sunoco LP that would have resulted assuming the incremental units related to our or Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method. A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows: Years Ended December 31, 2019 2018 2017 Income from continuing operations $ 4,899 $ 3,630 $ 2,543 Less: Net income attributable to redeemable noncontrolling interests 51 39 — Less: Income (loss) from continuing operations attributable to noncontrolling interests 1,256 1,888 1,583 Income from continuing operations, net of noncontrolling interests 3,592 1,703 960 Less: General Partner’s interest in income from continuing operations 4 3 2 Less: ET Series A Convertible Preferred Unitholders’ interest in net income from continuing operations — 33 38 Income from continuing operations available to Limited Partners $ 3,588 $ 1,667 $ 920 Basic Income from Continuing Operations per Limited Partner Unit: Weighted average limited partner units 2,628.0 1,423.8 1,078.2 Basic income from continuing operations per Limited Partner unit $ 1.37 $ 1.17 $ 0.86 Basic loss from discontinued operations per Limited Partner unit $ — $ (0.01 ) $ (0.01 ) Diluted Income from Continuing Operations per Limited Partner Unit: Income from continuing operations available to Limited Partners $ 3,588 $ 1,667 $ 920 Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units (1 ) 33 38 Diluted income from continuing operations available to Limited Partners 3,587 1,700 958 Weighted average limited partner units 2,628.0 1,423.8 1,078.2 Dilutive effect of unconverted unit awards and ET Series A Convertible Preferred Units — 30.3 72.6 Dilutive effect of unvested unit awards 9.6 7.3 — Weighted average limited partner units, assuming dilutive effect of unvested unit awards 2,637.6 1,461.4 1,150.8 Diluted income from continuing operations per Limited Partner unit $ 1.36 $ 1.16 $ 0.84 Diluted loss from discontinued operations per Limited Partner unit $ — $ (0.01 ) $ (0.01 )

Debt Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2019
Debt Obligations [Abstract]
Debt Disclosure [Text Block]	DEBT OBLIGATIONS: Our debt obligations consist of the following: December 31, 2019 2018 Parent Company Indebtedness: 7.50% Senior Notes due October 15, 2020 (1) $ 52 $ 1,187 4.25% Senior Notes due March 15, 2023 5 1,000 5.875% Senior Notes due January 15, 2024 23 1,150 5.50% Senior Notes due June 1, 2027 44 1,000 ET Senior Secured Term Loan — 1,220 Unamortized premiums, discounts and fair value adjustments, net — (10 ) Deferred debt issuance costs — (27 ) 124 5,520 Subsidiary Indebtedness: ETO Debt 9.70% Senior Notes due March 15, 2019 — 400 9.00% Senior Notes due April 15, 2019 — 450 5.50% Senior Notes due February 15, 2020 (1) 250 250 5.75% Senior Notes due September 1, 2020 (1) 400 400 4.15% Senior Notes due October 1, 2020 (1) 1,050 1,050 7.50% Senior Notes due October 15, 2020 (1) 1,135 — 4.40% Senior Notes due April 1, 2021 600 600 4.65% Senior Notes due June 1, 2021 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 — 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 — 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 — 9.00% Debentures due November 1, 2024 65 65 4.05% Senior Notes due March 15, 2025 1,000 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 — 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 — 8.25% Senior Notes due November 15, 2029 267 267 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 — Floating Rate Junior Subordinated Notes due November 1, 2066 546 546 ETO $2.00 billion Term Loan facility due October 2022 2,000 — ETO $5.00 billion Revolving Credit Facility due December 2023 4,214 3,694 Unamortized premiums, discounts and fair value adjustments, net (5 ) 17 Deferred debt issuance costs (207 ) (178 ) 42,120 32,288 Transwestern Debt 5.36% Senior Notes due December 9, 2020 (1) 175 175 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 ) (1 ) 574 574 Panhandle Debt 8.125% Senior Notes due June 1, 2019 — 150 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 11 14 246 399 Bakken Project Debt 3.625% Senior Notes due April 1, 2022 650 — 3.90% Senior Notes due April 1, 2024 1,000 — 4.625% Senior Notes due April 1, 2029 850 — Bakken $2.50 billion Credit Facility due August 2019 — 2,500 Unamortized premiums, discounts and fair value adjustments, net (3 ) — Deferred debt issuance costs (16 ) (3 ) 2,481 2,497 Sunoco LP Debt 4.875% Senior Notes Due January 15, 2023 1,000 1,000 5.50% Senior Notes Due February 15, 2026 800 800 6.00% Senior Notes Due April 15, 2027 600 — 5.875% Senior Notes Due March 15, 2028 400 400 Sunoco LP $1.50 billion Revolving Credit Facility due July 2023 162 700 Lease-related obligations 135 107 Deferred debt issuance costs (26 ) (23 ) 3,071 2,984 USAC Debt 6.875% Senior Notes due April 1, 2026 725 725 6.875% Senior Notes due September 1, 2027 750 — USAC $1.60 billion Revolving Credit Facility due April 2023 403 1,050 Deferred debt issuance costs (26 ) (16 ) 1,852 1,759 SemGroup Debt HFOTCO Tax Exempt Notes due 2050 225 — SemCAMS Revolver due February 25, 2024 92 — SemCAMS Term Loan A due February 25, 2024 269 — Unamortized premiums, discounts and fair value adjustments, net 1 — Deferred debt issuance costs (3 ) — 584 — Other 2 7 Total debt 51,054 46,028 Less: Current maturities of long-term debt 26 2,655 Long-term debt, less current maturities $ 51,028 $ 43,373 (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. The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $279 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: 2020 $ 3,086 2021 1,412 2022 5,792 2023 8,965 2024 4,708 Thereafter 27,366 Total $ 51,329 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 ET Senior Notes The ET Senior Notes are the Parent Company’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Parent Company’s obligations under the ET Senior Notes previously were secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the ET Term Loan Facility, by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. Subsequent to the termination of the Revolver Credit Agreement and the ET Term Loan Facility, the collateral securing the ET Senior Notes was released. The ET Senior Notes are not guaranteed by any of the Parent Company’s subsidiaries. The covenants related to the ET Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Parent Company’s assets. 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 billion aggregate principal amount of ETO’s 2.900% Senior Notes due 2025, $1.5 billion aggregate principal amount of ETO’s 3.750% Senior Notes due 2030, and $2 billion aggregate principal amount of ETO’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 Partners Operations L.P., 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. ET-ETO Senior Notes Exchange In February 2019, ETO commenced offers to exchange all of ET’s outstanding senior notes for senior notes issued by ETO (the “ET-ETO senior notes exchange”). Approximately 97% of ET’s outstanding senior notes were tendered and accepted, and substantially all the exchanges settled on March 25, 2019. In connection with the exchange, ETO issued $4.21 billion aggregate principal amount of the following senior notes: • $1.14 billion aggregate principal amount of 7.50% senior notes due 2020 ; • $995 million aggregate principal amount of 4.25% senior notes due 2023 ; • $1.13 billion aggregate principal amount of 5.875% senior notes due 2024 ; and • $956 million aggregate principal amount of 5.50% senior notes due 2027 . 2019 ETO Senior Notes Offering and Redemption In January 2019, ETO issued the following senior notes: • $750 million aggregate principal amount of 4.50% senior notes due 2024 ; • $1.50 billion aggregate principal amount of 5.25% senior notes due 2029 ; and • $1.75 billion aggregate principal amount of 6.25% senior notes due 2049 . The $3.96 billion net proceeds from the offering were used to make an intercompany loan to ET (which ET used to repay its term loan in full), for general partnership purposes and to redeem at maturity all of the following: • ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019 ; • ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019 ; and • Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019 . Panhandle Senior Notes Redemption In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO. Bakken Senior Notes Offering In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, issued the following senior notes related to the Bakken pipeline: • $650 million aggregate principal amount of 3.625% senior notes due 2022; • $1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and • $850 million aggregate principal amount of 4.625% senior notes due 2029. The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated. Sunoco LP Senior Notes Offering In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00% senior notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings under its credit facility. In July 2019, Sunoco LP completed an exchange of these notes for registered notes with substantially identical terms. USAC Senior Notes In March 2019, USAC issued $750 million aggregate principal amount of 6.875% senior notes due 2027 in a private placement, and in December 2019, USAC exchanged those notes for substantially identical senior notes registered under the Securities Act. The net proceeds from this offering were used to repay a portion of USAC’s existing borrowings under its credit facility and for general partnership purposes. 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. Term Loans, Credit Facilities and Commercial Paper ET Term Loan Facility On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement had a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contained an accordion feature, under which the total commitments may be increased, subject to the terms thereof. In connection with the Parent Company’s entry into the Senior Secured Term Loan Agreement on February 2, 2017, the Parent Company terminated its previous term loan agreements. Pursuant to the Term Credit Agreement, the Term Lenders provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). Under the Term Credit Agreement, the obligations of the Parent Company were secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets. Interest accrued on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. On January 15, 2019, Energy Transfer LP paid in full all outstanding borrowings under its Senior Secured Term Loan Agreement and thereafter terminated the term loan agreement. In connection with the termination of the term loan agreement, the collateral securing certain series of the Partnership’s outstanding senior notes was released in accordance with the terms of the applicable indentures governing such senior notes. 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 Partners Operations L.P. As of December 31, 2019 , 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, 2019 was 2.78% . 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, 2019 , the ETO Five-Year Credit Facility had $4.21 billion outstanding, of which $1.64 billion was commercial paper. The amount available for future borrowings was $709 million after taking into account letters of credit of $77 million . The weighted average interest rate on the total amount outstanding as of December 31, 2019 was 2.88% . 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 27, 2020. As of December 31, 2019 , the ETO 364-Day Facility had no outstanding borrowings. Sunoco LP Credit Facility Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”). As of December 31, 2019 , the Sunoco LP Credit Facility had $162 million outstanding borrowings and $8 million in standby letters of credit. The amount available for future borrowings was $1.33 billion at December 31, 2019 . The weighted average interest rate on the total amount outstanding as of December 31, 2019 was 3.75% . 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, 2019 , USAC had $403 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2019 , USAC had $1.2 billion of availability under its credit facility. The weighted average interest rate on the total amount outstanding as of December 31, 2019 was 4.31% . SemCAMS Credit Facilities SemCAMS is party to a credit agreement providing for a C $350 million (US $270 million at the December 31, 2019 exchange rate) senior secured term loan facility, a C $525 million (US $404 million at the December 31, 2019 exchange rate) senior secured revolving credit facility, and a C $300 million (US $231 million at the December 31, 2019 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 . SemCAMS may incur additional term loans and revolving commitments in an aggregate amount not to exceed C $250 million (US $193 million at the December 31, 2019 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 the Parent Company The Term Loan Facility and ET Revolving Credit Facility contain customary representations, warranties, covenants and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements. The Term Loan Facility and ET Revolving Credit Facility contain financial covenants as follows: • Maximum Leverage Ratio – Consolidated Funded Debt (as defined therein) of the Parent Company to Consolidated EBITDA (as defined therein) of the Parent Company of not more than 6.0 to 1 , with a permitted increase to 7 to 1 during a specified acquisition period following the close of a specified acquisition; and • Consolidated EBITDA (as defined therein) to interest expense of not less than 1.5 to 1 . 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 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 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 Facility ranges from 0.125% to 0.300% . The applicable margin for eurodollar rate loans under the ETO 364-Day Facility ranges from 1.250% to 1.750% and the applicable margin for base rate loans ranges from 0.250% to 0.750% . 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 4.04 to 1 at December 31, 2019 , 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) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (ii) 5.0 to 1.0 thereafter, in each case subject to a provision for increases to such thresholds by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs. 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 Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions. We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2019 .

Redeemable Preferred Units

Redeemable Preferred Units	12 Months Ended
	Dec. 31, 2019
Preferred Units, Preferred Partners' Capital Account [Abstract]
Redeemable Noncontrolling Interest [Text Block]	REDEEMABLE NONCONTROLLING INTERESTS: Certain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of December 31, 2019 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 $247 million in SemCAMS preferred shares acquired as part of the merger with 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. SemCAMS Redeemable Preferred Stock SemCAMS has 300,000 shares of cumulative preferred stock issued and outstanding. The preferred stock is redeemable at SemCAMS’s option subsequent to January 3, 2021 at a redemption price of C$1,100 (US $845 at the December 31, 2019 exchange rate) per share. The preferred stock is redeemable by the holder contingent upon a change of control or liquidation of SemCAMS. The preferred stock is convertible to SemCAMS common shares in the event of an initial public offering by SemCAMS. The preferred stock was recorded at fair value in connection with the SemGroup purchase accounting. Dividends on the preferred stock are payable in-kind through the quarter ending June 30, 2020. The dividends paid-in-kind increased the liquidation preference such that as of December 31, 2019, the preferred stock was convertible into 315,859 shares.

Equity

Equity	12 Months Ended
	Dec. 31, 2019
Partners' Capital Notes [Abstract]
Equity	EQUITY: Limited Partner Units Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.” As of December 31, 2019 , there were issued and outstanding 2.69 billion Common Units representing an aggregate 99.9% limited partner interest in the Partnership. Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures. Common Units The change in ET Common Units during the years ended December 31, 2019 , 2018 and 2017 was as follows: Years Ended December 31, 2019 2018 2017 Number of Common Units, beginning of period 2,619.4 1,079.1 1,046.9 Conversion of ET Series A Convertible Preferred Units to common units — 79.1 — Common Units issued in mergers and acquisitions 57.6 1,458.9 — Common Units repurchased (1.9 ) — — Issuance of Common Units 14.5 2.3 32.2 Number of Common Units, end of period 2,689.6 2,619.4 1,079.1 In October 2018, ET issued 1.46 billion ET Common Units in connection with the Energy Transfer Merger. In December 2019, ET issued 57.6 million ET Common Units in connection with the SemGroup acquisition. ET Equity Distribution Agreement In March 2017, the Partnership entered into an equity distribution agreement relating to at-the-market offerings of its common units with an aggregate offering price up to $1 billion . As of December 31, 2019 , there have been no sales of common units under the equity distribution agreement. ET Series A Convertible Preferred Units In May 2018, the Partnership converted its 329.3 million Series A Convertible Preferred Units into approximately 79.1 million ET common units in accordance with the terms of ET’s partnership agreement. ET Class A Units In connection with the Energy Transfer Merger, the Partnership issued 647,745,099 Class A units (“ET Class A Units”) representing limited partner interests in the Partnership to LE GP, LLC (“LE GP”), the general partner of ET. The number of ET Class A Units issued allows LE GP and its affiliates to retain a voting interest in the Partnership that is identical to their voting interest in the Partnership prior to the completion of the Merger. The ET Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, ET’s partnership agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of ET Class A Units additional ET Class A Units such that the holder maintains a voting interest in the Partnership that is identical to its voting interest in the Partnership prior to such issuance. The ET Class A Units are not entitled to distributions and otherwise have no economic attributes. ET Repurchase Program In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of ET Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 1.9 million ET Common Units under this program in 2019 and no ET Common Units in 2018 or 2017 and there was $911 million available to use under the program as of December 31, 2019 . ET Distribution Reinvestment Program During the year ended December 31, 2019 , distributions of $148 million were reinvested under the distribution reinvestment program. As of December 31, 2019 , a total of 29 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment program. Sale of Common Units by Subsidiaries The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented. ETO Class K Units As of December 31, 2019, 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. ETO 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. ETO 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. ETO Preferred Units In November 2017, ETO issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit and 550,000 of its 6.625% Series B Preferred Units at a price of $1,000 per unit. In April 2018, ETO issued 18 million of its 7.375% Series C Preferred Units at a price of $25 per unit. In July 2018, ETO issued 17.8 million of its 7.625% Series D Preferred Units at a price of $25 per unit. In April 2019, ETO issued 32 million of its 7.600% Series E Preferred Units at a price of $25 per unit. As of December 31, 2019 all of ETO Series A, Series B, Series C, Series D and Series E Preferred Units issued remain outstanding. 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. PennTex Tender Offer and Limited Call Right Exercise In June 2017, ETO purchased all of the outstanding PennTex common units not previously owned by ETO for $20.00 per common unit in cash. ETO now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ. Subsidiary Equity Transactions Sunoco LP’s Common Unit Repurchase In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETO for aggregate cash consideration of approximately $540 million . ETO used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility. 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, 2019 and 2018, Sunoco LP issued no units under its ATM program. For the year ended December 31, 2017 , Sunoco LP issued an additional 1.3 million units with total net proceeds of $33 million , net of commissions of $0.3 million . As of December 31, 2019 , $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement. Sunoco LP’s Series A Preferred Units On March 30, 2017, ET purchased 12.0 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million . The distribution rate of Sunoco LP Series A Preferred Units is 10.00% , per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the liquidation preference. In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ET for an aggregate redemption amount of approximately $313 million . The redemption amount included the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions. USAC’s Distribution Reinvestment Program During the year ended December 31, 2019 and nine months ended December 31, 2018 , distributions of $1 million and $0.6 million , respectively, were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 60,584 and 39,280 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. Parent Company Quarterly Distributions of Available Cash Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from its interest in ETO. Our distributions declared and paid with respect to our common units were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2016 (1) February 7, 2017 February 21, 2017 $ 0.2850 March 31, 2017 (1) May 10, 2017 May 19, 2017 0.2850 June 30, 2017 (1) August 7, 2017 August 21, 2017 0.2850 September 30, 2017 (1) November 7, 2017 November 20, 2017 0.2950 December 31, 2017 (1) February 8, 2018 February 20, 2018 0.3050 March 31, 2018 May 7, 2018 May 21, 2018 0.3050 June 30, 2018 August 6, 2018 August 20, 2018 0.3050 September 30, 2018 November 8, 2018 November 19, 2018 0.3050 December 31, 2018 February 8, 2019 February 19, 2019 0.3050 March 31, 2019 May 7, 2019 May 20, 2019 0.3050 June 30, 2019 August 6, 2019 August 19, 2019 0.3050 September 30, 2019 November 5, 2019 November 19, 2019 0.3050 December 31, 2019 February 7, 2020 February 19, 2020 0.3050 (1) Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received ET Series A Convertible Preferred Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $ 0.11 per unit. See additional information below. Our distributions declared and paid with respect to ET Series A Convertible Preferred Unit were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2016 February 7, 2017 February 21, 2017 $ 0.1100 March 31, 2017 May 10, 2017 May 19, 2017 0.1100 June 30, 2017 August 7, 2017 August 21, 2017 0.1100 September 30, 2017 November 7, 2017 November 20, 2017 0.1100 December 31, 2017 February 8, 2018 February 20, 2018 0.1100 March 31, 2018 May 7, 2018 May 21, 2018 0.1100 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 December 31, 2017 February 1, 2018 February 15, 2018 $ 15.4510 * $ 16.3780 * $ — $ — $ — 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 * Represent prorated initial distributions. Prorated initial distributions on the recently issued ETO Series F Preferred Units and ETO Series G Preferred Units will be payable in May 2020. (1) ETO Series A Preferred Units and ETO Series B 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, 2016 February 13, 2017 February 21, 2017 $ 0.8255 March 31, 2017 May 9, 2017 May 16, 2017 0.8255 June 30, 2017 August 7, 2017 August 15, 2017 0.8255 September 30, 2017 November 7, 2017 November 14, 2017 0.8255 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 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, 2019 , USAC had approximately 96.6 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 09, 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 Accumulated Other Comprehensive Income The following table presents the components of AOCI, net of tax: December 31, 2019 2018 Available-for-sale securities $ 13 $ 2 Foreign currency translation adjustment 2 (5 ) Actuarial loss related to pensions and other postretirement benefits (25 ) (48 ) Investments in unconsolidated affiliates, net (1 ) 9 Total AOCI, net of tax $ (11 ) $ (42 ) The table below sets forth the tax amounts included in the respective components of other comprehensive income: December 31, 2019 2018 Available-for-sale securities $ (1 ) $ (1 ) Foreign currency translation adjustment 2 2 Actuarial loss relating to pension and other postretirement benefits 8 12 Total $ 9 $ 13

Unit-Based Compensation Plans

Unit-Based Compensation Plans	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Abstract]
Unit-Based Compensation Plans	NON-CASH COMPENSATION PLANS: ET Non-Cash Compensation Plan We, Sunoco LP and USAC, have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other non-cash compensation awards. As of December 31, 2019 , an aggregate total of 6.5 million ET Common Units remain available to be awarded under our equity incentive plans. ET Long-Term Incentive Plan We have granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ET Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five-year service vesting requirement. The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2018 22.4 $ 15.94 Replacement awards issued in the SemGroup Transaction 1.4 11.60 Awards granted 8.9 12.51 Awards vested (4.0 ) 21.09 Awards forfeited (0.7 ) 15.70 Unvested awards as of December 31, 2019 28.0 13.89 During the years ended December 31, 2019, 2018, and 2017, the weighted average grant-date fair value per unit award granted was $12.51 , $13.00 and $17.01 , respectively. The total fair value of awards vested was $47 million , $49 million , and $40 million , respectively, based on the market price of the respective Common Units as of the vesting date. As of December 31, 2019, a total of 28.0 million unit awards remain unvested, for which ET expects to recognize a total of $258 million in compensation expense over a weighted average period of 2.6 years. Cash Restricted Units. We previously granted cash restricted units, which entitled the award recipient to receive cash equal to the market value of one ET Common Unit upon vesting. The Partnership does not currently have any cash restricted units outstanding. 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 Units Weighted Average Grant-Date Fair Value Per Unit Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2018 2.1 $ 29.15 1.4 $ 14.98 Awards granted 0.7 30.70 0.7 15.88 Awards vested (0.5 ) 30.04 (0.3 ) 13.06 Awards forfeited (0.2 ) 28.16 — 16.78 Unvested awards as of December 31, 2019 2.1 29.21 1.8 15.09 The following table summarizes the weighted average grant-date fair value per unit award granted: Years Ended December 31, 2019 2018 2017 Sunoco LP $ 30.70 $ 27.67 $ 28.31 USAC 15.88 15.47 N/A The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2019, 2018 and 2017 was $17 million , $22 million , and $9 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, 2019 and 2018 and Sunoco LP for the year ended December 31, 2017. As of December 31, 2019 , estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $57 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 (Note

Income Taxes Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 Current expense (benefit): Federal $ (20 ) $ (8 ) $ 54 State (2 ) 19 (16 ) Total (22 ) 11 38 Deferred expense (benefit): Federal 174 181 (2,055 ) State 43 (188 ) 184 Total 217 (7 ) (1,871 ) Total income tax expense (benefit) from continuing operations $ 195 $ 4 $ (1,833 ) 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, 2019 , 2018 and 2017 is as follows: Years Ended December 31, 2019 2018 2017 Income tax expense at United States statutory rate $ 1,070 $ 763 $ 248 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax (882 ) (635 ) (477 ) Goodwill impairment — — 207 State tax, net of federal tax benefit 12 (125 ) 124 Dividend received deduction (3 ) (5 ) (14 ) Federal rate change — — (1,812 ) Change in tax status of subsidiary — — (124 ) Other (2 ) 6 15 Income tax expense (benefit) from continuing operations $ 195 $ 4 $ (1,833 ) 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, 2019 2018 Deferred income tax assets: Net operating losses, alternative minimum tax credit and other carryforwards $ 936 $ 768 Pension and other postretirement benefits 7 34 Long-term debt — 13 Other 85 181 Total deferred income tax assets 1,028 996 Valuation allowance (95 ) (96 ) Net deferred income tax assets 933 900 Deferred income tax liabilities: Property, plant and equipment (501 ) (782 ) Investments in affiliates (3,547 ) (2,872 ) Trademarks (72 ) (63 ) Other (21 ) (109 ) Total deferred income tax liabilities (4,141 ) (3,826 ) Net deferred income taxes $ (3,208 ) $ (2,926 ) As of December 31, 2019 , ETP Holdco had a federal net operating loss carryforward of $2.65 billion , of which $1.10 billion will expire between 2031 and 2037 while the remaining can be carried forward indefinitely. As of December 31, 2019, Semgroup Corporation had a federal net operating loss carryforward of $766 million of which $185 million will expire between 2031 and 2037 while the remaining can be carried forward indefinitely. As of December 31, 2019 , Sunoco Property Company LLC, a corporate subsidiary of Sunoco LP, has no federal net operating loss carryforward. Our corporate subsidiaries have $15 million of federal alternative minimum tax credits at December 31, 2019 , of which $8 million is expected to be reclassified to current income tax receivable in 2020 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have state net operating loss carryforward benefits of $118 million , net of federal tax, which expire between 2020 and 2038, while others are carried forward indefinitely. Our corporate subsidiaries have Canadian net operating losses of $68 million that will begin to expire in 2033 and foreign tax credits of $45 million that will begin to expire in 2020. Our corporate subsidiaries have cumulative excess business interest expense of $35 million available for carryforward indefinitely. A valuation allowance of $49 million is attributable to state net operating loss carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania. A separate valuation allowance of $46 million is attributable to foreign tax credits. The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2019 2018 2017 Balance at beginning of year $ 624 $ 609 $ 615 Additions attributable to tax positions taken in the current year — 8 — Additions attributable to tax positions taken in prior years 11 7 28 Reduction attributable to tax positions taken in prior years (541 ) — (25 ) Lapse of statute — — (9 ) Balance at end of year $ 94 $ 624 $ 609 As of December 31, 2019 , we have $90 million ( $72 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 2019 , we recognized interest and penalties of less than $1 million . At December 31, 2019 , we have interest and penalties accrued of $3 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 ETC Sunoco's petition on October 7, 2019. The petition for certiorari applied to Sunoco's 2004 through 2009 tax years, and 2010 - 2011 are on extension with the IRS through March 30, 2020, via a Form 907 (Agreement to Extend the Time to Bring Suit). Due to the uncertainty surrounding the litigation, a reserve of $530 million was previously established for the full amount of the pending refund claims, and the receivable and reserve for this issue were netted in the balance sheet. Subsequent to the Supreme Court's denial of the petition in October 2019, the receivable and reserve have been reversed, with no impact to the Partnership's financial position 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 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, ET and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2014 and prior tax years. ET 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 Liabilities	12 Months Ended
	Dec. 31, 2019
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: FERC Proceedings By Order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by the Order dated October 1, 2019. A hearing in the combined proceedings is scheduled for August 2020, with an initial decision expected in early 2021. By Order issued February 19, 2019, the FERC initiated a review of Southwest Gas’ existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing. Southwest Gas filed a cost and revenue study on May 6, 2019. On July 10, 2019, Southwest Gas filed an Offer of Settlement in this Section 5 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. By order dated October 29, 2019, the FERC approved the settlement as filed, and there is not a material impact on revenue. In addition, on November 30, 2018, Sea Robin filed a rate case pursuant to Section 4 of the Natural Gas Act. On July 22, 2019, Sea Robin filed an Offer of Settlement in this Section 4 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. By order dated October 17, 2019, the FERC approved the settlement as filed, and there is not a material impact on revenue. Commitments In the normal course of business, ETO purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETO believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations. Our joint venture agreements require that we funds 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, 2019 2018 2017 ROW expense $ 45 $ 46 $ 46 PES Refinery Fire and Bankruptcy We own an approximately 7.4% non-operating interest in PES, which owns a refinery in Philadelphia. In addition, the Partnership provides logistics services to PES under commercial contracts and Sunoco LP has historically purchased refined products from PES. In June 2019, an explosion and fire occurred at the refinery complex. On July 21, 2019, 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. The Partnership has not recorded a valuation allowance related to the note receivable as of December 31, 2019, because management is not yet able to determine the collectability of the note in bankruptcy. In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of December 31, 2019, 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.” In the event that the PES property is sold in connection with the bankruptcy proceeding, it may be necessary for the Partnership to record additional environmental remediation liabilities in the future depending upon the proposed use of such property by the buyer of the property; 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. 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 challenging permits issued by the United States Army Corps of Engineers (“USACE”) permitting 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 allowing 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”). Plaintiffs and Defendants filed cross motions for summary judgment, and the parties await a ruling. While we believe that the pending lawsuits are unlikely to halt or suspend operation of the pipeline, we cannot assure this outcome. Energy Transfer cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project. Mont Belvieu Incident On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas, experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells, 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”) 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, 2019 , Sunoco is a defendant in five cases, including one case each initiated by the States of Maryland and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals L.P. (“SPMT”). It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position. Regency Merger Litigation 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 the parties await a ruling from the court. The Regency Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it. Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation On January 27, 2014, a trial commenced between ETO against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETO against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETO. The jury also found that ETO owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETO and awarded ETO $536 million , consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETO shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETO’s motion for rehearing to the Court of Appeals was denied. On November 27, 2017, ETO filed a Petition for Review with the Texas Supreme Court. On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. On June 28, 2019, the Texas Supreme Court granted ETO’s petition for review and oral argument was heard on October 8, 2019. On January 31, 2020, the Texas Supreme Court affirmed the judgment of the Court of Appeals. Litigation Filed By or Against Williams In April and May, 2016, the Williams Companies, Inc. (“Williams”) filed two lawsuits (the “Williams Litigation”) against ET, LE GP, and, in one of the lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC (collectively, “Defendants”), alleging that Defendants breached their obligations under the ET-Williams merger agreement (the “Merger Agreement”). In general, Williams alleges that Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) issuing the Partnership’s Series A Convertible Preferred Units (the “Issuance”), and (c) making allegedly untrue representations and warranties in the Merger Agreement. After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of Defendants and issued a declaratory judgment that ET could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court did not reach a decision regarding Williams’ claims related to the Issuance nor the alleged untrue representations and warranties. On March 23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June 2016 trial. In September 2016, the parties filed amended pleadings. Williams filed an amended complaint seeking a $410 million termination fee based on the alleged breaches of the Merger Agreement listed above. Defendants filed amended counterclaims and affirmative defenses, asserting that Williams materially breached the Merger Agreement by, among other things, (a) failing to use its reasonable best efforts to consummate the merger, (b) failing to provide material information to ET for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, and (d) breaching the Merger Agreement’s forum-selection clause. Trial is currently set for June 2020. Defendants cannot predict the outcome of the Williams Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them. Unitholder Litigation Relating to the Issuance ET unitholders filed a putative class action lawsuits against ET, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon in the Delaware Court of Chancery (the “Issuance Litigation”). Plaintiffs alleged that the issuance of ET Series A Convertible Preferred Units (“Issuance”) breached various provisions of ET’s partnership agreement. Plaintiffs sought, among other things, preliminary and permanent injunctive relief and class-wide damages allegedly resulting from the Issuance. The matter was tried on February 19-21, 2018. In a May 17, 2018 opinion, the court found that one provision of the Issuance breached ET’s partnership agreement, but that this breach caused no damages. The court denied Plaintiffs’ requests for injunctive relief and declined to award damages or any other form of relief. Plaintiffs subsequently filed a motion seeking $8.5 million in attorneys’ fees and expenses, which the defendants opposed. On May 6, 2019, the Court entered an Order and Final Judgment, consistent with its May 2018 post-trial opinion, in which it ordered Energy Transfer to pay $4.5 million in attorneys’ fees and expenses and granted Plaintiffs’ Motion for Class Certification. On June 5, 2019, Plaintiffs filed a notice of appeal to the Supreme Court of Delaware from, among other things, the May 17, 2018 Memorandum Opinion and the May 6, 2019 Order and Final Judgment. The Delaware Supreme Court summarily affirmed the Court’s rulings. The case was closed on December 12, 2019, ending the litigation. Rover On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants (collectively, the Defendants”) seeking to recover approximately $2.6 million in 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 Defendants intend to oppose. Bayou Bridge On January 11, 2018, environmental groups and a trade association filed suit against the U.S. Army Corps of Engineers (“USACE”) in the United States District Court for the Middle District of Louisiana alleging violations of the National Environmental Policy Act, the Clean Water Act, and the Rivers and Harbors Act. ETO, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened. In February 2018, the District Court initially granted Plaintiffs’ motion for a preliminary injunction, but the Fifth Circuit Court of Appeals subsequently vacated that decision. The Fifth Circuit’s ruling allowed construction to continue and be completed during the pendency of the case. Plaintiffs filed a second motion for preliminary injunction in January 2019, which was denied. Plaintiffs and Defendants filed cross motions for summary judgment, and the parties await a ruling. 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 Department 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. 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 (“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 former 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. To date, the Partnership is not aware of any further action with regard to this Notice. In December 2019, the former DA announced charges against a current employee related to the provision of security services. The Partnership has secured independent counsel for the employee. While the Partnership will continue to cooperate with the investigation, it intends to vigorously defend itself. Delaware County, Pennsylvania Investigation On March 11, 2019, the Delaware County District Attorney’s Office (“DA”) announced that the DA and the Pennsylvania Attorney General’s Office, at the request of the DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. The Partnership has not been appraised of the specific conduct under investigation. While the Partnership will cooperate with the investigation, it intends to vigorously defend itself. Recently Filed Litigation Involving Energy Transfer LP Two purported unitholders of ET filed securities class actions against ET’s Board of Directors and ET as a nominal defendant. See Bettiol v. LP GP, Case No. 3:19-cv-02890-X and Donel Davidson v. Kelcy L. Warren, Cause No. DC-20-02322. The complaints assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, abuse of control, and gross mismanagement and seek damages on behalf of ET related to an alleged decline in ET’s unit value and also seek changes to ET’s corporate governance structure, attorney’s fees, and litigation costs. Another purported unitholder of ET, Allegheny County Employees’ Retirement System (“ACERS”), individually and on behalf of all other similarly situated, filed a federal securities class action suit against ET and three of ET’s directors: Kelcy L. Warren, John W. McReynolds, and Thomas E. Long. The complaint asserts claims for violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. ACERS seeks damages allegedly sustained by it and the class in connection with an alleged decline in ET’s unit value, as well as attorney’s fees, litigation costs, and any other relief the court deems proper. The lawsuits allege, among other things, the existence of wrongdoing by ET during permitting and construction of its Mariner East pipeline project, including that ET made materially false and misleading statements regarding its business, operations, and compliance policies related to the project. The defendants cannot predict the outcome of these lawsuits or any lawsuits that might be filed subsequent to the date of this filing; nor can the defendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the defendants believe that the claims are without merit and intend to vigorously contest them. Other Litigation and Contingencies We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2019 and 2018 , accruals of approximately $120 million and $56 million , respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period. The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. In addition, other legal proceedings exist that are considered reasonably possible to result in unfavorable outcomes. For those where possible losses can be estimated, the range of possible losses related to these contingent obligations is estimated to be up to $80 million ; however, no accruals have been recorded as of December 31, 2019 . 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 that enforcement actions were being pursued for three separate crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) which allegedly occurred in February 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) which allegedly occurred in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma which allegedly occurred in January 2015. In January 2019, a Consent Decree approved by all parties as well as an accompanying Complaint was filed in the United States District Court for the Western District of Louisiana seeking public comment and final court approval to resolve all penalties with DOJ and LDEQ for the three releases. Subsequently, the court approved the Consent Decree and the penalty payment of $5.4 million was satisfied. The Consent Decree requires certain injunctive relief to be completed on the Longview-to-Mayersville pipeline within three years but the injunctive relief is not expected to have any material impact on operations. In addition to resolution of the civil penalty and injunctive relief, we continue to discuss natural resource damages with the Louisiana trustees related to the Caddo Parish, Louisiana release. In October 2018, Pipeline Hazardous Materials Safety Administration (“PHMSA”) issued a notice of proposed safety order (the “Notice”) to SPMT, a wholly owned subsidiary of ETO. The Notice alleged that conditions exist on certain pipeline facilities owned and operated by SPMT in Nederland, Texas that pose a pipeline integrity risk to public safety, property or the environment. The Notice also made preliminary findings of fact and proposed corrective measures. SPMT responded to the Notice by submitting a timely written response on November 2, 2018, attended an informal consultation held on January 30, 2019 and entered into a consent agreement with PHMSA resolving the issues in the Notice as of March 2019. SPMT is currently awaiting response from PHMSA regarding the approval status of the submitted Remedial Work Plan. On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The 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 will be presented to the OCC at a final hearing the date of which is to be determined. 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, 2019 , Sunoco had been named as a PRP at approximately 40 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

Revenue (Notes)

Revenue (Notes)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	REVENUE: The following disclosures discuss the Partnership’s revised revenue recognition policies upon the adoption of ASU 2014-09 on January 1, 2018. These policies were applied to the amounts reflected in the Partnership’s consolidated financial statements for the years ended December 31, 2019 and 2018, while the amounts reflected in the Partnership’s consolidated financial statements for the year ended December 31, 2017 were recorded under the Partnership’s previous accounting policies. 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 17 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2019 and 2018 and ASC Topic 605 for 2017 . Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. 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 Royal Dutch Shell plc (“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 determine 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 fee for a right to use our assets, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. 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, January 1, 2018 $ 221 Additions 765 Revenue recognized (592 ) Balance, December 31, 2018 394 Additions 664 Revenue recognized (681 ) Balance, December 31, 2019 $ 377 The balances of receivables from contracts with customers listed in the table below include both current trade receivables and long-term receivables, net of allowance for doubtful accounts. The allowance for receivables represents Sunoco LP’s best estimate of the probable losses associated with potential customer defaults. Sunoco LP determines the allowance based on historical experience and on a specific identification basis. The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2019 and 2018 were as follows: December 31, 2019 December 31, 2018 Contract Balances Contract asset $ 117 $ 75 Accounts receivable from contracts with customers 366 347 Contract liability — 1 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, 2019 and 2018 was $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, 2019 , the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $43.59 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below: Years Ending December 31, 2020 2021 2022 Thereafter Total Revenue expected to be recognized on contracts with customers existing as of December 31, 2019 $ 6,232 $ 5,300 $ 4,899 $ 27,158 $ 43,589 Practical Expedients Utilized by the Partnership The Partnership elected the follow

Lease Accounting (Notes)

Lease Accounting (Notes)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lessee, Operating Leases [Text Block]	LEASE ACCOUNTING: Lessee Accounting The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet. At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term. To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives. Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance. For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded. The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of December 31, 2019 were as follows: December 31, 2019 Operating leases: Lease right-of-use assets, net $ 935 Operating lease current liabilities 60 Accrued and other current liabilities 1 Non-current operating lease liabilities 901 Finance leases: Property, plant and equipment, net $ 1 Lease right-of-use assets, net 29 Accrued and other current liabilities 1 Current maturities of long-term debt 6 Long-term debt, less current maturities 26 Other non-current liabilities 2 The components of lease expense for the year ended December 31, 2019 were as follows: Income Statement Location Year Ended December 31, 2019 Operating lease costs: Operating lease cost Cost of goods sold $ 28 Operating lease cost Operating expenses 73 Operating lease cost Selling, general and administrative 16 Total operating lease costs 117 Finance lease costs: Amortization of lease assets Depreciation, depletion and amortization 6 Interest on lease liabilities Interest expense, net of capitalized interest 1 Total finance lease costs 7 Short-term lease cost Operating expenses 42 Variable lease cost Operating expenses 17 Lease costs, gross 183 Less: Sublease income Other revenue 47 Lease costs, net $ 136 The weighted average remaining lease terms and weighted average discount rates as of December 31, 2019 were as follows: December 31, 2019 Weighted-average remaining lease term (years): Operating leases 24 Finance leases 5 Weighted-average discount rate (%): Operating leases 5 % Finance leases 5 % Cash flows and non-cash activity related to leases for the year ended December 31, 2019 were as follows: Year Ended December 31, 2019 Operating cash flows from operating leases $ (159 ) Lease assets obtained in exchange for new finance lease liabilities 28 Lease assets obtained in exchange for new operating lease liabilities 40 Maturities of lease liabilities as of December 31, 2019 are as follows: Operating leases Finance leases Total 2020 $ 104 $ 8 $ 112 2021 96 8 104 2022 83 8 91 2023 77 7 84 2024 74 4 78 Thereafter 1,342 5 1,347 Total lease payments 1,776 40 1,816 Less: present value discount 815 5 820 Present value of lease liabilities $ 961 $ 35 $ 996 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 year ended December 31, 2019 was $149 million . Future minimum operating lease payments receivable as of December 31, 2019 are as follows: Lease Payments 2020 $ 138 2021 112 2022 75 2023 20 2024 15 Thereafter 12 Total undiscounted cash flows $ 372

Derivative Assets And Liabiliti

Derivative Assets And Liabilities	12 Months Ended
	Dec. 31, 2019
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Derivative Assets And Liabilities	DERIVATIVE ASSETS AND LIABILITIES: Commodity Price Risk We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales 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, 2019 December 31, 2018 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (BBtu): Fixed Swaps/Futures 1,483 2020 468 2019 Basis Swaps IFERC/NYMEX (1) (35,208 ) 2020-2024 16,845 2019-2020 Options – Puts — — 10,000 2019 Power (Megawatt): Forwards 3,213,450 2020-2029 3,141,520 2019 Futures (353,527 ) 2020 56,656 2019-2021 Options – Puts 51,615 2020 18,400 2019 Options – Calls (2,704,330 ) 2020-2021 284,800 2019 (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (18,923 ) 2020-2022 (30,228 ) 2019-2021 Swing Swaps IFERC (9,265 ) 2020 54,158 2019-2020 Fixed Swaps/Futures (3,085 ) 2020-2021 (1,068 ) 2019-2021 Forward Physical Contracts (13,364 ) 2020-2021 (123,254 ) 2019-2020 NGL (MBbls) – Forwards/Swaps (1,300 ) 2020-2021 (2,135 ) 2019 Crude (MBbls) – Forwards/Swaps 4,465 2020 20,888 2019 Refined Products (MBbls) – Futures (2,473 ) 2020-2021 (1,403 ) 2019 Corn (thousand bushels) (1,210 ) 2020 (1,920 ) 2019 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (31,780 ) 2020 (17,445 ) 2019 Fixed Swaps/Futures (31,780 ) 2020 (17,445 ) 2019 Hedged Item – Inventory 31,780 2020 17,445 2019 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. Interest Rate Risk We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances. The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes: Term Type (1) Notional Amount Outstanding December 31, 2019 December 31, 2018 March 2019 Pay a floating rate and receive a fixed rate of 1.42% $ — $ 300 July 2019 (2) Forward-starting to pay a fixed rate of 3.56% and receive a floating rate — 400 July 2020 (2)(3) Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400 400 July 2021 (2) Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400 400 July 2022 (2) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 400 — (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, 2019 December 31, 2018 December 31, 2019 December 31, 2018 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 24 $ — $ — $ (13 ) 24 — — (13 ) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 319 402 (350 ) (397 ) Commodity derivatives 41 158 (39 ) (173 ) Interest rate derivatives — — (399 ) (163 ) 360 560 (788 ) (733 ) Total derivatives $ 384 $ 560 $ (788 ) $ (746 ) The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 2019 December 31, 2018 December 31, 2019 December 31, 2018 Derivatives without offsetting agreements Derivative liabilities $ — $ — $ (399 ) $ (163 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 41 158 (39 ) (173 ) Broker cleared derivative contracts Other current assets (liabilities) 343 402 (350 ) (410 ) 384 560 (788 ) (746 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (18 ) (47 ) 18 47 Counterparty netting Other current assets (liabilities) (318 ) (397 ) 318 397 Total net derivatives $ 48 $ 116 $ (452 ) $ (302 ) We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or 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, 2019 2018 2017 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ — $ (3 ) $ 26 Location of Gain (Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2019 2018 2017 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Revenues $ (3 ) $ — $ — Commodity derivatives – Trading Cost of products sold 21 32 31 Commodity derivatives – Non-trading Cost of products sold (78 ) (102 ) 5 Interest rate derivatives Gains (losses) on interest rate derivatives (241 ) 47 (37 ) Embedded derivatives Other, net — — 1 Total $ (301 ) $ (23 ) $ —

Retirement Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Retirement Benefits	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 $66 million , $62 million and $59 million to these 401(k) savings plans for the years ended December 31, 2019, 2018 and 2017 , respectively. Pension and Other Postretirement Benefit Plans Panhandle Postretirement benefits expense for the years ended December 31, 2019 , 2018 , and 2017 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. In March, 2012, ETC Sunoco established a trust for its postretirement benefit liabilities. ETC Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of ETC Sunoco 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, 2019 December 31, 2018 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 $ 1 $ 37 $ 198 $ 1 $ 47 $ 156 Service cost — — 1 — — 1 Interest cost 2 1 7 — 1 5 Amendments — — — — — 60 Benefits paid, net (1 ) (7 ) (16 ) — (7 ) (17 ) Actuarial (gain) loss and other 4 — 18 — (4 ) (7 ) Settlements (4 ) — — — — — SemGroup Acquisition 50 3 — — — — Benefit obligation at end of period 52 34 208 1 37 198 Change in plan assets: Fair value of plan assets at beginning of period 1 — 241 1 — 257 Return on plan assets and other 6 — 35 — — (8 ) Employer contributions 1 — 10 — — 9 Benefits paid, net (1 ) — (16 ) — — (17 ) Settlements (4 ) — — — — — SemGroup Acquisition 40 — — — — — Fair value of plan assets at end of period 43 — 270 1 — 241 Amount underfunded (overfunded) at end of period $ 9 $ 34 $ (62 ) $ — $ 37 $ (43 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 88 $ — $ — $ 68 Current liabilities — (5 ) (2 ) — (6 ) (2 ) Non-current liabilities (9 ) (29 ) (24 ) — (31 ) (23 ) $ (9 ) $ (34 ) $ 62 $ — $ (37 ) $ 43 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain (loss) $ — $ 1 $ (5 ) $ — $ 1 $ (7 ) Prior service cost — — 40 — — 66 $ — $ 1 $ 35 $ — $ 1 $ 59 The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2019 December 31, 2018 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 51 $ 34 N/A $ — $ 37 N/A Accumulated benefit obligation 52 34 208 1 37 198 Fair value of plan assets 43 — 270 1 — 241 Components of Net Periodic Benefit Cost December 31, 2019 December 31, 2018 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Service cost $ — $ 1 $ — $ 1 Interest cost 3 7 1 5 Expected return on plan assets (2 ) (10 ) — (10 ) Prior service cost amortization — 26 — 16 Net periodic benefit cost $ 1 $ 24 $ 1 $ 12 Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2019 December 31, 2018 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 4.00 % 2.71 % 4.02 % 3.40 % Rate of compensation increase — — N/A N/A The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2019 December 31, 2018 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.33 % 3.76 % 3.52 % 3.51 % Expected return on assets: Tax exempt accounts 3.37 % 7.00 % 3.26 % 6.63 % Taxable accounts — 4.75 % N/A 4.50 % Rate of compensation increase — — N/A N/A 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, 2019 2018 Health care cost trend rate 7.25 % 7.15 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.83 % 4.82 % Year that the rate reaches the ultimate trend rate 2026 2024 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, 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 . Fair Value Measurements at December 31, 2018 Fair Value Total Level 1 Level 2 Level 3 Mutual funds (1) $ 1 $ 1 $ — $ — (1) Comprised of approximately 100% equities as of December 31, 2018 . The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: 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 . Fair Value Measurements at December 31, 2018 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 20 $ 20 $ — $ — Mutual funds (1) 144 144 — — Fixed income securities 77 — 77 — Total $ 241 $ 164 $ 77 $ — (1) Primarily comprised of approximately 53% equities, 46% fixed income securities and 1% cash as of December 31, 2018 . 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 $ 7 million to pension plans and $ 8 million to other postretirement plans in 2020 . 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 - Unfunded Plans (1) Other Postretirement Benefits (Gross, Before Medicare Part D) 2020 $ 7 $ 20 2021 8 20 2022 8 19 2023 8 18 2024 7 15 2025 – 2029 22 67 (1) Expected benefit payments of funded pension plans are less than $1 million for the next ten years. 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

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS: In June 2017, the Partnership acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 8 . ET previously paid ETO to provide services on its behalf and on behalf of other subsidiaries of ET, which included the reimbursement of various operating and general and administrative expenses incurred by ETO on behalf of ET and its subsidiaries. These agreements expired in 2016. The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. The following table summarizes the revenues from related companies on our consolidated statements of operations: Years Ended December 31, 2019 2018 2017 Affiliated revenues $ 492 $ 431 $ 303 The following table summarizes the related company accounts receivable and accounts payable balances on our consolidated balance sheets: December 31, 2019 2018 Accounts receivable from related companies: FGT $ 50 $ 25 Phillips 66 36 42 Traverse Rover LLC 42 — Other 31 44 Total accounts receivable from related companies $ 159 $ 111 As of December 31, 2019 and 2018 , accounts payable with related companies in the Partnership’s consolidated balance sheets totaled $31 million and $59 million , respectively.

Reportable Segments

Reportable Segments	12 Months Ended
	Dec. 31, 2019
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 primarily reflected in crude sales. Revenues from our investment in Sunoco LP segment are primarily reflected in refined product sales. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas sales. We report Segment Adjusted EBITDA 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, 2019 2018 2017 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,749 $ 3,428 $ 2,891 Intersegment revenues 350 309 192 3,099 3,737 3,083 Interstate transportation and storage: Revenues from external customers 1,941 1,664 1,112 Intersegment revenues 22 18 19 1,963 1,682 1,131 Midstream: Revenues from external customers 2,280 2,090 2,510 Intersegment revenues 3,751 5,432 4,433 6,031 7,522 6,943 NGL and refined products transportation and services: Revenues from external customers 9,920 10,119 7,885 Intersegment revenues 1,721 1,004 763 11,641 11,123 8,648 Crude oil transportation and services: Revenues from external customers 18,447 17,236 11,672 Intersegment revenues — 96 31 18,447 17,332 11,703 Investment in Sunoco LP: Revenues from external customers 16,590 16,982 11,713 Intersegment revenues 6 12 10 16,596 16,994 11,723 Investment in USAC: Revenues from external customers 678 495 — Intersegment revenues 20 13 — 698 508 — All other: Revenues from external customers 1,608 2,073 2,740 Intersegment revenues 81 155 161 1,689 2,228 2,901 Eliminations (5,951 ) (7,039 ) (5,609 ) Total revenues $ 54,213 $ 54,087 $ 40,523 Years Ended December 31, 2019 2018 2017 Cost of products sold: Intrastate transportation and storage $ 1,909 $ 2,665 $ 2,327 Midstream 3,577 5,145 4,761 NGL and refined products transportation and services 8,393 8,462 6,508 Crude oil transportation and services 14,758 14,439 9,826 Investment in Sunoco LP 15,380 15,872 10,615 Investment in USAC 91 67 — All other 1,504 2,006 2,509 Eliminations (5,885 ) (6,998 ) (5,580 ) Total cost of products sold $ 39,727 $ 41,658 $ 30,966 Years Ended December 31, 2019 2018 2017 Depreciation, depletion and amortization: Intrastate transportation and storage $ 184 $ 169 $ 147 Interstate transportation and storage 387 334 254 Midstream 1,066 1,006 954 NGL and refined products transportation and services 613 466 401 Crude oil transportation and services 437 445 402 Investment in Sunoco LP 181 167 169 Investment in USAC 231 169 — All other 48 103 227 Total depreciation, depletion and amortization $ 3,147 $ 2,859 $ 2,554 Years Ended December 31, 2019 2018 2017 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 18 $ 19 $ (156 ) Interstate transportation and storage 222 227 236 Midstream 20 26 20 NGL and refined products transportation and services 53 64 33 Crude oil transportation and services (1 ) 6 4 All other (10 ) 2 7 Total equity in earnings of unconsolidated affiliates $ 302 $ 344 $ 144 Years Ended December 31, 2019 2018 2017 Segment Adjusted EBITDA: Intrastate transportation and storage $ 999 $ 927 $ 626 Interstate transportation and storage 1,792 1,680 1,274 Midstream 1,602 1,627 1,481 NGL and refined products transportation and services 2,666 1,979 1,641 Crude oil transportation and services 2,972 2,330 1,379 Investment in Sunoco LP 665 638 732 Investment in USAC 420 289 — All Other 98 40 187 Total Segment Adjusted EBITDA 11,214 9,510 7,320 Depreciation, depletion and amortization (3,147 ) (2,859 ) (2,554 ) Interest expense, net of interest capitalized (2,331 ) (2,055 ) (1,922 ) Impairment losses (74 ) (431 ) (1,039 ) Gains (losses) on interest rate derivatives (241 ) 47 (37 ) Non-cash compensation expense (113 ) (105 ) (99 ) Unrealized gains (losses) on commodity risk management activities (5 ) (11 ) 59 Inventory valuation adjustments 79 (85 ) 24 Losses on extinguishments of debt (18 ) (112 ) (89 ) Adjusted EBITDA related to unconsolidated affiliates (626 ) (655 ) (716 ) Equity in earnings of unconsolidated affiliates 302 344 144 Impairment of investments in unconsolidated affiliates — — (313 ) Adjusted EBITDA related to discontinued operations — 25 (223 ) Other, net 54 21 155 Income from continuing operations before income tax (expense) benefit 5,094 3,634 710 Income tax (expense) benefit from continuing operations (195 ) (4 ) 1,833 Income from continuing operations 4,899 3,630 2,543 Loss from discontinued operations, net of income taxes — (265 ) (177 ) Net income $ 4,899 $ 3,365 $ 2,366 December 31, 2019 2018 2017 Segment assets: Intrastate transportation and storage $ 6,648 $ 6,365 $ 5,020 Interstate transportation and storage 18,111 15,081 15,316 Midstream 20,332 19,745 20,004 NGL and refined products transportation and services 19,145 18,267 17,600 Crude oil transportation and services 22,840 18,022 17,730 Investment in Sunoco LP 5,438 4,879 8,344 Investment in USAC 3,730 3,775 — All other and eliminations 2,636 2,112 2,232 Total segment assets $ 98,880 $ 88,246 $ 86,246 Years Ended December 31, 2019 2018 2017 Additions to property, plant and equipment (1) : Intrastate transportation and storage $ 124 $ 344 $ 175 Interstate transportation and storage 375 812 728 Midstream 827 1,161 1,308 NGL and refined products transportation and services 2,976 2,381 2,971 Crude oil transportation and services 403 474 453 Investment in Sunoco LP 148 103 103 Investment in USAC 200 205 — All other 215 150 268 Total additions to property, plant and equipment (1) $ 5,268 $ 5,630 $ 6,006 (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, 2019 2018 2017 Advances to and investments in affiliates: Intrastate transportation and storage $ 88 $ 83 $ 85 Interstate transportation and storage 2,524 2,070 2,118 Midstream 112 124 126 NGL and refined products transportation and services 461 243 234 Crude oil transportation and services 242 28 22 All other 33 94 120 Total advances to and investments in affiliates $ 3,460 $ 2,642 $ 2,705

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	QUARTERLY FINANCIAL DATA (UNAUDITED): Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year. 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 1,927 1,819 1,830 1,701 7,277 Net income 1,180 1,208 1,161 1,350 4,899 Limited Partners’ interest in net income 869 877 831 1,011 3,588 Income from continuing operations per limited partner unit: Basic $ 0.33 $ 0.33 $ 0.32 $ 0.38 $ 1.37 Diluted $ 0.33 $ 0.33 $ 0.32 $ 0.38 $ 1.36 Net income per limited partner unit: Basic $ 0.33 $ 0.33 $ 0.32 $ 0.38 $ 1.37 Diluted $ 0.33 $ 0.33 $ 0.32 $ 0.38 $ 1.36 Quarters Ended March 31 June 30 September 30 December 31 Total Year 2018: Revenues $ 11,882 $ 14,118 $ 14,514 $ 13,573 $ 54,087 Operating income 1,100 1,126 1,703 1,419 5,348 Income from continuing operations 726 659 1,393 852 3,630 Net income 489 633 1,391 852 3,365 Limited Partners’ interest in net income 341 330 370 617 1,658 Income from continuing operations per limited partner unit: Basic $ 0.32 $ 0.30 $ 0.32 $ 0.26 $ 1.17 Diluted $ 0.32 $ 0.30 $ 0.32 $ 0.26 $ 1.16 Net income per limited partner unit: Basic $ 0.31 $ 0.30 $ 0.32 $ 0.26 $ 1.16 Diluted $ 0.31 $ 0.30 $ 0.32 $ 0.26 $ 1.15

Operations And Organization Ope

Operations And Organization Operations and Organization (Policies)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Accounting, Policy [Policy Text Block]	The consolidated financial statements of Energy Transfer LP presented herein for the years ended December 31, 2019, 2018 and 2017 , have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. The consolidated financial statements of ET presented herein include the results of operations of: • the Parent Company; • our controlled subsidiary, Energy Transfer Operating, L.P.; and • Energy Transfer Partners GP, L.P. (“ETP GP”), the general partner of ETO, and Energy Transfer Partners, L.L.C. (“ETP LLC”), the general partner of ETP GP.

Estimates, Significant Accoun_2

Estimates, Significant Accounting Policies and Balance Sheet Detail (Policy)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
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. 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.
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 17 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2019 and 2018 and ASC Topic 605 for 2017 . Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. 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 Royal Dutch Shell plc (“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 determine 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. 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, 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. 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 doubtful accounts 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. Increases 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 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. Inventories consisted of the following: December 31, 2019 2018 Natural gas, NGLs and refined products (1) $ 833 $ 833 Crude oil 654 506 Spare parts and other 448 338 Total inventories $ 1,935 $ 1,677 (1) Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of $85 million as of December 31, 2018. 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.
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 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. In 2017, the Partnership recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets.
Equity and Cost Method Investments, Policy [Policy Text Block]	Advances to and 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.
Other Non-Current Assets, net	Other Non-Current Assets, net
Intangible Assets	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, 2019 December 31, 2018 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 7,535 $ (1,743 ) $ 7,106 $ (1,493 ) Patents (10 years) 48 (35 ) 48 (30 ) Trade names (20 years) 66 (31 ) 66 (28 ) Other (5 to 20 years) 19 (12 ) 33 (9 ) Total amortizable intangible assets 7,668 (1,821 ) 7,253 (1,560 ) Non-amortizable intangible assets: Trademarks 295 — 295 — Other 12 — 12 — Total non-amortizable intangible assets 307 — 307 — Total intangible assets $ 7,975 $ (1,821 ) $ 7,560 $ (1,560 ) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2019 2018 2017 Reported in depreciation, depletion and amortization expense $ 308 $ 321 $ 344 Estimated aggregate amortization expense of intangible assets for the next five years was as follows: Years Ending December 31: 2020 $ 394 2021 390 2022 360 2023 320 2024 307 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 primarily due to decreases in projected future revenues and cash flows from the date the intangible assets were originally recorded. Sunoco LP performed impairment tests on its indefinite-lived intangible assets during the fourth quarter of 2017 and recognized a total of $17 million in impairment charges on their contractual rights and liquor licenses primarily due to decreases in projected future revenues and cash flows from the date the intangible assets were originally recorded.
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, 2017 $ 10 $ 196 $ 870 $ 693 $ 1,167 $ 1,430 $ — $ 402 $ 4,768 Acquired — — — — — 129 366 — 495 CDM Contribution — — — — — — 253 (253 ) — Impaired — — (378 ) — — — — — (378 ) Other — — — — — — — — — 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 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 fourth quarter of 2019, $265 million goodwill was recorded in conjunction with the acquisition of SemGroup. 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. During the fourth quarter of 2017, the Partnership recognized goodwill impairments of $262 million in the interstate transportation and storage segment, $79 million in the NGL and refined products transportation and services segment and $452 million in the all other segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. Sunoco LP recognized goodwill impairments of $387 million , of which $102 million was allocated to continuing operations , primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. In connection with aforementioned impairments, the Partnership determined the fair value of our reporting units using 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 determined 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 determined 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 estimated 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.
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. Except for certain amounts discussed below, management was not able to reasonably measure the fair value of AROs as of December 31, 2019 and 2018 , in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s 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. ETC Sunoco has legal AROs for several other assets at its 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, ETC Sunoco is legally or contractually required to abandon in place or remove the asset. We believe we may have additional AROs related to ETC Sunoco’s 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 has AROs related to the estimated future cost to remove underground storage tanks. As of December 31, 2019 and 2018 , other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $247 million and $193 million , respectively. For the years ended December 31, 2019, 2018 and 2017 aggregate accretion expense related to AROs was $5 million , $13 million and $9 million , respectively. 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.
Accrued and Other Current Liabilities Policy [Text Block]	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 sheet. See Note 7 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	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, 2019 was $54.79 billion and $51.05 billion , respectively. As of December 31, 2018 , the aggregate fair value and carrying amount of our debt obligations was $45.06 billion and $46.03 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.
Contributions In Aid Of Construction Costs Policy Text Block	Contributions in Aid of Construction Costs On 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 Costs Shipping 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 our all other segment in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income . Excise taxes collected by Sunoco LP’s retail locations where Sunoco LP holds the inventory were $386 million , $370 million and $234 million for the years ended December 31, 2019 , 2018 and 2017 , respectively.
Issuances of Subsidiary Units	Issuances of Subsidiary Units We 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 Taxes	Income Taxes ET 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 Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third 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, ET would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2019, 2018 and 2017 , 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. The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
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. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.
Share-based Payment Arrangement [Policy Text Block]	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.

Revenue (Policies)

Revenue (Policies)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
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 17 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2019 and 2018 and ASC Topic 605 for 2017 . Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. 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 Royal Dutch Shell plc (“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 determine 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.
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 fee for a right to use our assets, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. 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, January 1, 2018 $ 221 Additions 765 Revenue recognized (592 ) Balance, December 31, 2018 394 Additions 664 Revenue recognized (681 ) Balance, December 31, 2019 $ 377 The balances of receivables from contracts with customers listed in the table below include both current trade receivables and long-term receivables, net of allowance for doubtful accounts. The allowance for receivables represents Sunoco LP’s best estimate of the probable losses associated with potential customer defaults. Sunoco LP determines the allowance based on historical experience and on a specific identification basis.

Lease Accounting (Policies)

Lease Accounting (Policies)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
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 year ended December 31, 2019 was $149 million .
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.

Estimates, Significant Accoun_3

Estimates, Significant Accounting Policies and Balance Sheet Detail (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities	The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2019 2018 2017 Accounts receivable $ (473 ) $ 541 $ (948 ) Accounts receivable from related companies (69 ) 162 24 Inventories (117 ) 282 58 Other current assets 117 7 38 Other non-current assets, net (78 ) (92 ) 84 Accounts payable 146 (766 ) 712 Accounts payable to related companies (32 ) (202 ) (178 ) Accrued and other current liabilities (44 ) 382 (97 ) Other non-current liabilities (186 ) 28 106 Derivative assets and liabilities, net 218 (53 ) 9 Net change in operating assets and liabilities, net of effects of acquisitions $ (518 ) $ 289 $ (192 )
Schedule Of Non-Cash Investing And Financing Activities	Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2019 2018 2017 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 1,334 $ 1,030 $ 1,060 Lease assets obtained in exchange for new lease liabilities 68 — — Net losses from subsidiary common unit transactions — (126 ) (56 ) NON-CASH FINANCING ACTIVITIES: Contribution of assets from noncontrolling interests $ — $ — $ 988 SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 1,932 $ 1,870 $ 1,914 Cash paid for income taxes 31 508 50
Schedule of Inventory	Inventories consisted of the following: December 31, 2019 2018 Natural gas, NGLs and refined products (1) $ 833 $ 833 Crude oil 654 506 Spare parts and other 448 338 Total inventories $ 1,935 $ 1,677 (1) Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of $85 million as of December 31, 2018.
Other Current Assets	Other current assets consisted of the following: December 31, 2019 2018 Deposits paid to vendors $ 95 $ 141 Prepaid expenses and other 180 209 Total other current assets $ 275 $ 350
Property, Plant and Equipment	Components and useful lives of property, plant and equipment were as follows: December 31, 2019 2018 Land and improvements $ 1,264 $ 1,168 Buildings and improvements (1 to 45 years) 2,632 2,664 Pipelines and equipment (5 to 83 years) 64,678 58,783 Product storage and related facilities (2 to 83 years) 5,898 4,978 Right of way (20 to 83 years) 4,859 4,533 Other (1 to 48 years) 1,964 1,583 Construction work-in-process 8,495 6,067 89,790 79,776 Less – Accumulated depreciation and depletion (15,597 ) (12,813 ) Property, plant and equipment, net $ 74,193 $ 66,963
Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense	We recognized the following amounts for the periods presented: Years Ended December 31, 2019 2018 2017 Depreciation, depletion and amortization expense $ 2,839 $ 2,538 $ 2,204 Capitalized interest 166 294 286
Schedule of 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, 2019 2018 Regulatory assets $ 42 $ 43 Pension assets 84 68 Deferred charges 178 173 Restricted funds 178 178 Other 593 544 Total other non-current assets, net $ 1,075 $ 1,006
Components And Useful Lives Of Intangibles And Other Assets	Components and useful lives of intangible assets were as follows: December 31, 2019 December 31, 2018 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 7,535 $ (1,743 ) $ 7,106 $ (1,493 ) Patents (10 years) 48 (35 ) 48 (30 ) Trade names (20 years) 66 (31 ) 66 (28 ) Other (5 to 20 years) 19 (12 ) 33 (9 ) Total amortizable intangible assets 7,668 (1,821 ) 7,253 (1,560 ) Non-amortizable intangible assets: Trademarks 295 — 295 — Other 12 — 12 — Total non-amortizable intangible assets 307 — 307 — Total intangible assets $ 7,975 $ (1,821 ) $ 7,560 $ (1,560 )
Aggregate Amortization Expense Of Intangibles And Other Assets	Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2019 2018 2017 Reported in depreciation, depletion and amortization expense $ 308 $ 321 $ 344
Estimated Aggregate Amortization Expense	Estimated aggregate amortization expense of intangible assets for the next five years was as follows: Years Ending December 31: 2020 $ 394 2021 390 2022 360 2023 320 2024 307
Schedule 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, 2017 $ 10 $ 196 $ 870 $ 693 $ 1,167 $ 1,430 $ — $ 402 $ 4,768 Acquired — — — — — 129 366 — 495 CDM Contribution — — — — — — 253 (253 ) — Impaired — — (378 ) — — — — — (378 ) Other — — — — — — — — — 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
Accrued and Other Current Liabilities	Accrued and other current liabilities consisted of the following: December 31, 2019 2018 Interest payable $ 579 $ 571 Customer advances and deposits 123 128 Accrued capital expenditures 1,334 1,030 Accrued wages and benefits 217 283 Taxes payable other than income taxes 263 256 Exchanges payable 67 112 Other 759 538 Total accrued and other current liabilities $ 3,342 $ 2,918
Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis	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, 2019 and 2018 based on inputs used to derive their fair values: 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: 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 ) Fair Value Total Fair Value Measurements at December 31, 2018 Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 42 $ 42 $ — Swing Swaps IFERC 52 8 44 Fixed Swaps/Futures 97 97 — Forward Physical Contracts 20 — 20 Power: Power – Forwards 48 — 48 Futures 1 1 — Options – Calls 1 1 — NGLs – Forwards/Swaps 291 291 — Refined Products – Futures 7 7 — Crude - Forwards/Swaps 1 1 — Total commodity derivatives 560 448 112 Other non-current assets 26 17 9 Total assets $ 586 $ 465 $ 121 Liabilities: Interest rate derivatives $ (163 ) $ — $ (163 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (91 ) (91 ) — Swing Swaps IFERC (40 ) — (40 ) Fixed Swaps/Futures (88 ) (88 ) — Forward Physical Contracts (21 ) — (21 ) Power: Forwards (42 ) — (42 ) Futures (1 ) (1 ) — NGLs – Forwards/Swaps (224 ) (224 ) — Refined Products – Futures (15 ) (15 ) — Crude - Forwards/Swaps (61 ) (61 ) — Total commodity derivatives (583 ) (480 ) (103 ) Total liabilities $ (746 ) $ (480 ) $ (266 )

Acquisitions and Related Tran_2

Acquisitions and Related Transactions (Tables)	12 Months Ended
	Dec. 31, 2019
Disposal Groups, Including Discontinued Operations [Table Text Block]	There were no results of operations associated with discontinued operations for the year ended December 31, 2019 . The results of operations associated with discontinued operations for the years ended December 31, 2018 and 2017 are presented in the following table: Years Ended December 31, 2018 2017 REVENUES $ 349 $ 6,964 COSTS AND EXPENSES Cost of products sold 305 5,806 Operating expenses 61 763 Depreciation, depletion and amortization — 34 Selling, general and administrative 7 168 Impairment losses — 285 Total costs and expenses 373 7,056 OPERATING LOSS (24 ) (92 ) OTHER EXPENSE Interest expense, net 2 36 Loss on extinguishment of debt 20 — Other, net 61 1 LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (107 ) (129 ) Income tax expense 158 48 LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES $ (265 ) $ (177 ) LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES ATTRIBUTABLE TO ET $ (10 ) $ (6 )
SemGroup [Member]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	Summary of Assets Acquired and Liabilities Assumed The SemGroup merger 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 purchase price allocation below is preliminary, as management is currently evaluating certain tax-related assumptions. The total purchase price was allocated as follows: At December 5, 2019 Total current assets $ 794 Property, plant and equipment 3,914 Other non-current assets 623 Goodwill (1) 265 Intangible assets 460 Total assets 6,056 Total current liabilities 629 Long-term debt, less current maturities (2) 2,576 Other non-current liabilities 196 SemCAMS Preferred shares 241 Total liabilities 3,642 Noncontrolling interest 822 Total consideration (3) 1,592 Cash received (4) 153 Total consideration, net of cash received $ 1,439 (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 SemGroup’s operations. (2) 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 were redeemed in total in December 2019, subsequent to the close of the SemGroup Transaction, utilizing proceeds from an intercompany promissory note from ETO. (3) Total consideration includes (i) cash paid to SemGroup shareholders, (ii) fair value of ET Common Units issued in the acquisition and (iii) cash paid to redeem SemGroup’s preferred shares. (4) Cash received represents cash and cash equivalents held by SemGroup as of the acquisition date.
USA Compression Partners, LP [Member]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The total purchase price was allocated as follows: At April 2, 2018 Total current assets $ 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 Total consideration 250 Cash received (2) 711 Total consideration, net of cash received (2) $ (461 ) (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) Cash received represents cash and cash equivalents held by USAC as of the acquisition date.

Advances to and Investments i_2

Advances to and Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2019
Investment In Affiliates [Abstract]
Schedule Of Aggregated Selected Balance Sheet And Income Statement Data For Our Unconsolidated Affiliates	The carrying values of the Partnership’s investments advances to and in unconsolidated affiliates as of December 31, 2019 and 2018 were as follows: December 31, 2019 2018 Citrus $ 1,876 $ 1,737 FEP 218 107 MEP 429 225 Others 937 573 Total $ 3,460 $ 2,642 The following table presents equity in earnings (losses) of unconsolidated affiliates: Years Ended December 31, 2019 2018 2017 Citrus $ 148 $ 141 $ 144 FEP 59 55 53 MEP 15 31 38 Other 80 117 (91 ) Total equity in earnings of unconsolidated affiliates $ 302 $ 344 $ 144
Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block]	The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, and MEP (on a 100% basis) for all periods presented, except as noted below: December 31, 2019 2018 Current assets $ 247 $ 212 Property, plant and equipment, net 7,680 7,800 Other assets 40 39 Total assets $ 7,967 $ 8,051 Current liabilities $ 738 $ 1,534 Non-current liabilities 3,242 3,439 Equity 3,987 3,078 Total liabilities and equity $ 7,967 $ 8,051 Years Ended December 31, 2019 2018 (1) 2017 Revenue $ 1,192 $ 1,249 $ 1,358 Operating income 683 723 407 Net income 443 460 145 (1) Selected income data related to HPC for the year ended December 31, 2018 reflects HPC’s results for January 1, 2018 through March 31, 2018. HPC was fully consolidated beginning April 1, 2018 as discussed above.

Net Income Per Limited Partne_2

Net Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Reconciliation Of Net Income (Loss) And Weighted Average Units	A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows: Years Ended December 31, 2019 2018 2017 Income from continuing operations $ 4,899 $ 3,630 $ 2,543 Less: Net income attributable to redeemable noncontrolling interests 51 39 — Less: Income (loss) from continuing operations attributable to noncontrolling interests 1,256 1,888 1,583 Income from continuing operations, net of noncontrolling interests 3,592 1,703 960 Less: General Partner’s interest in income from continuing operations 4 3 2 Less: ET Series A Convertible Preferred Unitholders’ interest in net income from continuing operations — 33 38 Income from continuing operations available to Limited Partners $ 3,588 $ 1,667 $ 920 Basic Income from Continuing Operations per Limited Partner Unit: Weighted average limited partner units 2,628.0 1,423.8 1,078.2 Basic income from continuing operations per Limited Partner unit $ 1.37 $ 1.17 $ 0.86 Basic loss from discontinued operations per Limited Partner unit $ — $ (0.01 ) $ (0.01 ) Diluted Income from Continuing Operations per Limited Partner Unit: Income from continuing operations available to Limited Partners $ 3,588 $ 1,667 $ 920 Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units (1 ) 33 38 Diluted income from continuing operations available to Limited Partners 3,587 1,700 958 Weighted average limited partner units 2,628.0 1,423.8 1,078.2 Dilutive effect of unconverted unit awards and ET Series A Convertible Preferred Units — 30.3 72.6 Dilutive effect of unvested unit awards 9.6 7.3 — Weighted average limited partner units, assuming dilutive effect of unvested unit awards 2,637.6 1,461.4 1,150.8 Diluted income from continuing operations per Limited Partner unit $ 1.36 $ 1.16 $ 0.84 Diluted loss from discontinued operations per Limited Partner unit $ — $ (0.01 ) $ (0.01 )

Debt Obligations Debt Obligatio

Debt Obligations Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Obligations [Abstract]
Schedule of debt obligations	Our debt obligations consist of the following: December 31, 2019 2018 Parent Company Indebtedness: 7.50% Senior Notes due October 15, 2020 (1) $ 52 $ 1,187 4.25% Senior Notes due March 15, 2023 5 1,000 5.875% Senior Notes due January 15, 2024 23 1,150 5.50% Senior Notes due June 1, 2027 44 1,000 ET Senior Secured Term Loan — 1,220 Unamortized premiums, discounts and fair value adjustments, net — (10 ) Deferred debt issuance costs — (27 ) 124 5,520 Subsidiary Indebtedness: ETO Debt 9.70% Senior Notes due March 15, 2019 — 400 9.00% Senior Notes due April 15, 2019 — 450 5.50% Senior Notes due February 15, 2020 (1) 250 250 5.75% Senior Notes due September 1, 2020 (1) 400 400 4.15% Senior Notes due October 1, 2020 (1) 1,050 1,050 7.50% Senior Notes due October 15, 2020 (1) 1,135 — 4.40% Senior Notes due April 1, 2021 600 600 4.65% Senior Notes due June 1, 2021 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 — 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 — 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 — 9.00% Debentures due November 1, 2024 65 65 4.05% Senior Notes due March 15, 2025 1,000 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 — 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 — 8.25% Senior Notes due November 15, 2029 267 267 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 — Floating Rate Junior Subordinated Notes due November 1, 2066 546 546 ETO $2.00 billion Term Loan facility due October 2022 2,000 — ETO $5.00 billion Revolving Credit Facility due December 2023 4,214 3,694 Unamortized premiums, discounts and fair value adjustments, net (5 ) 17 Deferred debt issuance costs (207 ) (178 ) 42,120 32,288 Transwestern Debt 5.36% Senior Notes due December 9, 2020 (1) 175 175 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 ) (1 ) 574 574 Panhandle Debt 8.125% Senior Notes due June 1, 2019 — 150 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 11 14 246 399 Bakken Project Debt 3.625% Senior Notes due April 1, 2022 650 — 3.90% Senior Notes due April 1, 2024 1,000 — 4.625% Senior Notes due April 1, 2029 850 — Bakken $2.50 billion Credit Facility due August 2019 — 2,500 Unamortized premiums, discounts and fair value adjustments, net (3 ) — Deferred debt issuance costs (16 ) (3 ) 2,481 2,497 Sunoco LP Debt 4.875% Senior Notes Due January 15, 2023 1,000 1,000 5.50% Senior Notes Due February 15, 2026 800 800 6.00% Senior Notes Due April 15, 2027 600 — 5.875% Senior Notes Due March 15, 2028 400 400 Sunoco LP $1.50 billion Revolving Credit Facility due July 2023 162 700 Lease-related obligations 135 107 Deferred debt issuance costs (26 ) (23 ) 3,071 2,984 USAC Debt 6.875% Senior Notes due April 1, 2026 725 725 6.875% Senior Notes due September 1, 2027 750 — USAC $1.60 billion Revolving Credit Facility due April 2023 403 1,050 Deferred debt issuance costs (26 ) (16 ) 1,852 1,759 SemGroup Debt HFOTCO Tax Exempt Notes due 2050 225 — SemCAMS Revolver due February 25, 2024 92 — SemCAMS Term Loan A due February 25, 2024 269 — Unamortized premiums, discounts and fair value adjustments, net 1 — Deferred debt issuance costs (3 ) — 584 — Other 2 7 Total debt 51,054 46,028 Less: Current maturities of long-term debt 26 2,655 Long-term debt, less current maturities $ 51,028 $ 43,373
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 $279 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: 2020 $ 3,086 2021 1,412 2022 5,792 2023 8,965 2024 4,708 Thereafter 27,366 Total $ 51,329

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2019
Change In ETE Common Units	The change in ET Common Units during the years ended December 31, 2019 , 2018 and 2017 was as follows: Years Ended December 31, 2019 2018 2017 Number of Common Units, beginning of period 2,619.4 1,079.1 1,046.9 Conversion of ET Series A Convertible Preferred Units to common units — 79.1 — Common Units issued in mergers and acquisitions 57.6 1,458.9 — Common Units repurchased (1.9 ) — — Issuance of Common Units 14.5 2.3 32.2 Number of Common Units, end of period 2,689.6 2,619.4 1,079.1 In October 2018, ET issued 1.46 billion ET Common Units in connection with the Energy Transfer Merger.
Accumulated Other Comprehensive Income (Loss)	The following table presents the components of AOCI, net of tax: December 31, 2019 2018 Available-for-sale securities $ 13 $ 2 Foreign currency translation adjustment 2 (5 ) Actuarial loss related to pensions and other postretirement benefits (25 ) (48 ) Investments in unconsolidated affiliates, net (1 ) 9 Total AOCI, net of tax $ (11 ) $ (42 )
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The table below sets forth the tax amounts included in the respective components of other comprehensive income: December 31, 2019 2018 Available-for-sale securities $ (1 ) $ (1 ) Foreign currency translation adjustment 2 2 Actuarial loss relating to pension and other postretirement benefits 8 12 Total $ 9 $ 13
Parent Company [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Our distributions declared and paid with respect to our common units were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2016 (1) February 7, 2017 February 21, 2017 $ 0.2850 March 31, 2017 (1) May 10, 2017 May 19, 2017 0.2850 June 30, 2017 (1) August 7, 2017 August 21, 2017 0.2850 September 30, 2017 (1) November 7, 2017 November 20, 2017 0.2950 December 31, 2017 (1) February 8, 2018 February 20, 2018 0.3050 March 31, 2018 May 7, 2018 May 21, 2018 0.3050 June 30, 2018 August 6, 2018 August 20, 2018 0.3050 September 30, 2018 November 8, 2018 November 19, 2018 0.3050 December 31, 2018 February 8, 2019 February 19, 2019 0.3050 March 31, 2019 May 7, 2019 May 20, 2019 0.3050 June 30, 2019 August 6, 2019 August 19, 2019 0.3050 September 30, 2019 November 5, 2019 November 19, 2019 0.3050 December 31, 2019 February 7, 2020 February 19, 2020 0.3050
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, 2016 February 13, 2017 February 21, 2017 $ 0.8255 March 31, 2017 May 9, 2017 May 16, 2017 0.8255 June 30, 2017 August 7, 2017 August 15, 2017 0.8255 September 30, 2017 November 7, 2017 November 14, 2017 0.8255 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
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%
USAC [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	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, 2019 , USAC had approximately 96.6 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 09, 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
Preferred Units [Member] | Parent Company [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Our distributions declared and paid with respect to ET Series A Convertible Preferred Unit were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2016 February 7, 2017 February 21, 2017 $ 0.1100 March 31, 2017 May 10, 2017 May 19, 2017 0.1100 June 30, 2017 August 7, 2017 August 21, 2017 0.1100 September 30, 2017 November 7, 2017 November 20, 2017 0.1100 December 31, 2017 February 8, 2018 February 20, 2018 0.1100 March 31, 2018 May 7, 2018 May 21, 2018 0.1100
Preferred Units [Member] | ETO [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Period Ended Record Date Payment Date Series A (1) Series B (1) Series C Series D Series E December 31, 2017 February 1, 2018 February 15, 2018 $ 15.4510 * $ 16.3780 * $ — $ — $ — 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 * Represent prorated initial distributions. Prorated initial distributions on the recently issued ETO Series F Preferred Units and ETO Series G Preferred Units will be payable in May 2020. (1) ETO Series A Preferred Units and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.

Non-Cash Compensation Plans Uni

Non-Cash Compensation Plans Unit-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Schedule Of ETP Awards Granted To Employees And Non-Employee Directos	The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2018 22.4 $ 15.94 Replacement awards issued in the SemGroup Transaction 1.4 11.60 Awards granted 8.9 12.51 Awards vested (4.0 ) 21.09 Awards forfeited (0.7 ) 15.70 Unvested awards as of December 31, 2019 28.0 13.89
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, 2019 2018 2017 Sunoco LP $ 30.70 $ 27.67 $ 28.31 USAC 15.88 15.47 N/A
Subsidiaries [Member]
Schedule Of ETP Awards Granted To Employees And Non-Employee Directos	The following table summarizes the activity of the Subsidiary Unit Awards: Sunoco LP USAC Number of Units Weighted Average Grant-Date Fair Value Per Unit Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2018 2.1 $ 29.15 1.4 $ 14.98 Awards granted 0.7 30.70 0.7 15.88 Awards vested (0.5 ) 30.04 (0.3 ) 13.06 Awards forfeited (0.2 ) 28.16 — 16.78 Unvested awards as of December 31, 2019 2.1 29.21 1.8 15.09

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Federal and State Income Taxes [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows: Years Ended December 31, 2019 2018 2017 Current expense (benefit): Federal $ (20 ) $ (8 ) $ 54 State (2 ) 19 (16 ) Total (22 ) 11 38 Deferred expense (benefit): Federal 174 181 (2,055 ) State 43 (188 ) 184 Total 217 (7 ) (1,871 ) Total income tax expense (benefit) from continuing operations $ 195 $ 4 $ (1,833 )
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, 2019 , 2018 and 2017 is as follows: Years Ended December 31, 2019 2018 2017 Income tax expense at United States statutory rate $ 1,070 $ 763 $ 248 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax (882 ) (635 ) (477 ) Goodwill impairment — — 207 State tax, net of federal tax benefit 12 (125 ) 124 Dividend received deduction (3 ) (5 ) (14 ) Federal rate change — — (1,812 ) Change in tax status of subsidiary — — (124 ) Other (2 ) 6 15 Income tax expense (benefit) from continuing operations $ 195 $ 4 $ (1,833 )
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, 2019 2018 Deferred income tax assets: Net operating losses, alternative minimum tax credit and other carryforwards $ 936 $ 768 Pension and other postretirement benefits 7 34 Long-term debt — 13 Other 85 181 Total deferred income tax assets 1,028 996 Valuation allowance (95 ) (96 ) Net deferred income tax assets 933 900 Deferred income tax liabilities: Property, plant and equipment (501 ) (782 ) Investments in affiliates (3,547 ) (2,872 ) Trademarks (72 ) (63 ) Other (21 ) (109 ) Total deferred income tax liabilities (4,141 ) (3,826 ) Net deferred income taxes $ (3,208 ) $ (2,926 )
ScheduleOfUnrecognizedTaxBenefits [Table Text Block]	Years Ended December 31, 2019 2018 2017 Balance at beginning of year $ 624 $ 609 $ 615 Additions attributable to tax positions taken in the current year — 8 — Additions attributable to tax positions taken in prior years 11 7 28 Reduction attributable to tax positions taken in prior years (541 ) — (25 ) Lapse of statute — — (9 ) Balance at end of year $ 94 $ 624 $ 609

Regulatory Matters, Commitmen_2

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Environmental Exit Costs by Cost [Table Text Block]	The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements. December 31, 2019 2018 Current $ 46 $ 42 Non-current 274 295 Total environmental liabilities $ 320 $ 337
Right Of Way [Member]
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, 2019 2018 2017 ROW expense $ 45 $ 46 $ 46

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2019
Contract with Customer, Asset and Liability [Table Text Block]	The following table summarizes the consolidated activity of our contract liabilities: Contract Liabilities Balance, January 1, 2018 $ 221 Additions 765 Revenue recognized (592 ) Balance, December 31, 2018 394 Additions 664 Revenue recognized (681 ) Balance, December 31, 2019 $ 377
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]	As of December 31, 2019 , the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $43.59 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below: Years Ending December 31, 2020 2021 2022 Thereafter Total Revenue expected to be recognized on contracts with customers existing as of December 31, 2019 $ 6,232 $ 5,300 $ 4,899 $ 27,158 $ 43,589
Sunoco LP [Member]
Contract with Customer, Asset and Liability [Table Text Block]	The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2019 and 2018 were as follows: December 31, 2019 December 31, 2018 Contract Balances Contract asset $ 117 $ 75 Accounts receivable from contracts with customers 366 347 Contract liability — 1

Lease Accounting (Tables)

Lease Accounting (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lessor, Operating Lease, Payments to be Received, Maturity [Table Text Block]	Future minimum operating lease payments receivable as of December 31, 2019 are as follows: Lease Payments 2020 $ 138 2021 112 2022 75 2023 20 2024 15 Thereafter 12 Total undiscounted cash flows $ 372
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, 2019 were as follows: December 31, 2019 Operating leases: Lease right-of-use assets, net $ 935 Operating lease current liabilities 60 Accrued and other current liabilities 1 Non-current operating lease liabilities 901 Finance leases: Property, plant and equipment, net $ 1 Lease right-of-use assets, net 29 Accrued and other current liabilities 1 Current maturities of long-term debt 6 Long-term debt, less current maturities 26 Other non-current liabilities 2
Lease, Cost [Table Text Block]	The components of lease expense for the year ended December 31, 2019 were as follows: Income Statement Location Year Ended December 31, 2019 Operating lease costs: Operating lease cost Cost of goods sold $ 28 Operating lease cost Operating expenses 73 Operating lease cost Selling, general and administrative 16 Total operating lease costs 117 Finance lease costs: Amortization of lease assets Depreciation, depletion and amortization 6 Interest on lease liabilities Interest expense, net of capitalized interest 1 Total finance lease costs 7 Short-term lease cost Operating expenses 42 Variable lease cost Operating expenses 17 Lease costs, gross 183 Less: Sublease income Other revenue 47 Lease costs, net $ 136
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Maturities of lease liabilities as of December 31, 2019 are as follows: Operating leases Finance leases Total 2020 $ 104 $ 8 $ 112 2021 96 8 104 2022 83 8 91 2023 77 7 84 2024 74 4 78 Thereafter 1,342 5 1,347 Total lease payments 1,776 40 1,816 Less: present value discount 815 5 820 Present value of lease liabilities $ 961 $ 35 $ 996 The weighted average remaining lease terms and weighted average discount rates as of December 31, 2019 were as follows: December 31, 2019 Weighted-average remaining lease term (years): Operating leases 24 Finance leases 5 Weighted-average discount rate (%): Operating leases 5 % Finance leases 5 %
Schedule of additional lease information [Table Text Block]	Cash flows and non-cash activity related to leases for the year ended December 31, 2019 were as follows: Year Ended December 31, 2019 Operating cash flows from operating leases $ (159 ) Lease assets obtained in exchange for new finance lease liabilities 28 Lease assets obtained in exchange for new operating lease liabilities 40

Derivative Assets And Liabili_2

Derivative Assets And Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Offsetting Assets [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, 2019 December 31, 2018 December 31, 2019 December 31, 2018 Derivatives without offsetting agreements Derivative liabilities $ — $ — $ (399 ) $ (163 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 41 158 (39 ) (173 ) Broker cleared derivative contracts Other current assets (liabilities) 343 402 (350 ) (410 ) 384 560 (788 ) (746 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (18 ) (47 ) 18 47 Counterparty netting Other current assets (liabilities) (318 ) (397 ) 318 397 Total net derivatives $ 48 $ 116 $ (452 ) $ (302 )
Outstanding Commodity-Related Derivatives	The following table details our outstanding commodity-related derivatives: December 31, 2019 December 31, 2018 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (BBtu): Fixed Swaps/Futures 1,483 2020 468 2019 Basis Swaps IFERC/NYMEX (1) (35,208 ) 2020-2024 16,845 2019-2020 Options – Puts — — 10,000 2019 Power (Megawatt): Forwards 3,213,450 2020-2029 3,141,520 2019 Futures (353,527 ) 2020 56,656 2019-2021 Options – Puts 51,615 2020 18,400 2019 Options – Calls (2,704,330 ) 2020-2021 284,800 2019 (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (18,923 ) 2020-2022 (30,228 ) 2019-2021 Swing Swaps IFERC (9,265 ) 2020 54,158 2019-2020 Fixed Swaps/Futures (3,085 ) 2020-2021 (1,068 ) 2019-2021 Forward Physical Contracts (13,364 ) 2020-2021 (123,254 ) 2019-2020 NGL (MBbls) – Forwards/Swaps (1,300 ) 2020-2021 (2,135 ) 2019 Crude (MBbls) – Forwards/Swaps 4,465 2020 20,888 2019 Refined Products (MBbls) – Futures (2,473 ) 2020-2021 (1,403 ) 2019 Corn (thousand bushels) (1,210 ) 2020 (1,920 ) 2019 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (31,780 ) 2020 (17,445 ) 2019 Fixed Swaps/Futures (31,780 ) 2020 (17,445 ) 2019 Hedged Item – Inventory 31,780 2020 17,445 2019 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Interest Rate Swaps Outstanding	The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes: Term Type (1) Notional Amount Outstanding December 31, 2019 December 31, 2018 March 2019 Pay a floating rate and receive a fixed rate of 1.42% $ — $ 300 July 2019 (2) Forward-starting to pay a fixed rate of 3.56% and receive a floating rate — 400 July 2020 (2)(3) Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400 400 July 2021 (2) Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400 400 July 2022 (2) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 400 — (1) Floating rates are based on 3-month LIBOR.
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, 2019 December 31, 2018 December 31, 2019 December 31, 2018 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 24 $ — $ — $ (13 ) 24 — — (13 ) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 319 402 (350 ) (397 ) Commodity derivatives 41 158 (39 ) (173 ) Interest rate derivatives — — (399 ) (163 ) 360 560 (788 ) (733 ) Total derivatives $ 384 $ 560 $ (788 ) $ (746 )
Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized	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, 2019 2018 2017 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ — $ (3 ) $ 26
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, 2019 2018 2017 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Revenues $ (3 ) $ — $ — Commodity derivatives – Trading Cost of products sold 21 32 31 Commodity derivatives – Non-trading Cost of products sold (78 ) (102 ) 5 Interest rate derivatives Gains (losses) on interest rate derivatives (241 ) 47 (37 ) Embedded derivatives Other, net — — 1 Total $ (301 ) $ (23 ) $ —

Retirement Benefits Retirement

Retirement Benefits Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	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, 2019 December 31, 2018 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 $ 1 $ 37 $ 198 $ 1 $ 47 $ 156 Service cost — — 1 — — 1 Interest cost 2 1 7 — 1 5 Amendments — — — — — 60 Benefits paid, net (1 ) (7 ) (16 ) — (7 ) (17 ) Actuarial (gain) loss and other 4 — 18 — (4 ) (7 ) Settlements (4 ) — — — — — SemGroup Acquisition 50 3 — — — — Benefit obligation at end of period 52 34 208 1 37 198 Change in plan assets: Fair value of plan assets at beginning of period 1 — 241 1 — 257 Return on plan assets and other 6 — 35 — — (8 ) Employer contributions 1 — 10 — — 9 Benefits paid, net (1 ) — (16 ) — — (17 ) Settlements (4 ) — — — — — SemGroup Acquisition 40 — — — — — Fair value of plan assets at end of period 43 — 270 1 — 241 Amount underfunded (overfunded) at end of period $ 9 $ 34 $ (62 ) $ — $ 37 $ (43 ) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 88 $ — $ — $ 68 Current liabilities — (5 ) (2 ) — (6 ) (2 ) Non-current liabilities (9 ) (29 ) (24 ) — (31 ) (23 ) $ (9 ) $ (34 ) $ 62 $ — $ (37 ) $ 43 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain (loss) $ — $ 1 $ (5 ) $ — $ 1 $ (7 ) Prior service cost — — 40 — — 66 $ — $ 1 $ 35 $ — $ 1 $ 59
Defined Benefit Plan, Plan with Projected Benefit Obligation in Excess of Plan Assets [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, 2019 December 31, 2018 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 51 $ 34 N/A $ — $ 37 N/A Accumulated benefit obligation 52 34 208 1 37 198 Fair value of plan assets 43 — 270 1 — 241
Schedule of Health Care Cost Trend Rates [Table Text Block]	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, 2019 2018 Health care cost trend rate 7.25 % 7.15 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.83 % 4.82 % Year that the rate reaches the ultimate trend rate 2026 2024
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, 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 . Fair Value Measurements at December 31, 2018 Fair Value Total Level 1 Level 2 Level 3 Mutual funds (1) $ 1 $ 1 $ — $ — (1) Comprised of approximately 100% equities as of December 31, 2018 . The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: 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 . Fair Value Measurements at December 31, 2018 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 20 $ 20 $ — $ — Mutual funds (1) 144 144 — — Fixed income securities 77 — 77 — Total $ 241 $ 164 $ 77 $ — (1) Primarily comprised of approximately 53% equities, 46% fixed income securities and 1% cash as of December 31, 2018 . 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.
Schedule of Expected Benefit Payments [Table Text Block]	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 - Unfunded Plans (1) Other Postretirement Benefits (Gross, Before Medicare Part D) 2020 $ 7 $ 20 2021 8 20 2022 8 19 2023 8 18 2024 7 15 2025 – 2029 22 67 (1) Expected benefit payments of funded pension plans are less than $1 million for the next ten years.
Schedule of Net Benefit Costs [Table Text Block]	Components of Net Periodic Benefit Cost December 31, 2019 December 31, 2018 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Service cost $ — $ 1 $ — $ 1 Interest cost 3 7 1 5 Expected return on plan assets (2 ) (10 ) — (10 ) Prior service cost amortization — 26 — 16 Net periodic benefit cost $ 1 $ 24 $ 1 $ 12
Defined Benefit Plan, 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, 2019 December 31, 2018 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 4.00 % 2.71 % 4.02 % 3.40 % Rate of compensation increase — — N/A N/A The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2019 December 31, 2018 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 3.33 % 3.76 % 3.52 % 3.51 % Expected return on assets: Tax exempt accounts 3.37 % 7.00 % 3.26 % 6.63 % Taxable accounts — 4.75 % N/A 4.50 % Rate of compensation increase — — N/A N/A

Related Party Transactions Rela

Related Party Transactions Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Schedule of Related Party Transactions [Table Text Block]	The following table summarizes the revenues from related companies on our consolidated statements of operations: Years Ended December 31, 2019 2018 2017 Affiliated revenues $ 492 $ 431 $ 303 The following table summarizes the related company accounts receivable and accounts payable balances on our consolidated balance sheets: December 31, 2019 2018 Accounts receivable from related companies: FGT $ 50 $ 25 Phillips 66 36 42 Traverse Rover LLC 42 — Other 31 44 Total accounts receivable from related companies $ 159 $ 111 As of December 31, 2019 and 2018 , accounts payable with related companies in the Partnership’s consolidated balance sheets totaled $31 million and $59 million , respectively.

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2019
Financial Information By Segment	The following tables present financial information by segment: Years Ended December 31, 2019 2018 2017 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,749 $ 3,428 $ 2,891 Intersegment revenues 350 309 192 3,099 3,737 3,083 Interstate transportation and storage: Revenues from external customers 1,941 1,664 1,112 Intersegment revenues 22 18 19 1,963 1,682 1,131 Midstream: Revenues from external customers 2,280 2,090 2,510 Intersegment revenues 3,751 5,432 4,433 6,031 7,522 6,943 NGL and refined products transportation and services: Revenues from external customers 9,920 10,119 7,885 Intersegment revenues 1,721 1,004 763 11,641 11,123 8,648 Crude oil transportation and services: Revenues from external customers 18,447 17,236 11,672 Intersegment revenues — 96 31 18,447 17,332 11,703 Investment in Sunoco LP: Revenues from external customers 16,590 16,982 11,713 Intersegment revenues 6 12 10 16,596 16,994 11,723 Investment in USAC: Revenues from external customers 678 495 — Intersegment revenues 20 13 — 698 508 — All other: Revenues from external customers 1,608 2,073 2,740 Intersegment revenues 81 155 161 1,689 2,228 2,901 Eliminations (5,951 ) (7,039 ) (5,609 ) Total revenues $ 54,213 $ 54,087 $ 40,523 Years Ended December 31, 2019 2018 2017 Cost of products sold: Intrastate transportation and storage $ 1,909 $ 2,665 $ 2,327 Midstream 3,577 5,145 4,761 NGL and refined products transportation and services 8,393 8,462 6,508 Crude oil transportation and services 14,758 14,439 9,826 Investment in Sunoco LP 15,380 15,872 10,615 Investment in USAC 91 67 — All other 1,504 2,006 2,509 Eliminations (5,885 ) (6,998 ) (5,580 ) Total cost of products sold $ 39,727 $ 41,658 $ 30,966 Years Ended December 31, 2019 2018 2017 Depreciation, depletion and amortization: Intrastate transportation and storage $ 184 $ 169 $ 147 Interstate transportation and storage 387 334 254 Midstream 1,066 1,006 954 NGL and refined products transportation and services 613 466 401 Crude oil transportation and services 437 445 402 Investment in Sunoco LP 181 167 169 Investment in USAC 231 169 — All other 48 103 227 Total depreciation, depletion and amortization $ 3,147 $ 2,859 $ 2,554 Years Ended December 31, 2019 2018 2017 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 18 $ 19 $ (156 ) Interstate transportation and storage 222 227 236 Midstream 20 26 20 NGL and refined products transportation and services 53 64 33 Crude oil transportation and services (1 ) 6 4 All other (10 ) 2 7 Total equity in earnings of unconsolidated affiliates $ 302 $ 344 $ 144 Years Ended December 31, 2019 2018 2017 Segment Adjusted EBITDA: Intrastate transportation and storage $ 999 $ 927 $ 626 Interstate transportation and storage 1,792 1,680 1,274 Midstream 1,602 1,627 1,481 NGL and refined products transportation and services 2,666 1,979 1,641 Crude oil transportation and services 2,972 2,330 1,379 Investment in Sunoco LP 665 638 732 Investment in USAC 420 289 — All Other 98 40 187 Total Segment Adjusted EBITDA 11,214 9,510 7,320 Depreciation, depletion and amortization (3,147 ) (2,859 ) (2,554 ) Interest expense, net of interest capitalized (2,331 ) (2,055 ) (1,922 ) Impairment losses (74 ) (431 ) (1,039 ) Gains (losses) on interest rate derivatives (241 ) 47 (37 ) Non-cash compensation expense (113 ) (105 ) (99 ) Unrealized gains (losses) on commodity risk management activities (5 ) (11 ) 59 Inventory valuation adjustments 79 (85 ) 24 Losses on extinguishments of debt (18 ) (112 ) (89 ) Adjusted EBITDA related to unconsolidated affiliates (626 ) (655 ) (716 ) Equity in earnings of unconsolidated affiliates 302 344 144 Impairment of investments in unconsolidated affiliates — — (313 ) Adjusted EBITDA related to discontinued operations — 25 (223 ) Other, net 54 21 155 Income from continuing operations before income tax (expense) benefit 5,094 3,634 710 Income tax (expense) benefit from continuing operations (195 ) (4 ) 1,833 Income from continuing operations 4,899 3,630 2,543 Loss from discontinued operations, net of income taxes — (265 ) (177 ) Net income $ 4,899 $ 3,365 $ 2,366 December 31, 2019 2018 2017 Segment assets: Intrastate transportation and storage $ 6,648 $ 6,365 $ 5,020 Interstate transportation and storage 18,111 15,081 15,316 Midstream 20,332 19,745 20,004 NGL and refined products transportation and services 19,145 18,267 17,600 Crude oil transportation and services 22,840 18,022 17,730 Investment in Sunoco LP 5,438 4,879 8,344 Investment in USAC 3,730 3,775 — All other and eliminations 2,636 2,112 2,232 Total segment assets $ 98,880 $ 88,246 $ 86,246 Years Ended December 31, 2019 2018 2017 Additions to property, plant and equipment (1) : Intrastate transportation and storage $ 124 $ 344 $ 175 Interstate transportation and storage 375 812 728 Midstream 827 1,161 1,308 NGL and refined products transportation and services 2,976 2,381 2,971 Crude oil transportation and services 403 474 453 Investment in Sunoco LP 148 103 103 Investment in USAC 200 205 — All other 215 150 268 Total additions to property, plant and equipment (1) $ 5,268 $ 5,630 $ 6,006 (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, 2019 2018 2017 Advances to and investments in affiliates: Intrastate transportation and storage $ 88 $ 83 $ 85 Interstate transportation and storage 2,524 2,070 2,118 Midstream 112 124 126 NGL and refined products transportation and services 461 243 234 Crude oil transportation and services 242 28 22 All other 33 94 120 Total advances to and investments in affiliates $ 3,460 $ 2,642 $ 2,705

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	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 1,927 1,819 1,830 1,701 7,277 Net income 1,180 1,208 1,161 1,350 4,899 Limited Partners’ interest in net income 869 877 831 1,011 3,588 Income from continuing operations per limited partner unit: Basic $ 0.33 $ 0.33 $ 0.32 $ 0.38 $ 1.37 Diluted $ 0.33 $ 0.33 $ 0.32 $ 0.38 $ 1.36 Net income per limited partner unit: Basic $ 0.33 $ 0.33 $ 0.32 $ 0.38 $ 1.37 Diluted $ 0.33 $ 0.33 $ 0.32 $ 0.38 $ 1.36 Quarters Ended March 31 June 30 September 30 December 31 Total Year 2018: Revenues $ 11,882 $ 14,118 $ 14,514 $ 13,573 $ 54,087 Operating income 1,100 1,126 1,703 1,419 5,348 Income from continuing operations 726 659 1,393 852 3,630 Net income 489 633 1,391 852 3,365 Limited Partners’ interest in net income 341 330 370 617 1,658 Income from continuing operations per limited partner unit: Basic $ 0.32 $ 0.30 $ 0.32 $ 0.26 $ 1.17 Diluted $ 0.32 $ 0.30 $ 0.32 $ 0.26 $ 1.16 Net income per limited partner unit: Basic $ 0.31 $ 0.30 $ 0.32 $ 0.26 $ 1.16 Diluted $ 0.31 $ 0.30 $ 0.32 $ 0.26 $ 1.15

Operations And Organization (Na

Operations And Organization (Narrative) (Details)	1 Months Ended	3 Months Ended	12 Months Ended
	Oct. 31, 2018shares	Dec. 31, 2018shares	Dec. 31, 2019shares	Jul. 30, 2019shares
Limited Partner interest in the Partnership, percentage			99.90%
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
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest			100.00%
ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction	1,460,000,000
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.28
ETE Merger [Member] | Sunoco LP [Member]
Sale of Stock, Number of Shares Issued in Transaction	2,263,158	2,263,158
ETE Merger [Member] | Sunoco GP [Member]
Limited Partner interest in the Partnership, percentage	100.00%	100.00%
ETE Merger [Member] | USAC [Member]
Sale of Stock, Number of Shares Issued in Transaction	12,466,912	12,466,912
Limited Partner interest in the Partnership, percentage	100.00%	100.00%
ETE Merger [Member] | Lake Charles LNG [Member]
Limited Partner interest in the Partnership, percentage	100.00%	100.00%
ETE Merger [Member] | Energy Transfer LNG Export LLC, ET Crude Oil Terminals LLC, & ETC Illinois LLC [Member]
Limited Partner interest in the Partnership, percentage	60.00%	60.00%
IDRs [Member] | ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction	1,168,205,710
General Partner [Member] | ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction	18,448,341
ETO [Member] | ETE Merger [Member] | Sunoco LP [Member]
Sale of Stock, Number of Shares Issued in Transaction	2,874,275	2,874,275
ETO [Member] | ETE Merger [Member] | Sunoco GP [Member]
Sale of Stock, Number of Shares Issued in Transaction	42,812,389	42,812,389
ETO [Member] | ETE Merger [Member] | USAC [Member]
Sale of Stock, Number of Shares Issued in Transaction	16,134,903	16,134,903
ETO [Member] | ETE Merger [Member] | Lake Charles LNG [Member]
Sale of Stock, Number of Shares Issued in Transaction	37,557,815	37,557,815

Estimates, Significant Accoun_4

Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Impairment losses				$ 74	$ 431	$ 1,039
Operating Lease, Liability				961
Operating Lease, Right-of-Use Asset		$ 0		1,000	0		$ 889
Asset Retirement Obligation		193		247	193
Costs Incurred, Asset Retirement Obligation Incurred				5	13	9
Tangible Asset Impairment Charges				9	127
Asset Retirement Obligation, Legally Restricted Assets, Fair Value		26		31	26
Long-term Debt, Fair Value		45,060		54,790	45,060
Impairment losses	$ (12)	(9)		(21)	(378)
Goodwill acquired				307	495
Goodwill		4,885	$ 4,768	5,167	4,885	4,768
Long-term Debt		46,028		51,054	46,028
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net				0
Midstream [Member]
Impairment losses		378		(9)	(378)
Goodwill acquired				0	0
Goodwill		492	870	483	492	870
Other Segments [Member]
Impairment losses			(452)	0	0
Goodwill acquired				35	0
Goodwill		149	402	184	149	402
Investment In Sunoco LP [Member]
Impairment losses			(387)	0	0
Goodwill acquired				0	129
Goodwill		1,559	1,430	1,555	1,559	1,430
Retail Marketing [Member]
Excise Taxes Collected				386	370	$ 234
Sunoco LP [Member]
Impairment losses				47
Inventory Write-down					85
Long-term Debt		2,984		3,071	$ 2,984
USAC [Member]
Impairment losses				6
SemGroup [Member]
Goodwill acquired				265
Fair value exceeding carrying value by less than 20% [Member]
Goodwill				380
Customer relationships, contracts and agreements (3 to 46 years)
Impairment of Intangible Assets (Excluding Goodwill)		$ 30		$ 17
Continuing Operations [Member] | Investment In Sunoco LP [Member]
Impairment losses			$ (102)

Estimates, Significant Accoun_5

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Accounting Change) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Other current assets	$ 275	$ 350
Increase (Decrease) in Operating Capital	(518)	289	$ (192)
Inventories	1,935	1,677
Noncontrolling interests	12,018	10,291
Property, Plant and Equipment, Net	74,193	66,963		$ 66,962
Intangible assets, net	6,154	6,000
Other non-current assets, net	1,075	1,006
Other non-current liabilities	1,162	1,184		1,172
Cost of Goods and Services Sold	39,727	41,658	30,966
Operating expenses	3,294	3,089	2,644
Depreciation, depletion and amortization	3,147	2,859	2,554
Operating Lease, Right-of-Use Asset	1,000	0		889
Operating Lease, Liability, Current	60	0		71
Accrued and other current liabilities	3,342	2,918		2,917
Current maturities of long-term debt	26	2,655		2,656
Long-term debt, less current maturities	51,028	43,373		43,379
Operating Lease, Liability, Noncurrent	901	0		823
Natural gas sales
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	3,295	4,452	4,172
NGL sales
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	8,290	9,986	7,781
Crude sales
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	15,917	14,425	10,706
Gathering, transportation and other fees
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	9,086	6,797	4,435
Refined product sales
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	16,752	17,458	11,166
Other
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 873	$ 969	$ 2,263
Accounting Standards Update 2016-02 [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Property, Plant and Equipment, Net				(1)
Other non-current liabilities				(12)
Operating Lease, Right-of-Use Asset				889
Operating Lease, Liability, Current				71
Accrued and other current liabilities				(1)
Current maturities of long-term debt				1
Long-term debt, less current maturities				6
Operating Lease, Liability, Noncurrent				$ 823

Estimates (Schedule Of Net Chan

Estimates (Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Accounts receivable	$ (473)	$ 541	$ (948)
Accounts receivable from related companies	(69)	162	24
Inventories	(117)	282	58
Other current assets	(117)	(7)	(38)
Other non-current assets, net	(78)	(92)	84
Accounts payable	146	(766)	712
Accounts payable to related companies	(32)	(202)	(178)
Accrued and other current liabilities	(44)	382	(97)
Other non-current liabilities	(186)	28	106
Derivative assets and liabilities, net	218	(53)	9
Net change in operating assets and liabilities, net of effects of acquisitions	$ (518)	$ 289	$ (192)

Estimates (Schedule Of Non-Cash

Estimates (Schedule Of Non-Cash Investing And Financing Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 1,334	$ 1,030	$ 1,060
Right-of-Use Assets Obtained in Exchange for Liabilities	68	0	0
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	28
Contribution of assets from noncontrolling interests	0	0	988
Net losses from subsidiary common unit transactions	0	(126)	(56)
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	1,932	1,870	1,914
Cash paid for income taxes	$ 31	$ 508	$ 50

Estimates (Schedule of Inventor

Estimates (Schedule of Inventory) (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Inventory, Net [Abstract]
Natural gas, NGLs and refined products (1)	[1]	$ 833	$ 833
Crude oil		654	506
Spare parts and other		448	338
Total inventories		$ 1,935	$ 1,677
[1]	Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of $85 million as of December 31, 2018.

Estimates (Other Current Assets

Estimates (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Other Information [Abstract]
Deposits paid to vendors	$ 95	$ 141
Prepaid expenses and other	180	209
Total other current assets	$ 275	$ 350

Estimates (Property, Plant and

Estimates (Property, Plant and Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 89,790		$ 79,776
Less - Accumulated depreciation	(15,597)		(12,813)
Property, Plant and Equipment, Net	74,193	$ 66,962	66,963
Land and Land Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,264		1,168
Building and Building Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	2,632		2,664
Pipelines [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	64,678		58,783
Natural gas and NGL storage facilities (5 to 46 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	5,898		4,978
Right Of Way [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	4,859		4,533
Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,964		1,583
Construction Work-In-Process [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 8,495		$ 6,067

Estimates (Schedule Of Property

Estimates (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization expense	$ 2,839	$ 2,538	$ 2,204
Capitalized interest	$ 166	$ 294	$ 286

Estimates (Schedule of Other No

Estimates (Schedule of Other Non-Current Assets, net) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Regulatory assets	$ 42	$ 43
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Plan Assets	84	68
Deferred charges	178	173
Restricted funds	178	178
Other	593	544
Total other non-current assets, net	$ 1,075	$ 1,006

Estimates (Components Of Intang

Estimates (Components Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Gross Carrying Amount	$ 7,975	$ 7,560
Accumulated Amortization	(1,821)	(1,560)
Customer relationships, contracts and agreements (3 to 46 years)
Gross Carrying Amount	7,535	7,106
Accumulated Amortization	(1,743)	(1,493)
Patents (10 years)
Gross Carrying Amount	48	48
Accumulated Amortization	(35)	(30)
Trade names (20 years)
Gross Carrying Amount	66	66
Accumulated Amortization	(31)	(28)
Total Amortizable Intangible Assets [Member]
Gross Carrying Amount	7,668	7,253
Accumulated Amortization	(1,821)	(1,560)
Trademarks [Member]
Gross Carrying Amount	295	295
Accumulated Amortization	0	0
Other non-amortizable intangible assets [Member]
Gross Carrying Amount	12	12
Accumulated Amortization	0	0
Other Amortizable Intangible Assets [Member]
Gross Carrying Amount	19	33
Accumulated Amortization	(12)	(9)
Non-amortizable intangible assets [Member]
Gross Carrying Amount	307	307
Accumulated Amortization	$ 0	$ 0

Estimates, Significant Accoun_6

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Useful Lives) (Details) (Details)	12 Months Ended
	Dec. 31, 2019
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Intangible assets, useful life, minimum (years)	3 years
Minimum [Member] | Other (5 to 20 years)
Intangible assets, useful life, minimum (years)	5 years
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Intangible assets, useful life, minimum (years)	46 years
Maximum [Member] | Patents (10 years)
Intangible assets, useful life, minimum (years)	20 years
Maximum [Member] | Trade names (20 years)
Intangible assets, useful life, minimum (years)	10 years
Maximum [Member] | Other (5 to 20 years)
Intangible assets, useful life, minimum (years)	20 years
Buildings and improvements [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Buildings and improvements [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	45 years
Pipelines And Equipment [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	5 years
Pipelines And Equipment [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Natural gas and NGL storage facilities (5 to 46 years) | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	2 years
Natural gas and NGL storage facilities (5 to 46 years) | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Right Of Way [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	20 years
Right Of Way [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Property, Plant and Equipment, Other Types [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Property, Plant and Equipment, Other Types [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	48 years

Estimates (Aggregate Amortizati

Estimates (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Depreciation And Amortization [Member]
Reported in depreciation and amortization	$ 308	$ 321	$ 344

Estimates (Estimated Aggregate

Estimates (Estimated Aggregate Amortization Expense) (Details) $ in Millions	Dec. 31, 2019USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2019	$ 394
2020	390
2021	360
2022	320
2023	$ 307

Estimates (Schedule Of Goodwill

Estimates (Schedule Of Goodwill) (Details) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Goodwill [Roll Forward]
Goodwill				$ 4,885	$ 4,768
Goodwill acquired				307	495
Goodwill, Transfers					0
Goodwill		$ 4,885	$ 4,768	5,167	4,885
Goodwill impairment	$ (12)	(9)		(21)	(378)
Goodwill, Other Changes				(4)	0
Intrastate Transportation And Storage [Member]
Goodwill [Roll Forward]
Goodwill				10	10
Goodwill acquired				0	0
Goodwill, Transfers					0
Goodwill		10	10	10	10
Goodwill impairment				0	0
Goodwill, Other Changes				0	0
Interstate Transportation and Storage [Member]
Goodwill [Roll Forward]
Goodwill				196	196
Goodwill acquired				42	0
Goodwill, Transfers					0
Goodwill		196	196	226	196
Goodwill impairment			(262)	(12)	0
Goodwill, Other Changes				0	0
Midstream [Member]
Goodwill [Roll Forward]
Goodwill				492	870
Goodwill acquired				0	0
Goodwill, Transfers					0
Goodwill		492	870	483	492
Goodwill impairment		378		(9)	(378)
Goodwill, Other Changes				0	0
NGL and refined products transportation and services [Member]
Goodwill [Roll Forward]
Goodwill				693	693
Goodwill acquired				0	0
Goodwill, Transfers					0
Goodwill		693	693	693	693
Goodwill impairment			(79)	0	0
Goodwill, Other Changes				0	0
Crude oil transportation and services [Member]
Goodwill [Roll Forward]
Goodwill				1,167	1,167
Goodwill acquired				230	0
Goodwill, Transfers					0
Goodwill		1,167	1,167	1,397	1,167
Goodwill impairment				0	0
Goodwill, Other Changes				0	0
Investment In Sunoco LP [Member]
Goodwill [Roll Forward]
Goodwill				1,559	1,430
Goodwill acquired				0	129
Goodwill, Transfers					0
Goodwill		1,559	1,430	1,555	1,559
Goodwill impairment			(387)	0	0
Goodwill, Other Changes				(4)	0
Investment In USAC [Member]
Goodwill [Roll Forward]
Goodwill				619	0
Goodwill acquired				0	366
Goodwill, Transfers					253
Goodwill		619	0	619	619
Goodwill impairment				0	0
Goodwill, Other Changes				0	0
Other Segments [Member]
Goodwill [Roll Forward]
Goodwill				149	402
Goodwill acquired				35	0
Goodwill, Transfers					(253)
Goodwill		$ 149	402	184	149
Goodwill impairment			$ (452)	0	0
Goodwill, Other Changes				$ 0	$ 0

Estimates (Accrued And Other Cu

Estimates (Accrued And Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Other Information [Abstract]
Interest payable	$ 579		$ 571
Customer advances and deposits	123		128
Accrued capital expenditures	1,334		1,030
Accrued wages and benefits	217		283
Taxes payable other than income taxes	263		256
Exchanges payable	67		112
Other	759		538
Accrued and other current liabilities	$ 3,342	$ 2,917	$ 2,918

Estimates (Fair Value Of Financ

Estimates (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Commodity derivatives:	$ 384	$ 560
Other Assets, Fair Value Disclosure	31	26
Total assets	415	586
Interest rate derivatives	(399)	(163)
Commodity derivatives:	(389)	(583)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	788	746
Level 1 [Member]
Commodity derivatives:	369	448
Other Assets, Fair Value Disclosure	20	17
Total assets	389	465
Interest rate derivatives	0	0
Commodity derivatives:	(383)	(480)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	383	480
Level 2 [Member]
Commodity derivatives:	15	112
Other Assets, Fair Value Disclosure	11	9
Total assets	26	121
Interest rate derivatives	(399)	(163)
Commodity derivatives:	(6)	(103)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	405	266
Commodity Derivatives - Power [Member] | Options - Calls [Member]
Commodity derivatives:	1	1
Commodity Derivatives - Power [Member] | Forwards Swaps [Member]
Commodity derivatives:	11	48
Commodity derivatives:	(5)	(42)
Commodity Derivatives - Power [Member] | Future [Member]
Commodity derivatives:	4	1
Commodity derivatives:	(3)	(1)
Commodity Derivatives - Power [Member] | Options - Puts [Member]
Commodity derivatives:	1
Commodity Derivatives - Power [Member] | Level 1 [Member] | Options - Calls [Member]
Commodity derivatives:	1	1
Commodity Derivatives - Power [Member] | Level 1 [Member] | Forwards Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Commodity Derivatives - Power [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	4	1
Commodity derivatives:	(3)	(1)
Commodity Derivatives - Power [Member] | Level 1 [Member] | Options - Puts [Member]
Commodity derivatives:	1
Commodity Derivatives - Power [Member] | Level 2 [Member] | Options - Calls [Member]
Commodity derivatives:	0	0
Commodity Derivatives - Power [Member] | Level 2 [Member] | Forwards Swaps [Member]
Commodity derivatives:	11	48
Commodity derivatives:	(5)	(42)
Commodity Derivatives - Power [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Commodity Derivatives - Power [Member] | Level 2 [Member] | Options - Puts [Member]
Commodity derivatives:	0
Commodity Derivatives - Refined Products [Member] | Future [Member]
Commodity derivatives:	8	7
Commodity derivatives:	(10)	(15)
Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	8	7
Commodity derivatives:	(10)	(15)
Commodity Derivatives - Refined Products [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Commodity Derivatives - Crude [Member] | Forwards Swaps [Member]
Commodity derivatives:	13	1
Commodity Derivatives - Crude [Member] | Future [Member]
Commodity derivatives:		(61)
Commodity Derivatives - Crude [Member] | Level 1 [Member] | Forwards Swaps [Member]
Commodity derivatives:	13	1
Commodity Derivatives - Crude [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:		(61)
Commodity Derivatives - Crude [Member] | Level 2 [Member] | Forwards Swaps [Member]
Commodity derivatives:	0	0
Commodity Derivatives - Crude [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:		0
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	17	42
Commodity derivatives:	(49)	(91)
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	1	52
Commodity derivatives:	(1)	(40)
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	65	97
Commodity derivatives:	(43)	(88)
Commodity Derivatives - Natural Gas [Member] | Forward Physical Contracts [Member]
Commodity derivatives:		(21)
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	3	20
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	17	42
Commodity derivatives:	(49)	(91)
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	0	8
Commodity derivatives:	0	0
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	65	97
Commodity derivatives:	(43)	(88)
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Forward Physical Contracts [Member]
Commodity derivatives:		0
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	0	0
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	1	44
Commodity derivatives:	(1)	(40)
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Forward Physical Contracts [Member]
Commodity derivatives:		(21)
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	3	20
Commodity Derivatives - NGLs [Member] | Forwards Swaps [Member]
Commodity derivatives:	260	291
Commodity derivatives:	(278)	(224)
Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Forwards Swaps [Member]
Commodity derivatives:	260	291
Commodity derivatives:	(278)	(224)
Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Forwards Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	$ 0	$ 0

Acquisitions and Related Tran_3

Acquisitions and Related Transactions Acquisitions (2019 Transactions) (Details) - USD ($)		Dec. 05, 2019	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Long-term Debt			$ 51,054,000,000	$ 46,028,000,000
SemGroup [Member]
Business Acquisition [Line Items]
Senior Notes		$ 1,375,000,000
Preferred Stock, No Par Value		$ 0.01
Business Acquisition, Share Price		$ 6.80
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets		$ 794,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		3,914,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets		623,000,000
Business Acquisition, Purchase Price Allocation, Goodwill Expected to be Not Tax Deductible, Amount	[1]	265,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill		460,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets		6,056,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities		629,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	[2]	2,576,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other		196,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities		241,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities		3,642,000,000
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest		822,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	[3]	1,592,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents	[4]	153,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		$ 1,439,000,000
Conversion of Stock, Shares Issued		0.7275
SemGroup Subsidiary [Member] | SemGroup [Member]
Business Acquisition [Line Items]
Long-term Debt		$ 593,000,000
[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 SemGroup’s operations.
[2]	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 were redeemed in total in December 2019, subsequent to the close of the SemGroup Transaction, utilizing proceeds from an intercompany promissory note from ETO.
[3]	Total consideration includes (i) cash paid to SemGroup shareholders, (ii) fair value of ET Common Units issued in the acquisition and (iii) cash paid to redeem SemGroup’s preferred shares
[4]	Cash received represents cash and cash equivalents held by SemGroup as of the acquisition date.

Acquisitions and Related Tran_4

Acquisitions and Related Transactions Acquisitions (2018 Transactions) (Details) gal in Millions, $ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Oct. 31, 2018shares

Apr. 30, 2018USD ($)shares

Jan. 22, 2018USD ($)

Dec. 31, 2019USD ($)

Sep. 30, 2019USD ($)

Jun. 30, 2019USD ($)

Mar. 31, 2019USD ($)

Dec. 31, 2018USD ($)shares

Sep. 30, 2018USD ($)

Jun. 30, 2018USD ($)

Mar. 31, 2018USD ($)

Dec. 31, 2019USD ($)sharesgal

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Business Acquisition [Line Items]

Impairment losses | $

$ (12)

$ (9)

$ (21)

$ (378)

Limited Partner interest in the Partnership, percentage

99.90%

Long-term Purchase Commitment, Minimum Volume Required | gal

2,000

Revenues | $

$ 13,720

$ 13,495

$ 13,877

$ 13,121

$ 13,573

$ 14,514

$ 14,118

$ 11,882

$ 54,213

54,087

$ 40,523

ETE Merger [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

1,460,000,000

USAC Transaction [Member]

Business Acquisition [Line Items]

Business Combination, Consideration Transferred | $

$ 1,700

Payments to Acquire Businesses, Gross | $

$ 1,230

7-Eleven [Member]

Business Acquisition [Line Items]

Revenues | $

$ 199

3,200

Trade Receivables Held-for-sale, Reconciliation to Cash Flow, Period Increase (Decrease) | $

$ 3,700

$ 3,400

Sunoco LP [Member] | ETE Merger [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

2,263,158

2,263,158

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

Sunoco GP [Member] | ETE Merger [Member]

Business Acquisition [Line Items]

Limited Partner interest in the Partnership, percentage

100.00%

100.00%

USAC [Member] | ETE Merger [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

12,466,912

12,466,912

Limited Partner interest in the Partnership, percentage

100.00%

100.00%

Lake Charles LNG [Member] | ETE Merger [Member]

Business Acquisition [Line Items]

Limited Partner interest in the Partnership, percentage

100.00%

100.00%

Energy Transfer LNG Export LLC, ET Crude Oil Terminals LLC, & ETC Illinois LLC [Member] | ETE Merger [Member]

Business Acquisition [Line Items]

Limited Partner interest in the Partnership, percentage

60.00%

60.00%

ETO [Member] | Sunoco LP [Member] | ETE Merger [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

2,874,275

2,874,275

ETO [Member] | Sunoco GP [Member] | ETE Merger [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

42,812,389

42,812,389

ETO [Member] | USAC [Member] | ETE Merger [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

16,134,903

16,134,903

ETO [Member] | Lake Charles LNG [Member] | ETE Merger [Member]

Business Acquisition [Line Items]

Sale of Stock, Number of Shares Issued in Transaction

37,557,815

37,557,815

ET [Member] | 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

Additional aggregate volumes [Member]

Business Acquisition [Line Items]

Long-term Purchase Commitment, Minimum Volume Required | gal

500

Acquisitions and Related Tran_5

Acquisitions and Related Transactions Acquisitions (2017 Transactions) (Details) - USD ($) $ in Millions	1 Months Ended			12 Months Ended
	Oct. 31, 2017	Jul. 31, 2017	Feb. 28, 2017	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018	Feb. 01, 2017
Business Acquisition [Line Items]
Noncontrolling Interest, Increase from Sale of Parent Equity Interest		$ 988		$ 93
Intangible assets, net				6,154		$ 6,000
Property, Plant and Equipment, Net				$ 74,193	$ 66,962	$ 66,963
ETO [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.10%
ETO [Member] | Holdco [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		49.90%
Permian Express Partners LLC [Member]
Business Acquisition [Line Items]
Percent of total equity ownership of a subsidiary		88.00%
Intangible assets, net							$ 547
Property, Plant and Equipment, Net							$ 435
Holdco [Member] | Rover Pipeline LLC [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		65.00%
Blackstone [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	49.90%
Dakota Access and ETCOC [Member]
Business Acquisition [Line Items]
Percent of total equity ownership of a subsidiary		15.00%
Phillips 66 Company [Member] | Dakota Access and ETCOC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			25.00%
Bakken Holdings Company LLC [Member] | ETO [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Bakken Holdings Company LLC [Member] | Sunoco Logistics [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			49.00%
Bakken Holdings Company LLC [Member] | Bakken Pipeline Investments LLC [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired							200000000000.00%
Bakken Pipeline Investments LLC [Member] | Dakota Access and ETCOC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			75.00%

Acquisitions (Schedule Of Asset

Acquisitions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition Table) (Details) - USD ($) $ in Millions		Dec. 05, 2019	Apr. 30, 2018
SemGroup [Member]
Business Acquisition [Line Items]
Current assets		$ 794
Property, plant and equipment		3,914
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets		623
Goodwill(1)	[1]	265
Intangible assets		460
Total assets acquired		6,056
Current liabilities		629
Long-term debt obligations, less current maturities	[2]	2,576
Other non-current liabilities		196
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities		241
Total liabilities assumed		3,642
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest		822
Total consideration	[3]	1,592
Cash received	[4]	153
Total consideration, net of cash received		$ 1,439
USA Compression Partners, LP [Member]
Business Acquisition [Line Items]
Current assets			$ 786
Property, plant and equipment			1,332
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets			15
Goodwill(1)	[5]		366
Intangible assets			222
Total assets acquired			2,721
Current liabilities			110
Long-term debt obligations, less current maturities			1,527
Other non-current liabilities			2
Noncontrolling interest			832
Total liabilities assumed			1,639
Total consideration			250
Cash received	[6]		711
Total consideration, net of cash received	[6]		$ (461)
[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 SemGroup’s operations.
[2]	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 were redeemed in total in December 2019, subsequent to the close of the SemGroup Transaction, utilizing proceeds from an intercompany promissory note from ETO.
[3]	Total consideration includes (i) cash paid to SemGroup shareholders, (ii) fair value of ET Common Units issued in the acquisition and (iii) cash paid to redeem SemGroup’s preferred shares
[4]	Cash received represents cash and cash equivalents held by SemGroup as of the acquisition date.
[5]	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.
[6]	Cash received represents cash and cash equivalents held by USAC as of the acquisition date.

Acquisitions and Related Tran_6

Acquisitions and Related Transactions Acquisitions (Schedule of Discontinued Operations) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Loss on Debt Extinguishment				$ 20	$ 0
Disposal Group, Including Discontinued Operation, Revenue				349	6,964
Disposal Group, Including Discontinued Operation, Costs of Goods Sold				305	5,806
Disposal Group, Including Discontinued Operation, Operating Expense				61	763
Disposal Group, Including Discontinued Operation, Depreciation and Amortization				0	34
Disposal Group, Including Discontinued Operation, General and Administrative Expense				7	168
Impairment of Long-Lived Assets to be Disposed of				0	285
Goodwill impairment	$ 12	$ 9	$ 21	378
Disposal Group, Including Discontinued Operations, Total Costs and Expenses				373	7,056
Disposal Group, Including Discontinued Operation, Operating Income (Loss)				(24)	(92)
Disposal Group, Including Discontinued Operation, Interest Expense				2	36
Disposal Group, Including Discontinued Operation, Other Expense				61	1
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax				(107)	(129)
Discontinued Operation, Tax Effect of Discontinued Operation				158	48
Loss from discontinued operations			$ 0	(265)	(177)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent				$ (10)	$ (6)

Advances to and Investments i_3

Advances to and Investments in Unconsolidated Affiliates Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Impairment of investments in unconsolidated affiliates	$ 0	$ 0	$ 313
Impairment losses	74	431	1,039
Advances to and investments in unconsolidated affiliates	3,460	2,642	2,705
Equity in earnings of unconsolidated affiliates	$ 302	$ 344	$ 144
Citrus [Member]
Interest ownership	50.00%
Business Acquisition, Percentage of Voting Interests Acquired	50.00%
FGT [Member]
Percentage Ownership Operating Facility	100.00%
FEP [Member]
Interest ownership	50.00%
Impairment of investments in unconsolidated affiliates	$ 141
Midcontinent Express Pipeline, LLC [Member]
Interest ownership	50.00%

Advances to and Investments i_4

Advances to and Investments in Unconsolidated Affiliates Investment in Affiliates (Carrying Values) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity in earnings of unconsolidated affiliates	$ 302	$ 344	$ 144
Advances to and investments in unconsolidated affiliates	3,460	2,642	2,705
Citrus [Member]
Equity in earnings of unconsolidated affiliates	148	141	144
Advances to and investments in unconsolidated affiliates	1,876	1,737
FEP [Member]
Equity in earnings of unconsolidated affiliates	59	55	53
Advances to and investments in unconsolidated affiliates	218	107
MEP [Member]
Equity in earnings of unconsolidated affiliates	15	31	38
Advances to and investments in unconsolidated affiliates	429	225
Other Affiliates [Member]
Equity in earnings of unconsolidated affiliates	80	117	$ (91)
Advances to and investments in unconsolidated affiliates	$ 937	$ 573

Investments in Affiliates (Summ

Investments in Affiliates (Summarized Balance Sheet Information) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Investment In Affiliates [Abstract]
Current assets	$ 247	$ 212
Property, plant and equipment, net	7,680	7,800
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	40	39
Total assets	7,967	8,051
Current Liabilities	738	1,534
Non-current liabilities	3,242	3,439
Equity	3,987	3,078
Total liabilities and equity	$ 7,967	$ 8,051

Investments in Affiliates (Su_2

Investments in Affiliates (Summarized Income Statement Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Revenues	$ 1,192	$ 1,249	[1]	$ 1,358
Equity Method Investments Summarized Financial Information, Operating Income	683	723	[1]	407
Net income	443	460	[1]	145
Equity in earnings of unconsolidated affiliates	302	344		144
Citrus [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	148	141		144
FEP [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	59	55		53
MEP [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	15	31		38
Other Affiliates [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	$ 80	$ 117		$ (91)
[1]	Selected income data related to HPC for the year ended December 31, 2018 reflects HPC’s results for January 1, 2018 through March 31, 2018. HPC was fully consolidated beginning April 1, 2018 as discussed above.

Net Income Per Limited Partne_3

Net Income Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	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, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share [Abstract]
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent					$ 852	$ 1,393	$ 659	$ 726	$ 4,899	$ 3,630	$ 2,543
Less: Net income attributable to redeemable noncontrolling interests									51	39	0
Less: Income (loss) from continuing operations attributable to noncontrolling interests									1,256	1,888	1,583
Income from continuing operations, net of noncontrolling interests									3,592	1,703	960
Less: General Partner’s interest in income from continuing operations									4	3	2
Convertible Unitholders’ interest in net income									0	33	38
Income from continuing operations available to Limited Partners									3,588	1,667	920
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units									(1)	33	38
Diluted income from continuing operations available to Limited Partners									$ 3,587	$ 1,700	$ 958
Weighted average limited partner units									2,628	1,423.8	1,078.2
Incremental Common Shares Attributable to Dilutive Effect of Conversion of Preferred Stock									0	30.3	72.6
Basic income from continuing operations per Limited Partner unit	$ 0.38	$ 0.32	$ 0.33	$ 0.33	$ 0.26	$ 0.32	$ 0.30	$ 0.32	$ 1.37	$ 1.17	$ 0.86
Basic loss from discontinued operations per Limited Partner unit									$ 0	$ (0.01)	$ (0.01)
Dilutive effect of unconverted unit awards and ET Series A Convertible Preferred Units									9.6	7.3	0
Weighted average limited partner units, assuming dilutive effect of unvested unit awards									2,637.6	1,461.4	1,150.8
Diluted income from continuing operations per Limited Partner unit	$ 0.38	$ 0.32	$ 0.33	$ 0.33	$ 0.26	$ 0.32	$ 0.30	$ 0.32	$ 1.36	$ 1.16	$ 0.84
Diluted loss from discontinued operations per Limited Partner unit									$ 0	$ (0.01)	$ (0.01)

Debt Obligations Debt Obligat_2

Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Jun. 30, 2019	Mar. 31, 2019	Jan. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		$ 279
Other Long-term Debt		2					$ 7
Long-term Debt		51,054					46,028
Current maturities of long-term debt		26				$ 2,656	2,655
Long-term debt, less current maturities		51,028				$ 43,379	43,373
Parent Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		0					10
Deferred Finance Costs, Noncurrent, Net		0					(27)
Long-term Debt		$ 124					5,520
Parent Company [Member] | ETE 7.5% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.50%
Debt Instrument, Maturity Date		Oct. 15, 2020
Senior Notes	[1]	$ 52					1,187
Parent Company [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.88%
Debt Instrument, Maturity Date		Jan. 15, 2024
Senior Notes		$ 23					1,150
Parent Company [Member] | 5.5% Senior Notes due June 1, 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.50%
Debt Instrument, Maturity Date		Jun. 1, 2027
Senior Notes		$ 44					1,000
Parent Company [Member] | 4.25% Senior Notes due March 15, 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.25%
Debt Instrument, Maturity Date		Mar. 15, 2023
Senior Notes		$ 5					1,000
Parent Company [Member] | ETE Senior Secured Term Loan due February 2, 2024 [Member]
Debt Instrument [Line Items]
Secured Debt		0					1,220
ETO [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		(5)					17
Deferred Finance Costs, Noncurrent, Net		(207)					(178)
Long-term Debt		$ 42,120					32,288
ETO [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.88%		5.875%
Debt Instrument, Maturity Date		Jan. 15, 2024
Senior Notes		$ 1,127		$ 1,130			0
ETO [Member] | 5.5% Senior Notes due June 1, 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.50%		5.50%
Debt Instrument, Maturity Date		Jun. 1, 2027
Senior Notes		$ 956		$ 956			0
ETO [Member] | 4.25% Senior Notes due March 15, 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.25%		4.25%
Debt Instrument, Maturity Date		Mar. 15, 2023
Senior Notes		$ 995		$ 995			0
ETO [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.60%
Debt Instrument, Maturity Date		Feb. 1, 2024
Senior Notes		$ 277					277
ETO [Member] | 4.05% Senior Notes due March 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.05%
Debt Instrument, Maturity Date		Mar. 15, 2025
Senior Notes		$ 1,000					1,000
ETO [Member] | 4.75% Senior Notes due January 2026 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.75%
Debt Instrument, Maturity Date		Jan. 15, 2026
Senior Notes		$ 1,000					1,000
ETO [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		8.25%
Debt Instrument, Maturity Date		Nov. 15, 2029
Senior Notes		$ 267					267
ETO [Member] | 4.90% Senior Notes due March 2035 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.90%
Debt Instrument, Maturity Date		Mar. 15, 2035
Senior Notes		$ 500					500
ETO [Member] | 6.625% Senior Notes, due October 15, 2036 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.63%
Debt Instrument, Maturity Date		Oct. 15, 2036
Senior Notes		$ 400					400
ETO [Member] | 5.80% Senior Notes due 2038 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.80%
Debt Instrument, Maturity Date		Jul. 1, 2038
Senior Notes		$ 500					500
ETO [Member] | 7.5% Senior Notes, due July 1, 2038 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.50%
Debt Instrument, Maturity Date		Jul. 1, 2038
Senior Notes		$ 550					550
ETO [Member] | Senior Notes 6.05% Due June 1, 2041 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.85%
Debt Instrument, Maturity Date		Jun. 1, 2041
Senior Notes		$ 700					700
ETO [Member] | Senior Notes 6.50% Due February 1, 2042 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.05%
Debt Instrument, Maturity Date		Feb. 1, 2042
Senior Notes		$ 1,000					1,000
ETO [Member] | 5.15% Senior Notes due February 1, 2043 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.95%
Debt Instrument, Maturity Date		Feb. 1, 2043
Senior Notes		$ 450					450
ETO [Member] | 5.95% Senior Notes due October 1, 2043 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.15%
Debt Instrument, Maturity Date		Oct. 1, 2043
Senior Notes		$ 450					450
ETO [Member] | 5.15% Senior Notes due March 2045 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.30%
Debt Instrument, Maturity Date		Mar. 15, 2045
Senior Notes		$ 1,000					1,000
ETO [Member] | 6.125% Senior Notes due December 2045 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.35%
Debt Instrument, Maturity Date		May 15, 2045
Senior Notes		$ 1,000					1,000
ETO [Member] | 5.30% Senior Notes due April 2047 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.13%
Debt Instrument, Maturity Date		Apr. 1, 2047
Senior Notes		$ 900					900
ETO [Member] | 5.40% Senior Notes due October 1, 2047 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.30%
Debt Instrument, Maturity Date		Oct. 1, 2047
Senior Notes		$ 1,500					1,500
ETO [Member] | 6.0% Senior Notes due 2048 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.00%
Debt Instrument, Maturity Date		Jun. 15, 2048
Senior Notes		$ 1,000					1,000
ETO [Member] | 6.25% Senior Notes due 2049 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.25%			6.25%
Debt Instrument, Maturity Date		Apr. 15, 2049
Senior Notes		$ 1,750			$ 1,750		0
ETO [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.40%
Junior Subordinated Notes		$ 546					546
ETO [Member] | ETO Term Loan [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		2,000					0
ETO [Member] | ETO Credit Facility due December 2022 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		$ 4,214					3,694
ETO [Member] | 9.00% Debentures, due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		9.00%
Debt Instrument, Maturity Date		Nov. 1, 2024
Subordinated Debt		$ 65					65
ETO [Member] | 5.50% Senior Notes, due February 15, 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.50%
Debt Instrument, Maturity Date		Feb. 15, 2020
Senior Notes	[1]	$ 250					250
ETO [Member] | Senior Note 4.65% Due February 15, 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.65%
Debt Instrument, Maturity Date		Feb. 15, 2022
Senior Notes		$ 300					300
ETO [Member] | 3.45% Senior Notes due January 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.45%
Debt Instrument, Maturity Date		Feb. 1, 2023
Senior Notes		$ 350					350
ETO [Member] | 6.85% Senior Notes, due February 15, 2040 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date		Feb. 15, 2040
Senior Notes		$ 250					250
ETO [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.25%
Debt Instrument, Maturity Date		Apr. 1, 2024
Senior Notes		$ 500					500
ETO [Member] | 4.5% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					4.50%
Senior Notes		$ 750			$ 750		0
ETO [Member] | 5.95% Senior Notes due December 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.95%
Debt Instrument, Maturity Date		Dec. 1, 2025
Senior Notes		$ 400					400
ETO [Member] | 3.90% Senior Notes due July 15, 2026 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.90%
Debt Instrument, Maturity Date		Jul. 15, 2026
Senior Notes		$ 550					550
ETO [Member] | 4.20% Senior Notes due April 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.20%
Debt Instrument, Maturity Date		Apr. 15, 2027
Senior Notes		$ 600					600
ETO [Member] | 4.00% Senior Notes due October 1, 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.00%
Debt Instrument, Maturity Date		Oct. 1, 2027
Senior Notes		$ 750					750
ETO [Member] | 4.95% Senior Notes due 2028 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.95%
Debt Instrument, Maturity Date		Jun. 15, 2028
Senior Notes		$ 1,000					1,000
ETO [Member] | 5.25% Senior Notes due 2029 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.25%			5.25%
Debt Instrument, Maturity Date		Apr. 15, 2029
Senior Notes		$ 1,500			$ 1,500		0
ETO [Member] | Senior Note 6.10%, due February 15, 2042 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.50%
Debt Instrument, Maturity Date		Feb. 15, 2042
Senior Notes		$ 300					300
ETO [Member] | 5.30% Senior Notes due April 1, 2044 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.95%
Debt Instrument, Maturity Date		Apr. 1, 2044
Senior Notes		$ 700					700
ETO [Member] | 5.35% Senior Notes due May 15, 2045 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.15%
Debt Instrument, Maturity Date		Dec. 15, 2045
Senior Notes		$ 800					800
ETO [Member] | 4.95% Senior Notes due January 2043 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.10%
Debt Instrument, Maturity Date		Jan. 15, 2043
Senior Notes		$ 350					350
ETO [Member] | 9.7% Senior Notes, due March 15, 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		9.70%			9.70%
Debt Instrument, Maturity Date		Mar. 15, 2019
Senior Notes		$ 0					400
ETO [Member] | 9.0% Senior Notes due April 15, 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		9.00%			9.00%
Debt Instrument, Maturity Date		Apr. 15, 2019
Senior Notes		$ 0					450
ETO [Member] | 5.75% Senior Notes due September 1, 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.75%
Debt Instrument, Maturity Date		Sep. 1, 2020
Senior Notes	[1]	$ 400					400
ETO [Member] | 4.15% Senior Notes due October 1, 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.15%
Debt Instrument, Maturity Date		Oct. 1, 2020
Senior Notes	[1]	$ 1,050					1,050
ETO [Member] | 5.875% Senior Notes due April 1, 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.88%
Debt Instrument, Maturity Date		Mar. 1, 2022
Senior Notes		$ 900					900
ETO [Member] | 4.5% Senior Notes due November 1, 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.50%
Debt Instrument, Maturity Date		Nov. 1, 2023
Senior Notes		$ 600					600
ETO [Member] | 4.9% Senior Notes due February 1, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.90%
Debt Instrument, Maturity Date		Feb. 1, 2024
Senior Notes		$ 350					350
ETO [Member] | Senior Notes 4.65% Due June 1, 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.65%
Debt Instrument, Maturity Date		Jun. 1, 2021
Senior Notes		$ 800					800
ETO [Member] | Senior Notes 5.20% Due February 1, 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.20%
Debt Instrument, Maturity Date		Feb. 1, 2022
Senior Notes		$ 1,000					1,000
ETO [Member] | 5.0% Senior Notes due October 1, 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.00%
Debt Instrument, Maturity Date		Oct. 1, 2022
Senior Notes		$ 700					700
ETO [Member] | 3.6% Senior Notes due February 1, 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.60%
Debt Instrument, Maturity Date		Feb. 1, 2023
Senior Notes		$ 800					800
ETO [Member] | 4.20% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.20%
Debt Instrument, Maturity Date		Sep. 15, 2023
Senior Notes		$ 500					500
ETO [Member] | ETO 364-day Credit Facility due November 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		0
ETO [Member] | 7.5% Senior Notes due October 15, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes	[1]	1,135					0
Bakken Project [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net		(16)					(3)
Long-term Debt		2,481					2,497
Bakken Project [Member] | Bakken Project $2.50 billion Credit Facility due August 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		0					2,500
Debt Instrument, Unamortized Discount (Premium), Net		(3)					0
Bakken Project [Member] | 3.625% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		650					0
Bakken Project [Member] | 3.90% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000					0
Bakken Project [Member] | 4.625% Senior Notes due 2029 [Member]
Debt Instrument [Line Items]
Senior Notes		850					0
Sunoco LP [Member]
Debt Instrument [Line Items]
Capital Lease Obligations		135					107
Deferred Finance Costs, Noncurrent, Net		(26)					(23)
Long-term Debt		$ 3,071					2,984
Sunoco LP [Member] | 6.00% Senior Notes due April 15, 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.00%
Debt Instrument, Maturity Date		Apr. 15, 2027
Senior Notes		$ 600					0
Sunoco LP [Member] | 5.5% Senior Notes due August 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.50%
Debt Instrument, Maturity Date		Feb. 15, 2026
Sunoco LP [Member] | Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		$ 162					700
Sunoco LP [Member] | 5.875% senior notes due 2028 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.88%
Debt Instrument, Maturity Date		Mar. 15, 2028
Senior Notes		$ 400					400
Transwestern [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net		(1)					(1)
Long-term Debt		$ 574					574
Transwestern [Member] | 5.36% Senior Unsecured Notes, due December 9, 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.36%
Debt Instrument, Maturity Date		Dec. 9, 2020
Senior Notes	[1]	$ 175					175
Transwestern [Member] | 5.89% Senior Unsecured Notes, due May 24, 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.89%
Debt Instrument, Maturity Date		May 24, 2022
Senior Notes		$ 150					150
Transwestern [Member] | 5.66% Senior Unsecured Notes, due December 9, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.66%
Debt Instrument, Maturity Date		Dec. 9, 2024
Senior Notes		$ 175					175
Transwestern [Member] | 6.16% Senior Unsecured Notes, due May 24, 2037 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.16%
Debt Instrument, Maturity Date		May 24, 2037
Senior Notes		$ 75					75
Transwestern [Member] | 6.875% Senior notes due April 2026 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.88%
Debt Instrument, Maturity Date		Apr. 1, 2026
Transwestern [Member] | 6.875% Senior Notes due September 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.88%
Debt Instrument, Maturity Date		Sep. 1, 2027
Panhandle [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			8.125%
Debt Instrument, Unamortized Discount (Premium), Net		$ 11					14
Long-term Debt		$ 246					399
Panhandle [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.60%
Debt Instrument, Maturity Date		Feb. 1, 2024
Senior Notes		$ 82					82
Panhandle [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		8.20%
Debt Instrument, Maturity Date		Nov. 15, 2029
Senior Notes		$ 33					33
Panhandle [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member]
Debt Instrument [Line Items]
Junior Subordinated Notes		$ 54					54
Panhandle [Member] | 8.125% Senior Notes, due June 1, 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		8.13%			8.125%
Debt Instrument, Maturity Date		Jun. 1, 2019
Senior Notes		$ 0					150
Panhandle [Member] | 7.00% Senior Notes, due July 15, 2029 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.00%
Debt Instrument, Maturity Date		Jul. 15, 2029
Senior Notes		$ 66					66
USA Compression Partners, LP [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		403					1,050
Deferred Finance Costs, Noncurrent, Net		(26)					(16)
Long-term Debt		1,852					1,759
USA Compression Partners, LP [Member] | 6.875% Senior notes due April 2026 [Member]
Debt Instrument [Line Items]
Senior Notes		725					725
USA Compression Partners, LP [Member] | 6.875% Senior Notes due September 2027 [Member]
Debt Instrument [Line Items]
Senior Notes		750					0
SemGroup [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		1					0
Deferred Finance Costs, Noncurrent, Net		(3)					0
Long-term Debt		584					0
SemGroup [Member] | HFOTCO Tax Exempt Notes due 2050 [Member]
Debt Instrument [Line Items]
Senior Notes		225					0
SemGroup [Member] | SemCAMS Revolver due February 25, 2024 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		92					0
SemGroup [Member] | SemCAMS Term Loan A due February 25, 2024 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		$ 269					$ 0
[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 Obligat_3

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) $ in Millions	Dec. 31, 2019USD ($)
Debt Obligations [Abstract]
2020	$ 3,086
2021	1,412
2022	5,792
2023	8,965
2024	4,708
Thereafter	27,366
Long-term Debt	$ 51,329

Debt Obligations (Debt Narrativ

Debt Obligations (Debt Narrative) (Details) $ in Millions		1 Months Ended			3 Months Ended	12 Months Ended
		Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Jan. 31, 2019USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jan. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Oct. 31, 2019USD ($)
Noncontrolling interests						$ 12,018,000,000	$ 10,291,000,000
Less: Net income attributable to noncontrolling interests						1,256,000,000	1,632,000,000	$ 1,412,000,000
Repayments of Long-term Debt						20,101,000,000	28,948,000,000	31,268,000,000
Proceeds from Issuance of Senior Long-term Debt				$ 3,960,000,000		4,210,000,000
Long-term Debt						51,054,000,000	46,028,000,000
Proceeds from borrowings						$ 22,583,000,000	29,001,000,000	$ 31,608,000,000
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.
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) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (ii) 5.0 to 1.0 thereafter, in each case subject to a provision for increases to such thresholds by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.
Parent Company [Member]
Long-term Debt						$ 124,000,000	5,520,000,000
Parent Company [Member] | ETE 7.5% Senior Notes due 2020 [Member]
Senior Notes	[1]					$ 52,000,000	1,187,000,000
Debt instrument, interest rate, stated percentage						7.50%				7.50%
Debt Instrument, Maturity Date						Oct. 15, 2020
Parent Company [Member] | ETE Senior Secured Term Loan due February 2, 2024 [Member]
Line of Credit Facility, Maximum Borrowing Capacity						$ 2,200,000,000
Parent Company [Member] | 4.25% Senior Notes due March 15, 2023 [Member]
Senior Notes						$ 5,000,000	1,000,000,000
Debt instrument, interest rate, stated percentage						4.25%				4.25%
Debt Instrument, Maturity Date						Mar. 15, 2023
Parent Company [Member] | 5.5% Senior Notes due June 1, 2027 [Member]
Senior Notes						$ 44,000,000	1,000,000,000
Debt instrument, interest rate, stated percentage						5.50%				5.50%
Debt Instrument, Maturity Date						Jun. 1, 2027
Parent Company [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Senior Notes						$ 23,000,000	1,150,000,000
Debt instrument, interest rate, stated percentage						5.88%				5.88%
Debt Instrument, Maturity Date						Jan. 15, 2024
ET [Member]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed			97.00%
USA Compression Partners, LP [Member]
Long-term Debt						$ 1,852,000,000	1,759,000,000
Outstanding borrowings						403,000,000	1,050,000,000
USA Compression Partners, LP [Member] | 6.875% Senior notes due April 2026 [Member]
Senior Notes						725,000,000	725,000,000
USA Compression Partners, LP [Member] | USAC Credit Facility, due 2023 [Member]
Line of Credit Facility, Current Borrowing Capacity						1,600,000,000
USAC [Member]
Line of Credit Facility, Increase (Decrease), Net			$ 750,000,000
Line of Credit Facility, Maximum Borrowing Capacity			0.06875		$ 0.06875
USAC [Member] | USAC Credit Facility, due 2023 [Member]
Letters of Credit Outstanding, Amount						0
Line of Credit Facility, Remaining Borrowing Capacity						$ 1,200,000,000
Line of Credit Facility, Interest Rate at Period End						4.31%				4.31%
Outstanding borrowings						$ 403,000,000
SemCAMS [Member]
Line of Credit Facility, Remaining Borrowing Capacity						193,000,000
Line of Credit Facility, Maximum Borrowing Capacity						404,000,000
Long-term Construction Loan						231,000,000
SemCAMS [Member] | SemCAMS Senior secured term loan [Member]
Senior Notes						270,000,000
ETO [Member]
Long-term Debt						42,120,000,000	32,288,000,000
ETO [Member] | 5.75% Senior Notes due September 1, 2020 [Member]
Senior Notes	[1]					$ 400,000,000	400,000,000
Debt instrument, interest rate, stated percentage						5.75%				5.75%
Debt Instrument, Maturity Date						Sep. 1, 2020
ETO [Member] | 9.7% Senior Notes, due March 15, 2019 [Member]
Senior Notes						$ 0	400,000,000
Repayments of Senior Debt				$ 400,000,000
Debt instrument, interest rate, stated percentage				9.70%		9.70%				9.70%
Debt Instrument, Maturity Date						Mar. 15, 2019
ETO [Member] | 9.0% Senior Notes due April 15, 2019 [Member]
Senior Notes						$ 0	450,000,000
Repayments of Senior Debt				$ 450,000,000
Debt instrument, interest rate, stated percentage				9.00%		9.00%				9.00%
Debt Instrument, Maturity Date						Apr. 15, 2019
ETO [Member] | ETO Term Loan [Member]
Line of Credit Facility, Interest Rate at Period End						2.78%				2.78%
Outstanding borrowings						$ 2,000,000,000	0
Line of Credit Facility, Maximum Borrowing Capacity											$ 2,000,000,000
ETO [Member] | ETO Credit Facility due December 2022 [Member]
Line of Credit Facility, Current Borrowing Capacity						5,000,000,000
Letters of Credit Outstanding, Amount						77,000,000
Line of Credit Facility, Remaining Borrowing Capacity						$ 709,000,000
Line of Credit Facility, Interest Rate at Period End						2.88%				2.88%
Outstanding borrowings						$ 4,214,000,000	3,694,000,000
Long-term Commercial Paper, Noncurrent						1,640,000,000
ETO [Member] | 4.25% Senior Notes due March 15, 2023 [Member]
Senior Notes			$ 995,000,000		$ 995,000,000	$ 995,000,000	0
Debt instrument, interest rate, stated percentage			4.25%		4.25%	4.25%				4.25%
Debt Instrument, Maturity Date						Mar. 15, 2023
ETO [Member] | 5.5% Senior Notes due June 1, 2027 [Member]
Senior Notes			$ 956,000,000		$ 956,000,000	$ 956,000,000	0
Debt instrument, interest rate, stated percentage			5.50%		5.50%	5.50%				5.50%
Debt Instrument, Maturity Date						Jun. 1, 2027
ETO [Member] | 7.50% Senior Notes Due 2020 [Member]
Senior Notes			$ 1,140,000,000		$ 1,140,000,000
Debt instrument, interest rate, stated percentage			7.50%		7.50%	7.50%				7.50%
Debt Instrument, Maturity Date						Oct. 15, 2020
ETO [Member] | 5.35% Senior Notes due May 15, 2045 [Member]
Senior Notes						$ 800,000,000	800,000,000
Debt instrument, interest rate, stated percentage						5.15%				5.15%
Debt Instrument, Maturity Date						Dec. 15, 2045
ETO [Member] | 3.26% Junior Subordinated Notes due November 1, 2066 [Member]
Junior Subordinated Notes						$ 546,000,000	546,000,000
Debt instrument, interest rate, stated percentage						5.40%				5.40%
ETO [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Senior Notes						$ 500,000,000	500,000,000
Debt instrument, interest rate, stated percentage						4.25%				4.25%
Debt Instrument, Maturity Date						Apr. 1, 2024
ETO [Member] | 5.875% Senior Notes due April 1, 2022 [Member]
Senior Notes						$ 900,000,000	900,000,000
Debt instrument, interest rate, stated percentage						5.88%				5.88%
Debt Instrument, Maturity Date						Mar. 1, 2022
ETO [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Senior Notes			$ 1,130,000,000		$ 1,130,000,000	$ 1,127,000,000	0
Debt instrument, interest rate, stated percentage			5.875%		5.875%	5.88%				5.88%
Debt Instrument, Maturity Date						Jan. 15, 2024
ETO [Member] | 5.0% Senior Notes due October 1, 2022 [Member]
Senior Notes						$ 700,000,000	700,000,000
Debt instrument, interest rate, stated percentage						5.00%				5.00%
Debt Instrument, Maturity Date						Oct. 1, 2022
ETO [Member] | 4.40% Senior Notes due April 2021 [Member]
Senior Notes						$ 600,000,000	600,000,000
Debt instrument, interest rate, stated percentage						4.40%				4.40%
Debt Instrument, Maturity Date						Apr. 1, 2021
ETO [Member] | 3.90% Senior Notes due July 15, 2026 [Member]
Senior Notes						$ 550,000,000	550,000,000
Debt instrument, interest rate, stated percentage						3.90%				3.90%
Debt Instrument, Maturity Date						Jul. 15, 2026
ETO [Member] | ETO 364-day Credit Facility due November 2019 [Member]
Outstanding borrowings						$ 0
Line of Credit Facility, Maximum Borrowing Capacity						1,000,000,000
ETO [Member] | 4.5% Senior Notes due 2024 [Member]
Senior Notes				$ 750,000,000		750,000,000	0
Debt instrument, interest rate, stated percentage				4.50%
ETO [Member] | 6.25% Senior Notes due 2049 [Member]
Senior Notes				$ 1,750,000,000		$ 1,750,000,000	0
Debt instrument, interest rate, stated percentage				6.25%		6.25%				6.25%
Debt Instrument, Maturity Date						Apr. 15, 2049
ETO [Member] | 5.25% Senior Notes due 2029 [Member]
Senior Notes				$ 1,500,000,000		$ 1,500,000,000	0
Debt instrument, interest rate, stated percentage				5.25%		5.25%				5.25%
Debt Instrument, Maturity Date						Apr. 15, 2029
ETO [Member] | 4.20% Senior Notes due 2023 [Member]
Senior Notes						$ 500,000,000	500,000,000
Debt instrument, interest rate, stated percentage						4.20%				4.20%
Debt Instrument, Maturity Date						Sep. 15, 2023
ETO [Member] | 4.95% Senior Notes due 2028 [Member]
Senior Notes						$ 1,000,000,000	1,000,000,000
Debt instrument, interest rate, stated percentage						4.95%				4.95%
Debt Instrument, Maturity Date						Jun. 15, 2028
ETO [Member] | 5.80% Senior Notes due 2038 [Member]
Senior Notes						$ 500,000,000	500,000,000
Debt instrument, interest rate, stated percentage						5.80%				5.80%
Debt Instrument, Maturity Date						Jul. 1, 2038
ETO [Member] | 6.0% Senior Notes due 2048 [Member]
Senior Notes						$ 1,000,000,000	1,000,000,000
Debt instrument, interest rate, stated percentage						6.00%				6.00%
Debt Instrument, Maturity Date						Jun. 15, 2048
ETO [Member] | 4.15% Senior Notes due October 1, 2020 [Member]
Senior Notes	[1]					$ 1,050,000,000	1,050,000,000
Debt instrument, interest rate, stated percentage						4.15%				4.15%
Debt Instrument, Maturity Date						Oct. 1, 2020
ETO [Member] | 7.5% Senior Notes due October 15, 2020 [Member]
Senior Notes	[1]					$ 1,135,000,000	0
ETO [Member] | 5.50% Senior Notes, due February 15, 2020 [Member]
Senior Notes	[1]					$ 250,000,000	250,000,000
Debt instrument, interest rate, stated percentage						5.50%				5.50%
Debt Instrument, Maturity Date						Feb. 15, 2020
ETO [Member] | Minimum [Member] | ETO Credit Facility due December 2022 [Member]
Line of Credit Facility, Commitment Fee Percentage						0.125%
ETO [Member] | Minimum [Member] | ETO 364-day Credit Facility due November 2019 [Member]
Line of Credit Facility, Commitment Fee Percentage						0.125%
ETO [Member] | Maximum [Member] | ETO Credit Facility due December 2022 [Member]
Line of Credit Facility, Commitment Fee Percentage						0.30%
ETO [Member] | Maximum [Member] | ETO 364-day Credit Facility due November 2019 [Member]
Line of Credit Facility, Commitment Fee Percentage						0.225%
Transwestern [Member]
Long-term Debt						$ 574,000,000	574,000,000
Transwestern [Member] | 5.36% Senior Unsecured Notes, due December 9, 2020 [Member]
Senior Notes	[1]					$ 175,000,000	175,000,000
Debt instrument, interest rate, stated percentage						5.36%				5.36%
Debt Instrument, Maturity Date						Dec. 9, 2020
Transwestern [Member] | 6.875% Senior notes due April 2026 [Member]
Debt instrument, interest rate, stated percentage						6.88%				6.88%
Debt Instrument, Maturity Date						Apr. 1, 2026
Panhandle [Member]
Repayments of Senior Debt		$ 150,000,000
Long-term Debt						$ 246,000,000	399,000,000
Debt instrument, interest rate, stated percentage		8.125%
Panhandle [Member] | 3.26% Junior Subordinated Notes due November 1, 2066 [Member]
Junior Subordinated Notes						54,000,000	54,000,000
Panhandle [Member] | 8.125% Senior Notes, due June 1, 2019 [Member]
Senior Notes						$ 0	150,000,000
Repayments of Senior Debt				$ 150,000,000
Debt instrument, interest rate, stated percentage				8.125%		8.13%				8.13%
Debt Instrument, Maturity Date						Jun. 1, 2019
Dakota Access, LLC [Member]
Proceeds from Issuance of Senior Long-term Debt					$ 2,480,000,000
Dakota Access, LLC [Member] | 3.625% Senior Notes due 2022 [Member]
Senior Notes			$ 650,000,000		$ 650,000,000
Debt instrument, interest rate, stated percentage			3.625%		3.625%
Dakota Access, LLC [Member] | 3.90% Senior Notes due 2024 [Member]
Senior Notes			$ 1,000,000,000		$ 1,000,000,000
Debt instrument, interest rate, stated percentage			3.90%		3.90%
Dakota Access, LLC [Member] | 4.625% Senior Notes due 2029 [Member]
Senior Notes			$ 850,000,000		$ 850,000,000
Debt instrument, interest rate, stated percentage			4.625%		4.625%
Bakken Project [Member]
Long-term Debt						$ 2,481,000,000	2,497,000,000
Bakken Project [Member] | Bakken Project $2.50 billion Credit Facility due August 2019 [Member]
Outstanding borrowings						0	2,500,000,000
Bakken Project [Member] | 3.625% Senior Notes due 2022 [Member]
Senior Notes						650,000,000	0
Bakken Project [Member] | 3.90% Senior Notes due 2024 [Member]
Senior Notes						1,000,000,000	0
Bakken Project [Member] | 4.625% Senior Notes due 2029 [Member]
Senior Notes						850,000,000	0
Sunoco LP [Member]
Line of Credit Facility, Increase (Decrease), Net			$ 600,000,000
Long-term Debt						$ 3,071,000,000	2,984,000,000
Line of Credit Facility, Maximum Borrowing Capacity			$ 0.0600		$ 0.0600
Sunoco LP [Member] | 5.5% Senior Notes due August 2020 [Member]
Debt instrument, interest rate, stated percentage						5.50%				5.50%
Debt Instrument, Maturity Date						Feb. 15, 2026
Sunoco LP [Member] | 4.875% senior notes due 2023 [Member]
Senior Notes						$ 1,000,000,000	1,000,000,000
Debt instrument, interest rate, stated percentage						4.88%				4.88%
Debt Instrument, Maturity Date						Jan. 15, 2023
Sunoco LP [Member] | 5.500% senior notes due 2026 [Member]
Senior Notes						$ 800,000,000	800,000,000
Sunoco LP [Member] | 5.875% senior notes due 2028 [Member]
Senior Notes						$ 400,000,000	400,000,000
Debt instrument, interest rate, stated percentage						5.88%				5.88%
Debt Instrument, Maturity Date						Mar. 15, 2028
Sunoco LP [Member] | Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member]
Line of Credit Facility, Current Borrowing Capacity						$ 1,500,000,000
Letters of Credit Outstanding, Amount						8,000,000
Line of Credit Facility, Remaining Borrowing Capacity						$ 1,330,000,000
Line of Credit Facility, Interest Rate at Period End						3.75%				3.75%
Outstanding borrowings						$ 162,000,000	$ 700,000,000
Accordion feature [Member] | USA Compression Partners, LP [Member] | USAC Credit Facility, due 2023 [Member]
Outstanding borrowings						400,000,000
Accordion feature [Member] | ETO [Member] | ETO Credit Facility due December 2022 [Member]
Line of Credit Facility, Current Borrowing Capacity						$ 6,000,000,000
Eurodollar [Member] | Maximum [Member]
Debt Instrument, Basis Spread on Variable Rate						2.00%
Eurodollar [Member] | ETO [Member] | Minimum [Member] | ETO Credit Facility due December 2022 [Member]
Debt Instrument, Basis Spread on Variable Rate						1.125%
Eurodollar [Member] | ETO [Member] | Minimum [Member] | ETO 364-day Credit Facility due November 2019 [Member]
Debt Instrument, Basis Spread on Variable Rate						1.25%
Eurodollar [Member] | ETO [Member] | Maximum [Member] | ETO 364-day Credit Facility due November 2019 [Member]
Debt Instrument, Basis Spread on Variable Rate						1.75%
Base Rate Loans [Member] | ETO [Member] | Minimum [Member] | ETO Credit Facility due December 2022 [Member]
Debt Instrument, Basis Spread on Variable Rate						0.125%
Base Rate Loans [Member] | ETO [Member] | Minimum [Member] | ETO 364-day Credit Facility due November 2019 [Member]
Debt Instrument, Basis Spread on Variable Rate						0.25%
Base Rate Loans [Member] | ETO [Member] | Maximum [Member] | ETO Credit Facility due December 2022 [Member]
Debt Instrument, Basis Spread on Variable Rate						1.00%
Base Rate Loans [Member] | ETO [Member] | Maximum [Member] | ETO 364-day Credit Facility due November 2019 [Member]
Debt Instrument, Basis Spread on Variable Rate						0.75%
Canada, Dollars | SemCAMS [Member]
Line of Credit Facility, Remaining Borrowing Capacity										$ 250
Line of Credit Facility, Maximum Borrowing Capacity										525
Long-term Construction Loan										300
Canada, Dollars | SemCAMS [Member] | SemCAMS Senior secured term loan [Member]
Senior Notes										$ 350
Subsequent Event [Member] | 2.9% Senior Notes due 2025 [Member]
Senior Notes									$ 1,000,000,000
Subsequent Event [Member] | 3.75% Senior Notes due 2030 [Member]
Senior Notes									1,500,000,000
Subsequent Event [Member] | 5.0% Senior Notes due 2050 [Member]
Senior Notes									$ 2,000,000,000
[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 Obligat_4

Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2019
Debt Instrument [Line Items]
Leverage Ratio Maximum	6
Maximum Leverage Ratio Permitted	7
Supplementary Leverage Ratio	404.00%
Debt instrument covenant minimum fixed charge coverage ratio	1.5
ETO [Member]
Debt Instrument [Line Items]
Leverage Ratio Maximum	5
Maximum Leverage Ratio Permitted	5.5
Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member]
Debt Instrument [Line Items]
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.
USAC Credit Facility, due 2023 [Member]
Debt Instrument [Line Items]
Minimum interest coverage ratio	2.5
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) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (ii) 5.0 to 1.0 thereafter, in each case subject to a provision for increases to such thresholds by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.
Eurodollar [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%

Debt Obligations Debt Obligat_5

Debt Obligations Debt Obligations (Interest Rates & Maturities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Jun. 30, 2019	Mar. 31, 2019	Jan. 31, 2019	Dec. 31, 2018
Parent Company [Member]
Deferred Finance Costs, Noncurrent, Net	$ 0				$ 27
ETO [Member]
Deferred Finance Costs, Noncurrent, Net	207				178
Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage		8.125%
Sunoco LP [Member]
Deferred Finance Costs, Noncurrent, Net	26				23
Transwestern [Member]
Deferred Finance Costs, Noncurrent, Net	$ 1				$ 1
5.80% Senior Notes due 2038 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.80%
Debt Instrument, Maturity Date	Jul. 1, 2038
ETE 7.5% Senior Notes due 2020 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	Oct. 15, 2020
5.875% Senior Notes due January 15, 2024 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Debt Instrument, Maturity Date	Jan. 15, 2024
5.875% Senior Notes due January 15, 2024 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%		5.875%
Debt Instrument, Maturity Date	Jan. 15, 2024
5.5% Senior Notes due June 1, 2027 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Jun. 1, 2027
5.5% Senior Notes due June 1, 2027 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%		5.50%
Debt Instrument, Maturity Date	Jun. 1, 2027
4.25% Senior Notes due March 15, 2023 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Debt Instrument, Maturity Date	Mar. 15, 2023
4.25% Senior Notes due March 15, 2023 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.25%		4.25%
Debt Instrument, Maturity Date	Mar. 15, 2023
4.20% Senior Notes due 2023 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.20%
Debt Instrument, Maturity Date	Sep. 15, 2023
9.7% Senior Notes, due March 15, 2019 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.70%			9.70%
Debt Instrument, Maturity Date	Mar. 15, 2019
9.0% Senior Notes due April 15, 2019 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%			9.00%
Debt Instrument, Maturity Date	Apr. 15, 2019
4.15% Senior Notes due October 1, 2020 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.15%
Debt Instrument, Maturity Date	Oct. 1, 2020
7.50% Senior Notes Due 2020 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%		7.50%
Debt Instrument, Maturity Date	Oct. 15, 2020
Senior Notes 4.65% Due June 1, 2021 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	Jun. 1, 2021
Senior Notes 5.20% Due February 1, 2022 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.20%
Debt Instrument, Maturity Date	Feb. 1, 2022
3.6% Senior Notes due February 1, 2023 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.60%
Debt Instrument, Maturity Date	Feb. 1, 2023
4.9% Senior Notes due February 1, 2024 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.90%
Debt Instrument, Maturity Date	Feb. 1, 2024
4.90% Senior Notes due March 2035 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.90%
Debt Instrument, Maturity Date	Mar. 15, 2035
7.5% Senior Notes, due July 1, 2038 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	Jul. 1, 2038
Senior Notes 6.05% Due June 1, 2041 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.85%
Debt Instrument, Maturity Date	Jun. 1, 2041
Senior Notes 6.50% Due February 1, 2042 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.05%
Debt Instrument, Maturity Date	Feb. 1, 2042
5.15% Senior Notes due February 1, 2043 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.95%
Debt Instrument, Maturity Date	Feb. 1, 2043
5.95% Senior Notes due October 1, 2043 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Debt Instrument, Maturity Date	Oct. 1, 2043
5.15% Senior Notes due March 2045 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.30%
Debt Instrument, Maturity Date	Mar. 15, 2045
6.125% Senior Notes due December 2045 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.35%
Debt Instrument, Maturity Date	May 15, 2045
5.30% Senior Notes due April 2047 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument, Maturity Date	Apr. 1, 2047
5.40% Senior Notes due October 1, 2047 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.30%
Debt Instrument, Maturity Date	Oct. 1, 2047
6.0% Senior Notes due 2048 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Debt Instrument, Maturity Date	Jun. 15, 2048
6.25% Senior Notes due 2049 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.25%			6.25%
Debt Instrument, Maturity Date	Apr. 15, 2049
8.125% Senior Notes, due June 1, 2019 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.13%			8.125%
Debt Instrument, Maturity Date	Jun. 1, 2019
7.00% Senior Notes, due July 15, 2029 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Debt Instrument, Maturity Date	Jul. 15, 2029
5.75% Senior Notes due September 1, 2020 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument, Maturity Date	Sep. 1, 2020
5.875% Senior Notes due April 1, 2022 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Debt Instrument, Maturity Date	Mar. 1, 2022
4.5% Senior Notes due November 1, 2023 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Debt Instrument, Maturity Date	Nov. 1, 2023
5.0% Senior Notes due October 1, 2022 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Debt Instrument, Maturity Date	Oct. 1, 2022
7.60% Senior Notes, due February 1, 2024 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt Instrument, Maturity Date	Feb. 1, 2024
7.60% Senior Notes, due February 1, 2024 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt Instrument, Maturity Date	Feb. 1, 2024
4.05% Senior Notes due March 2025 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.05%
Debt Instrument, Maturity Date	Mar. 15, 2025
4.75% Senior Notes due January 2026 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.75%
Debt Instrument, Maturity Date	Jan. 15, 2026
8.25% Senior Notes, due November 14, 2029 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Debt Instrument, Maturity Date	Nov. 15, 2029
8.25% Senior Notes, due November 14, 2029 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.20%
Debt Instrument, Maturity Date	Nov. 15, 2029
7.2% Junior Subordinated Notes due November 21, 2066 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.40%
9.00% Debentures, due 2024 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%
Debt Instrument, Maturity Date	Nov. 1, 2024
5.50% Senior Notes, due February 15, 2020 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Feb. 15, 2020
4.40% Senior Notes due April 2021 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.40%
Debt Instrument, Maturity Date	Apr. 1, 2021
Senior Note 4.65% Due February 15, 2022 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	Feb. 15, 2022
3.45% Senior Notes due January 2023 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.45%
Debt Instrument, Maturity Date	Feb. 1, 2023
4.25% Senior Notes due April 1, 2024 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Debt Instrument, Maturity Date	Apr. 1, 2024
5.95% Senior Notes due December 2025 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt Instrument, Maturity Date	Dec. 1, 2025
3.90% Senior Notes due July 15, 2026 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.90%
Debt Instrument, Maturity Date	Jul. 15, 2026
4.20% Senior Notes due April 2027 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.20%
Debt Instrument, Maturity Date	Apr. 15, 2027
4.00% Senior Notes due October 1, 2027 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.00%
Debt Instrument, Maturity Date	Oct. 1, 2027
4.95% Senior Notes due 2028 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.95%
Debt Instrument, Maturity Date	Jun. 15, 2028
5.25% Senior Notes due 2029 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.25%			5.25%
Debt Instrument, Maturity Date	Apr. 15, 2029
6.85% Senior Notes, due February 15, 2040 [Member] | ETO [Member]
Debt Instrument, Maturity Date	Feb. 15, 2040
Senior Note 6.10%, due February 15, 2042 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Maturity Date	Feb. 15, 2042
4.95% Senior Notes due January 2043 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.10%
Debt Instrument, Maturity Date	Jan. 15, 2043
5.30% Senior Notes due April 1, 2044 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt Instrument, Maturity Date	Apr. 1, 2044
5.35% Senior Notes due May 15, 2045 [Member] | ETO [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Debt Instrument, Maturity Date	Dec. 15, 2045
5.36% Senior Unsecured Notes, due December 9, 2020 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.36%
Debt Instrument, Maturity Date	Dec. 9, 2020
5.89% Senior Unsecured Notes, due May 24, 2022 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.89%
Debt Instrument, Maturity Date	May 24, 2022
5.66% Senior Unsecured Notes, due December 9, 2024 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.66%
Debt Instrument, Maturity Date	Dec. 9, 2024
6.16% Senior Unsecured Notes, due May 24, 2037 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.16%
Debt Instrument, Maturity Date	May 24, 2037
6.875% Senior notes due April 2026 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.88%
Debt Instrument, Maturity Date	Apr. 1, 2026
3.625% Senior Notes due 2022 [Member] | Bakken Pipeline [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.63%
Debt Instrument, Maturity Date	Apr. 1, 2022
3.90% Senior Notes due 2024 [Member] | Bakken Pipeline [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.90%
Debt Instrument, Maturity Date	Apr. 1, 2024
4.625% Senior Notes due 2029 [Member] | Bakken Pipeline [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.63%
Debt Instrument, Maturity Date	Apr. 1, 2029
4.875% senior notes due 2023 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.88%
Debt Instrument, Maturity Date	Jan. 15, 2023
5.5% Senior Notes due August 2020 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Feb. 15, 2026
6.00% Senior Notes due April 15, 2027 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Debt Instrument, Maturity Date	Apr. 15, 2027
5.875% senior notes due 2028 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Debt Instrument, Maturity Date	Mar. 15, 2028
6.875% Senior Notes due September 2027 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.88%
Debt Instrument, Maturity Date	Sep. 1, 2027

Redeemable Preferred Units (Det

Redeemable Preferred Units (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2018	Dec. 31, 2019	Jan. 31, 2021	Dec. 31, 2018	Apr. 02, 2018
Redeemable noncontrolling interests		$ 739		$ 499
USAC [Member]
Redeemable noncontrolling interests		477
ETO [Member]
Redeemable noncontrolling interests		15
SemCAMS [Member]
Redeemable noncontrolling interests		$ 247
Preferred Stock, Shares Outstanding		300,000
Preferred Units [Member] | USAC [Member]
Preferred Units, Issued					500,000
Shares Issued, Price Per Share					$ 1,000
Proceeds from Issuance of Preferred Limited Partners Units	$ 500
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 24.375
Preferred Stock, Redemption Terms		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.
Preferred Units [Member] | SemCAMS [Member]
Preferred Units, Issued		315,859
Subsequent Event [Member]
Preferred Stock, Redemption Price Per Share			$ 845
Canada, Dollars | Subsequent Event [Member]
Preferred Stock, Redemption Price Per Share			$ 1,100

Equity (Narrative) (Details)

Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 01, 2020	Jul. 31, 2019	Apr. 30, 2019	Oct. 31, 2018	Jul. 31, 2018	May 31, 2018	Apr. 30, 2018	Feb. 28, 2018	Jan. 31, 2018	Nov. 30, 2017	Feb. 28, 2017	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		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 31, 2021	Jan. 31, 2020	Jul. 30, 2019	Apr. 02, 2018
Stock Issued During Period, Shares, New Issues																														14,500,000	2,300,000	32,200,000
Stock Repurchase Program, Authorized Amount												$ 2,000																		$ 2,000
Partners' Capital Account, Unit-based Payment Arrangement, Number of Units																														57,600,000	1,458,900,000	0
Stock Repurchase Program, Remaining Authorized Repurchase Amount												$ 911																		$ 911
Minimum beneficial percentage ownership, other than the Partnership's General Partner and its affiliates, no voting rights, not considered outstanding												20.00%																		20.00%
Limited Partners' Capital Account, Units Outstanding												2,689,600,000				2,619,368,605				1,079,100,000								1,046,900,000		2,689,600,000	2,619,368,605	1,079,100,000
Stock Issued During Period, Shares, Conversion of Units						79,100,000
Limited Partner interest in the Partnership, percentage																														99.90%
Units repurchased under buyback program																														$ 25	$ 0	$ 0
Equity Distribution Agreements, Value of Units Available to be Issued												$ 1,000																		1,000
Stock Issued During Period, Value, Dividend Reinvestment Plan																														$ 148
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan												29,000,000																		29,000,000
Proceeds from Issuance of Common Limited Partners Units																														$ 0	$ 0	$ 568
Parent Company [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit												$ 0.3050	$ 0.3050	$ 0.3050	$ 0.3050	$ 0.3050	$ 0.3050	$ 0.3050	$ 0.3050	$ 0.3050	[1]	$ 0.2950	[1]	$ 0.2850	[1]	$ 0.2850	[1]	$ 0.2850	[1]
PennTex [Member]
Sale of Stock, Price Per Share																								20
Phillips 66 Company [Member] | Dakota Access and ETCOC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest											25.00%
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																		28,500,000
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
Stock Repurchased During Period, Shares								17,286,859
Units repurchased under buyback program								$ 540
USAC [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.																39,700,000															39,700,000				46,100,000
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
Limited Partners' Capital Account, Units Outstanding												96,600,000																		96,600,000
Stock Issued During Period, Value, Dividend Reinvestment Plan																														$ 1	$ 0.6
Stock Issued During Period, Shares, Dividend Reinvestment Plan																														60,584	39,280
Bakken Holdings Company LLC [Member] | Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest											49.00%
Bakken Pipeline Investments LLC [Member] | Dakota Access and ETCOC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest											75.00%
Convertible Preferred Stock [Member]
Limited Partners' Capital Account, Units Outstanding						329,300,000
Series A Preferred Units [Member]
Preferred Stock, Shares Issued										950,000
Preferred Stock, Dividend Rate, Percentage										6.25%
Shares Issued, Price Per Share										$ 1,000
Preferred Units, Liquidation Spread, Percent										4.028%
Series A Preferred Units [Member] | Sunoco LP [Member]
Payments for Repurchase of Preferred Stock and Preference Stock									$ 300																	$ 300
Stock Repurchased and Retired During Period, Shares																										12,000,000
Preferred Stock, Dividend Rate, Percentage																										10.00%
Preferred Stock, Liquidation Preference Per Share																										$ 25
Preferred Units, Liquidation Spread, Percent																										8.00%
Preferred Stock Redemption Premium									$ 313
Call premium on preferred units.									1.00%
Series C Preferred Units [Member]
Preferred Stock, Shares Issued							18,000,000
Preferred Stock, Dividend Rate, Percentage							7.375%
Shares Issued, Price Per Share							$ 25
Preferred Units, Liquidation Spread, Percent							4.53%
Preferred Stock, Redemption Price Per Share							$ 25
Series B Preferred Units [Member]
Preferred Stock, Shares Issued										550,000
Preferred Stock, Dividend Rate, Percentage										6.625%
Shares Issued, Price Per Share										$ 1,000
Preferred Units, Liquidation Spread, Percent										4.155%
Series D Preferred Units [Member]
Preferred Stock, Dividend Rate, Percentage					7.625%
Shares Issued, Price Per Share					$ 25					$ 25
Preferred Stock, Liquidation Preference Per Share					$ 17,800,000
Preferred Units, Liquidation Spread, Percent					4.738%
Preferred Stock, Redemption Price Per Share										$ 25
Series E Preferred Units [Member]
Preferred Stock, Dividend Rate, Percentage			7.60%
Shares Issued, Price Per Share			$ 25
Preferred Units, Liquidation Spread, Percent			5.161%
Preferred Stock, Redemption Price Per Share			$ 25
Preferred Units, Outstanding			32,000,000
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															6,400,000
Partners' Capital Account, Units, Converted		6,397,965
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																		101,500,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit																												0.67275
Cash Distributions, Percent												1.50%																		1.50%
Class L Units [Member]
Cash Distributions, Percent												7.65%																		7.65%
Class M Units [Member]
Preferred Stock, Dividend Rate, Percentage																														8.00%
ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction				1,460,000,000
ETE Merger [Member] | Sunoco LP [Member]
Sale of Stock, Number of Shares Issued in Transaction				2,263,158												2,263,158
ETE Merger [Member] | USAC [Member]
Limited Partner interest in the Partnership, percentage				100.00%												100.00%
Sale of Stock, Number of Shares Issued in Transaction				12,466,912												12,466,912
USAC [Member]
Stock Issued During Period, Shares, Conversion of Units		6,397,965
Class D Units [Member]
Stock Issued During Period, Shares, New Issues																														0	79,100,000	0
Series A Convertible Preferred Units [Member]
Units repurchased under buyback program																														$ 0
ETE Class A Units [Member] | ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction				647,745,099
Series A Convertible Preferred Units [Member] | Parent Company [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit																			$ 0.1100	$ 0.1100		$ 0.1100		$ 0.1100		$ 0.1100		$ 0.11
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]
Equity Distribution Agreements, Value of Units Available to be Issued												$ 295																		$ 295
Partners' Capital Account, Units, Sale of Units																														0	1,300,000
Proceeds from Issuance of Common Limited Partners Units																															$ 33
Payments for Commissions																															$ 0.3
Subsequent Event [Member]
Preferred Stock, Redemption Price Per Share																																	$ 845
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%
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%
[1]	Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received ET Series A Convertible Preferred Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $ 0.11 per unit. See additional information below.

Equity (Change In ETE Common Un

Equity (Change In ETE Common Units) (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stock Issued During Period, Shares, New Issues	14,500,000	2,300,000	32,200,000
Outstanding	2,689,600,000	2,619,368,605	1,079,100,000	1,046,900,000
Issuance of restricted Common Units under long-term incentive plans	(57,600,000)	(1,458,900,000)	0
Partners' Capital Account, Units, Treasury Units Purchased	(1,900,000)	0	0
Number of Common Units, end of period	2,689,600,000	2,619,368,605	1,079,100,000
Class D Units [Member]
Stock Issued During Period, Shares, New Issues	0	79,100,000	0

Equity (Quarterly Distributions

Equity (Quarterly Distributions Of Available Cash) (Details) - $ / shares		3 Months Ended
		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		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016
Parent Company [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.3050	$ 0.3050	$ 0.3050		$ 0.3050	$ 0.3050	$ 0.3050		$ 0.3050		$ 0.3050	$ 0.3050	[1]	$ 0.2950	[1]	$ 0.2850	[1]	$ 0.2850	[1]	$ 0.2850	[1]
USAC [Member]
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
Sunoco LP [Member]
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
Series A Convertible Preferred Units [Member] | Parent Company [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit												$ 0.1100	0.1100		$ 0.1100		$ 0.1100		$ 0.1100		$ 0.11
Minimum Quarterly Distribution [Member]
Distribution Payment Targets							$0.4375
First Target Distribution [Member]
Distribution Payment Targets							$0.4375 to $0.503125
Second Target Distribution [Member]
Distribution Payment Targets							$0.503125 to $0.546875
Third Target Distribution [Member]
Distribution Payment Targets							$0.546875 to $0.656250
Thereafter [Member]
Distribution Payment Targets							Above $0.656250
IDRs [Member] | Minimum Quarterly Distribution [Member]
Distribution Payment Targets							—%
IDRs [Member] | First Target Distribution [Member]
Distribution Payment Targets							—%
IDRs [Member] | Second Target Distribution [Member]
Distribution Payment Targets							15%
IDRs [Member] | Third Target Distribution [Member]
Distribution Payment Targets							25%
IDRs [Member] | Thereafter [Member]
Distribution Payment Targets							50%
Limited Partner [Member] | Minimum Quarterly Distribution [Member]
Distribution Payment Targets							100%
Limited Partner [Member] | First Target Distribution [Member]
Distribution Payment Targets							100%
Limited Partner [Member] | Second Target Distribution [Member]
Distribution Payment Targets							85%
Limited Partner [Member] | Third Target Distribution [Member]
Distribution Payment Targets							75%
Limited Partner [Member] | Thereafter [Member]
Distribution Payment Targets							50%
Series A Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[2]	31.2500	0	31.2500		0	$ 31.2500	0		31.2500			15.4510	[3]
Series B Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[2]	33.1250	0	33.1250		0	33.1250	0		33.1250			16.3780
Series C Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		0.4609	0.4609	0.4609		0.4609	0.4609	0.4609		0.5634	[3]		0
Series D Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		0.4766	0.4766	0.4766		0.4766	0.4766	0.5931	[3]	0			0
Series E Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.4750	$ 0.4750	$ 0.5806	[3]	$ 0	$ 0	$ 0		$ 0			$ 0
[1]	Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received ET Series A Convertible Preferred Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $ 0.11 per unit. See additional information below.
[2]	(1) ETO Series A Preferred Units and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.
[3]	* Represent prorated initial distributions. Prorated initial distributions on the recently issued ETO Series F Preferred Units and ETO Series G Preferred Units will be payable in May 2020.

Equity (Accumulated Other Compr

Equity (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Partners' Capital Notes [Abstract]
Unrealized gains on available-for-sale securities	$ 13	$ 2
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Gain (Loss) Arising During Period, Net of Tax	2	(5)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax	(25)	(48)
AOCI attributable to equity method investments	(1)	9
AOCI Including Portion Attributable to Noncontrolling Interest, Tax	(11)	(42)
Total AOCI included in partners' capital, net of tax	$ (11)	$ (42)

Equity Tax amounts in component

Equity Tax amounts in components of other comprehensive income (loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Other Comprehensive Income Loss Commodity Hedges Tax	$ (1)	$ (1)
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax	2	2
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized (Gain) Loss Arising During Period, Tax	8	12
Other Comprehensive Income (Loss), Tax	$ 9	$ 13

ETE Unit-Based Compensation Pla

ETE Unit-Based Compensation Plans (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	Dec. 05, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stock Issued During Period, Shares, New Issues		14.5	2.3	32.2
ETE Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		6.5
Sunoco LP Unit Based Compensation Plans [Member]
Awards granted		8.9
Weighted Average Grant-Date Fair Value Per Unit, Awards granted		$ 12.51	$ 13	$ 17.01
Unvested awards		28	22.4
Weighted Average Grant-Date Fair Value Per Unit		$ 13.89	$ 15.94
Units Vested In Period		(4)
Weighted Average Grant-Date Fair Value Per Unit, Awards vested		$ 21.09
Fair Value Of Units As Of The Vesting Date		$ 47	$ 49	$ 40
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount		$ 258
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term		2 years 7 months 6 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period		(0.7)
Weighted Average Grant-Date Fair Value Per Unit, Awards forfeited		$ 15.70
SemGroup Compensation Plans [Member] [Member]
Awards granted	1.4
Weighted Average Grant-Date Fair Value Per Unit, Awards granted	$ 11.60

Non-Cash Compensation Plans Sub

Non-Cash Compensation Plans Subsidiary Unit-Based Compensation Plans (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Subsidiary Unit Based Compensation [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair Value Of Units As Of The Vesting Date	$ 17	$ 22	$ 9
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 57
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	3 years 7 months 6 days
Sunoco LP Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	2.1	2.1
Weighted Average Grant-Date Fair Value Per Unit	$ 29.21	$ 29.15
Awards granted	0.7
Weighted Average Grant-Date Fair Value Per Unit, Awards granted	$ 30.70	$ 27.67	$ 28.31
Awards vested	(0.5)
Weighted Average Grant-Date Fair Value Per Unit, Awards vested	$ 30.04
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	0.2
Weighted Average Grant-Date Fair Value Per Unit, Awards forfeited	$ 28.16
USAC Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	1.8	1.4
Weighted Average Grant-Date Fair Value Per Unit	$ 15.09	$ 14.98
Awards granted	0.7
Weighted Average Grant-Date Fair Value Per Unit, Awards granted	$ 15.88	$ 15.47
Awards vested	(0.3)
Weighted Average Grant-Date Fair Value Per Unit, Awards vested	$ 13.06
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	0
Weighted Average Grant-Date Fair Value Per Unit, Awards forfeited	$ 16.78

Non-Cash Compensation Plans U_2

Non-Cash Compensation Plans Unit-based compensation Narrative (Details) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2018	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / shares
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ 0	$ 0	$ (1,812)
ET Unit Based Compensation Plans [Member]
Weighted Average Grant-Date Fair Value Per Unit, Awards granted | $ / shares		$ 12.51	$ 13	$ 17.01
Fair Value Of Units As Of The Vesting Date		$ 47	$ 49	$ 40
Unvested awards | shares		28	22.4
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount		$ 258
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term		2 years 7 months 6 days
Subsidiary Unit Based Compensation [Member]
Fair Value Of Units As Of The Vesting Date		$ 17	$ 22	$ 9
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount		$ 57
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term		3 years 7 months 6 days
ETE Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.28

Income Taxes Narrative (Details

Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Oct. 31, 2019
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	$ 1,100
Deferred Tax Liabilities, Gross	4,141	$ 3,826
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	90
Net operating losses, alternative minimum tax credit and other carryforwards	936	768
Valuation allowance	(95)	(96)
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, Ater Tax	72
State	(2)	19	$ (16)
Unrecognized Tax Benefits, Interest on Income Taxes Expense	1
Income Tax Examination, Penalties and Interest Accrued	3
Deferred Income Tax Expense (Benefit)	217	(7)	(1,871)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	0	$ 0	$ (1,812)
Tax Credit Carryforward, Valuation Allowance	49
ETP Holdco and other corporate subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	2,650
SemGroup [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	766
Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Net operating losses, alternative minimum tax credit and other carryforwards	15
Deferred Tax Asset, Interest Carryforward	$ 35
Holdco [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Jan. 1, 2031
Sunoco, Inc. [Member]
Operating Loss Carryforwards [Line Items]
Estimated Litigation Liability				$ 530
Net of federal tax [Member]
Operating Loss Carryforwards [Line Items]
State	$ 53
Maximum [Member] | Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037
Minimum [Member] | Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date	Jan. 1, 2020
Expiring between 2031 and 2037 [Member] | SemGroup [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 185
Reclassed to current income tax receivable within 12 months [Member]
Operating Loss Carryforwards [Line Items]
Net operating losses, alternative minimum tax credit and other carryforwards	8
Expiring between 2020 and 2038 [Member] | Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	118
Expiring in 2033 [Member] | Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	68
Expiring in 2020 [Member] | Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	45
Pennsylvania Constitution [Member]
Operating Loss Carryforwards [Line Items]
State	67
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	34
Pennsylvania Constitution [Member] | Net of federal tax [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	27
Canada, Dollars | Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforward, Valuation Allowance	$ 46

Income Taxes Components of Inco

Income Taxes Components of Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current expense (benefit):
Federal	$ (20)	$ (8)	$ 54
State	(2)	19	(16)
Total	(22)	11	38
Deferred expense (benefit):
Federal	174	181	(2,055)
State	43	(188)	184
Total	217	(7)	(1,871)
Total income tax expense (benefit) from continuing operations	$ 195	$ 4	$ (1,833)

Income Taxes Reconciliation of

Income Taxes Reconciliation of Income Tax Satutory Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Effective Income Tax Rate Reconciliation, Change in Tax Status of Subsidiary	$ 0	$ 0	$ (124)
Income tax expense at United States statutory rate	1,070	763	248
Increase (reduction) in income taxes resulting from:
Goodwill impairment	0	0	207
Partnership earnings not subject to tax	(882)	(635)	(477)
State tax, net of federal tax benefit	12	(125)	124
Dividend received deduction	(3)	(5)	(14)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	0	0	(1,812)
Other	(2)	6	15
Total income tax expense (benefit) from continuing operations	$ 195	$ 4	$ (1,833)

Income Taxes Effects of Tempora

Income Taxes Effects of Temporary Differences That Comprise Net Deffered Income Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred income tax assets:
Net operating losses, alternative minimum tax credit and other carryforwards	$ 936	$ 768
Pension and other postretirement benefits	7	34
Long-term debt	0	13
Other	85	181
Deferred Tax Assets, Gross	1,028	996
Valuation allowance	(95)	(96)
Net deferred income tax assets	933	900
Deferred income tax liabilities:
Property, plant and equipment	(501)	(782)
Investments in affiliates	(3,547)	(2,872)
Trademarks	(72)	(63)
Other	(21)	(109)
Deferred Tax Liabilities, Gross	4,141	3,826
Deferred Tax Liabilities	$ (3,208)	$ (2,926)

Income Taxes Components of Net

Income Taxes Components of Net Deferred Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Components of Net Deferred Income Tax [Abstract]
Total deferred income tax assets	$ 1,028	$ 996
Deferred Tax Liabilities, Net	(3,208)	(2,926)
Valuation allowance	95	96
Net deferred income tax assets	$ 933	$ 900

Income Taxes Changes in Unrecog

Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Changes in Unrecognized Tax Benefits [Abstract]
Balance at beginning of year	$ 624	$ 609	$ 615
Additions attributable to tax positions taken in the current year	0	8	0
Additions attributable to tax positions taken in prior years	11	7	28
Reduction attributable to tax positions taken in prior years	(541)	0	(25)
Lapse of statute	0	0	9
Balance at end of year	$ 94	$ 624	$ 609

Regulatory Matters, Commitmen_3

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Limited Partner interest in the Partnership, percentage	99.90%
Operating Leases, Rent Expense	$ 45,000,000	$ 46,000,000	$ 46,000,000
Payments for Environmental Liabilities	39,000,000	48,000,000
Accrual for loss contingency	0
Loss Contingency, Estimate of Possible Loss	80,000,000
Total environmental liabilities	$ 320,000,000	337,000,000
Site Contingency, Number of Sites Needing Remediation	40
Long-term Debt	$ 51,054,000,000	46,028,000,000
PES [Member]
Limited Partner interest in the Partnership, percentage	7.40%
Debt Instrument, Debt Default, Amount	$ 75,000,000
Sunoco LP [Member]
Long-term Debt	3,071,000,000	2,984,000,000
Rover Pipeline LLC [Member]
Proposed Environmental Penalty	2,600,000
SPLP and Mid-Valley Pipeline [Member]
Loss Contingency, Damages Awarded, Value	5,400,000
Related To Deductibles [Member]
Accrual for loss contingency	$ 120,000,000	56,000,000
4.875% senior notes due 2023 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.88%
Senior Notes	$ 1,000,000,000	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]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Senior Notes	$ 400,000,000	$ 400,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount	536,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount	1,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount	595,000,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount	$ 319,000,000

Regulatory Matters, Commitmen_4

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Environmental Remediation Obligations [Abstract]
Current		$ 42
Non-current		295
Total environmental liabilities	$ 320	$ 337

Revenue Narrative (Details)

Revenue Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Sunoco LP [Member]
Capitalized Contract Cost, Amortization	$ 17	$ 14

Revenue Contracts with customer

Revenue Contracts with customers (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2019	Jan. 01, 2018
Contract with Customer, Liability	$ 377	$ 394		$ 221
Deferred Revenue, Additions	664	765
Contract with Customer, Liability, Revenue Recognized	$ (681)	(592)
Sunoco LP [Member]
Contract with Customer, Liability		1	$ 0
Receivables from Customers		347	366
Contract with Customer, Asset, after Allowance for Credit Loss		$ 75	$ 117

Revenue Revenue, future obligat

Revenue Revenue, future obligations (Details) $ in Millions	Dec. 31, 2019USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-12-31
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 6,232
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	5,300
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	4,899
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	27,158
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 43,589

Lease Accounting Leasee Account

Lease Accounting Leasee Accounting(Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Rental Income, Nonoperating	$ 149
Operating Lease, Weighted Average Remaining Lease Term	24 years
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 104
Operating Lease, Cost	117
Operating Lease, Right-of-Use Asset	1,000	$ 0		$ 889
Operating Lease, Liability, Current	60	0		71
Accrued and other current liabilities	3,342	2,918		2,917
Operating Lease, Liability, Noncurrent	901	0		823
Property, Plant and Equipment, Net	74,193	66,963		66,962
Current maturities of long-term debt	26	2,655		2,656
Long-term debt, less current maturities	51,028	43,373		43,379
Other non-current liabilities	1,162	1,184		$ 1,172
Finance Lease, Interest Expense	1
Lease, Cost	136
Lease, Cost, Gross	183
Net Cash Provided by (Used in) Financing Activities	(1,197)	$ (3,082)	$ 953
Finance Lease, Liability, Payments, Remainder of Fiscal Year	8
Lease Liabilities, Remainder of Year	112
Lessee, Operating Lease, Liability, Payments, Due Year Two	96
Finance Lease, Liability, Payments, Due Year Two	8
Lease Liabilities, Due Year Two	104
Lessee, Operating Lease, Liability, Payments, Due Year Three	83
Finance Lease, Liability, Payments, Due Year Three	8
Lease Liabilities, Due Year Three	91
Lessee, Operating Lease, Liability, Payments, Due Year Four	77
Finance Lease, Liability, Payments, Due Year Four	7
Lease Liabilities, Due Year Four	84
Lessee, Operating Lease, Liability, Payments, Due Year Five	74
Finance Lease, Liability, Payments, Due Year Five	4
Lease Liabilities, Due Year Five	78
Lessee, Operating Lease, Liability, Payments, Due after Year Five	1,342
Finance Lease, Liability, Payments, Due after Year Five	5
Lease Liabilities, Due After Five Years	1,347
Lessee, Operating Lease, Liability, Payments, Due	1,776
Finance Lease, Liability, Payment, Due	40
Lease Liabilities, Due	1,816
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	815
Finance Lease, Liability, Undiscounted Excess Amount	5
Lease Liability, Undiscounted Excess Amount	820
Operating Lease, Liability	961
Finance Lease, Liability	35
Lease, Liabilities	$ 996
Finance Lease, Weighted Average Remaining Lease Term	5 years
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	$ 28
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	40
Operating Leases [Member]
Net Cash Provided by (Used in) Operating Activities	(159)
Operating Lease, Right-of-Use Asset	935
Operating Lease, Liability, Current	60
Accrued and other current liabilities	1
Operating Lease, Liability, Noncurrent	901
Finance Leases [Member]
Accrued and other current liabilities	1
Property, Plant and Equipment, Net	1
Finance Lease, Right-of-Use Asset	29
Current maturities of long-term debt	6
Long-term debt, less current maturities	26
Other non-current liabilities	2
Lease, Cost	7
Cost of Goods and Service Benchmark [Member]
Operating Lease, Cost	28
Operating Expense [Member]
Operating Lease, Cost	73
Short-term Lease, Cost	42
Variable Lease, Cost	17
Selling, General and Administrative Expenses [Member]
Operating Lease, Cost	16
Depreciation And Amortization [Member]
Finance Lease, Right-of-Use Asset, Amortization	6
Other Revenue [Member]
Sublease Income	$ 47
ETO [Member]
Operating Lease, Weighted Average Discount Rate, Percent	5.00%
Finance Lease, Weighted Average Discount Rate, Percent	5.00%
Real Estate [Member]
Lessee, Operating Lease, Term of Contract	40 years
Minimum [Member]
Lessee, Operating Lease, Renewal Term	1 year
Minimum [Member] | Equipment [Member]
Lessee, Operating Lease, Term of Contract	5 years
Maximum [Member]
Lessee, Operating Lease, Renewal Term	20 years
Maximum [Member] | Equipment [Member]
Lessee, Operating Lease, Term of Contract	15 years

Lease Accounting Lessor Account

Lease Accounting Lessor Accounting (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Rental Income, Nonoperating	$ 149
Lessor, Operating Lease, Payments to be Received, Next Twelve Months	138
Lessor, Operating Lease, Payments to be Received, Two Years	112
Lessor, Operating Lease, Payments to be Received, Three Years	75
Lessor, Operating Lease, Payments to be Received, Four Years	20
Lessor, Operating Lease, Payments to be Received, Five Years	15
Lessor, Operating Lease, Payments to be Received, Thereafter	12
Lessor, Operating Lease, Payments to be Received	$ 372

Derivative Assets And Liabili_3

Derivative Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details)		Dec. 31, 2019MWbarrelsBBtuMB_blsbushels	Dec. 31, 2018MWMMbtubarrelsBBtubushels
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member]
Derivative, Nonmonetary Notional Amount		(9,265)
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount		(3,085)	(1,068)
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount		(18,923)	(30,228)
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member]
Derivative, Nonmonetary Notional Amount		(13,364)	(123,254)
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount	[1]	(35,208)
Natural Gas [Member] | Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount		(31,780)	(17,445)
Natural Gas [Member] | Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount		(31,780)	(17,445)
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member]
Derivative, Nonmonetary Notional Amount			(54,158)
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount		(1,483)	(468)
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount	[1]		(16,845)
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount		0	(10,000)
Natural Gas [Member] | Long [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member]
Derivative, Nonmonetary Notional Amount		(31,780)	(17,445)
Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount | MW		(2,704,330)
Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | MW		(353,527)
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount | MW			(284,800)
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forward Swaps [Member]
Derivative, Nonmonetary Notional Amount | MW		(3,213,450)	(3,141,520)
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | MW			(56,656)
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member]
Derivative, Nonmonetary Notional Amount | MW		(51,615)	(18,400)
Natural Gas Liquids [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member]
Derivative, Nonmonetary Notional Amount		(1,300)	(2,135)
Refined Products [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount		(2,473)	(1,403)
Corn [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | bushels		(1,210)	(1,920)
Crude Oil [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member]
Derivative, Nonmonetary Notional Amount | barrels		(4,465)	(20,888)
[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 Liabili_4

Derivative Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) - Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
March 2019 [Member]
Notional Amount		$ 0	$ 300
Type	[1]	Pay a floating rate and receive a fixed rate of 1.42%
July 2019 [Member] | Forward-Starting Swaps [Member]
Notional Amount	[2],[3]	$ 400	400
Type	[1],[2],[3]	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate
July 2021 [Member] | Forward-Starting Swaps [Member]
Notional Amount	[3]	$ 400	400
Type	[1],[3]	Forward-starting to pay a fixed rate of 3.55% and receive a floating rate
July 2018 [Member] | Forward-Starting Swaps [Member]
Notional Amount	[3]	$ 0	400
Type	[1],[3]	Forward-starting to pay a fixed rate of 3.56% and receive a floating rate
July 2022 [Member] | Forward-Starting Swaps [Member]
Notional Amount	[3]	$ 400	$ 0
Type	[1],[3]	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
[1]	Floating rates are based on 3-month LIBOR.
[2]	The July 2020 interest rate swaps were terminated in January 2020.
[3]	Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

Derivative Assets And Liabili_5

Derivative Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Asset Derivatives	$ 384	$ 560
Liability Derivatives	(788)	(746)
Designated as Hedging Instrument [Member]
Asset Derivatives	24	0
Liability Derivatives	0	(13)
Not Designated as Hedging Instrument [Member]
Asset Derivatives	360	560
Liability Derivatives	(788)	(733)
Broker cleared derivative contracts [Member]
Asset Derivatives	343	402
Liability Derivatives	(350)	(410)
Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Asset Derivatives	41	158
Liability Derivatives	(39)	(173)
Commodity Derivatives (Margin Deposits) [Member] | Designated as Hedging Instrument [Member]
Asset Derivatives	24	0
Liability Derivatives	0	(13)
Commodity Derivatives (Margin Deposits) [Member] | Not Designated as Hedging Instrument [Member]
Asset Derivatives	319	402
Liability Derivatives	(350)	(397)
Interest Rate Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Asset Derivatives	0	0
Liability Derivatives	$ (399)	$ (163)

Derivative Assets And Liabili_6

Derivative Assets And Liabilities Derivative Assets and Lianilities (Offsetting Agreements Netting Table) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Asset Derivatives	$ 384	$ 560
Derivative Liability, Fair Value, Gross Liability	(788)	(746)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(18)	(47)
Derivative Liability, Fair Value, Amount Offset Against Collateral	18	47
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(318)	(397)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	318	397
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	48	116
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	452	302
Without offsetting agreements [Member]
Asset Derivatives	0	0
Derivative Liability, Fair Value, Gross Liability	(399)	(163)
OTC Contracts [Member]
Asset Derivatives	41	158
Derivative Liability, Fair Value, Gross Liability	(39)	(173)
Broker cleared derivative contracts [Member]
Asset Derivatives	343	402
Derivative Liability, Fair Value, Gross Liability	$ (350)	$ (410)

Derivative Assets And Liabili_7

Derivative Assets And Liabilities (Derivatives Recognized OCI On Derivatives) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cost of Sales [Member] | Commodity Derivatives [Member]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 0	$ (3)	$ 26

Derivative Assets And Liabili_8

Derivative Assets And Liabilities (Derivative Amount Of Gain (Loss) Recognized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (301)	$ (23)	$ 0
Gains (losses) on interest rate derivatives	(241)	47	(37)
Commodity Derivatives [Member] | Cost of Sales [Member]
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	0	(3)	26
Embedded Derivatives in Preferred Units [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	0	0	1
Non Trading [Member] | Commodity Derivatives [Member] | Cost of Sales [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(78)	(102)	5
Trading [Member] | Commodity Derivatives [Member] | Trading Revenue [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(3)	0	0
Trading [Member] | Commodity Derivatives [Member] | Cost of Sales [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 21	$ 32	$ 31

Retirement Benefits (Narrative)

Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Retirement Benefits [Line Items]
Defined Contribution Plan, Cost	$ 66	$ 62	$ 59
Sunoco [Member]
Retirement Benefits [Line Items]
Liability, Other Postretirement Defined Benefit Plan, Noncurrent	$ 200
Pension Benefits
Retirement Benefits [Line Items]
Large Cap US Equitiies	100.00%	100.00%
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 7
Other Postretirement Benefits
Retirement Benefits [Line Items]
Large Cap US Equitiies	59.00%	53.00%
Fixed Income Securities	40.00%	46.00%
Cash Fund Investments	1.00%	1.00%
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 8
Minimum [Member] | Other Postretirement Benefits | Equity [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Plan Assets, Investment within Plan Asset Category, Percentage	25.00%
Minimum [Member] | Other Postretirement Benefits | Fixed Income Investments [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Plan Assets, Investment within Plan Asset Category, Percentage	65.00%
Maximum [Member] | Other Postretirement Benefits | Equity [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Plan Assets, Investment within Plan Asset Category, Percentage	35.00%
Maximum [Member] | Other Postretirement Benefits | Fixed Income Investments [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Plan Assets, Investment within Plan Asset Category, Percentage	75.00%
Funded Plans [Member] | Pension Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	$ 1

Retirement Benefits (Obligation

Retirement Benefits (Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Change in benefit obligation:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	$ 0	$ 0
Change in plan assets:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0	0
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	0	0
Change in benefit obligation:
Defined Benefit Plan, Interest Cost	3	1
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	43
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position		0
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		0
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	1	1
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	198	156
Defined Benefit Plan, Interest Cost	7	5
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	60
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	(16)	(17)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	18	(7)
Defined Benefit Plan, Benefit Obligation	208	198
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	241	257
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)	35	(8)
Defined Benefit Plan, Plan Assets, Contributions by Employer	10	9
Defined Benefit Plan, Plan Assets, Amount	270	241
Defined Benefit Plan, Funded (Unfunded) Status of Plan	(62)	(43)
Amounts recognized in the consolidated balance sheets consist of:
Assets for Plan Benefits, Defined Benefit Plan	88	68
Liability, Defined Benefit Plan, Current	(2)	(2)
Liability, Defined Benefit Plan, Noncurrent	(24)	(23)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	62	43
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Reclassification Adjustment, before Tax	(5)	(7)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	40	66
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	35	59
Defined Benefit Plan, Plan Assets, Benefits Paid	(16)	(17)
Funded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	(4)
Change in plan assets:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	(4)
Funded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	0
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	1	1
Defined Benefit Plan, Interest Cost	2	0
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	(1)	0
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	4	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0
Defined Benefit Plan, Benefit Obligation	52	1
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	1	1
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)	6	0
Defined Benefit Plan, Plan Assets, Contributions by Employer	1	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0
Defined Benefit Plan, Plan Assets, Amount	43	1
Defined Benefit Plan, Funded (Unfunded) Status of Plan	9	0
Amounts recognized in the consolidated balance sheets consist of:
Assets for Plan Benefits, Defined Benefit Plan	0	0
Liability, Defined Benefit Plan, Current	0	0
Liability, Defined Benefit Plan, Noncurrent	(9)	0
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	(9)
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Reclassification Adjustment, before Tax	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	0
Defined Benefit Plan, Plan Assets, Benefits Paid	(1)	0
Unfunded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0	0
Change in plan assets:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0	0
Unfunded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	0	0
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	37	47
Defined Benefit Plan, Interest Cost	1	1
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	(7)	(7)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	0	(4)
Defined Benefit Plan, Benefit Obligation	34	37
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	0	0
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)	0	0
Defined Benefit Plan, Plan Assets, Contributions by Employer	0	0
Defined Benefit Plan, Plan Assets, Amount	0	0
Defined Benefit Plan, Funded (Unfunded) Status of Plan	34	37
Amounts recognized in the consolidated balance sheets consist of:
Assets for Plan Benefits, Defined Benefit Plan	0	0
Liability, Defined Benefit Plan, Current	(5)	(6)
Liability, Defined Benefit Plan, Noncurrent	(29)	(31)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	(34)	(37)
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Reclassification Adjustment, before Tax	1	1
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	1	1
Defined Benefit Plan, Plan Assets, Benefits Paid	0	0
SemGroup Compensation Plans [Member] [Member]
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	0
Defined Benefit Plan, Benefit Obligation	0	0
SemGroup Compensation Plans [Member] [Member] | Other Postretirement Benefits
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	0
Defined Benefit Plan, Plan Assets, Amount	0	0
SemGroup Compensation Plans [Member] [Member] | Funded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	50
SemGroup Compensation Plans [Member] [Member] | Funded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	0
Defined Benefit Plan, Benefit Obligation		0
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	0
Defined Benefit Plan, Plan Assets, Amount	40	0
SemGroup Compensation Plans [Member] [Member] | Unfunded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	0
Defined Benefit Plan, Benefit Obligation	3	0
SemGroup Compensation Plans [Member] [Member] | Unfunded Plans [Member] | Pension Benefits
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	0
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0

Retirement Benefits (Accumulate

Retirement Benefits (Accumulated Benefit Obligation In Excess of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets		$ 241
Funded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	$ 51	0
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets		1
Unfunded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	$ 34	37
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets		$ 0

Retirement Benefits (Net Period

Retirement Benefits (Net Periodic Benefit Costs Schedule) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	$ 0	$ 0
Defined Benefit Plan, Interest Cost	3	1
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	2	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	1	1
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	1	1
Defined Benefit Plan, Interest Cost	7	5
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	10	10
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	26	16
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 24	$ 12

Retirement Benefits (Benefit As

Retirement Benefits (Benefit Assumptions) (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year	7.25%	7.15%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	4.83%	4.82%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.00%	4.02%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.33%	3.52%
Expected long term return on assets, tax exempt accounts	3.37%	3.26%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.71%	3.40%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.76%	3.51%
Expected long term return on assets, tax exempt accounts	7.00%	6.63%
Expected long term return on assets, taxable accounts	4.75%	4.50%

Retirement Benefits (Fair Value

Retirement Benefits (Fair Value of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Benefit Obligation	$ 208	$ 198	$ 156
Defined Benefit Plan, Plan Assets, Amount	270	241	257
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets		241
Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	43
Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	14	20
Cash and Cash Equivalents [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	1
Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	177	144
Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	19	1
Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	79	77
Fixed Income Securities [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	23
Level 1 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	191	164
Level 1 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	20
Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	14	20
Level 1 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	1
Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	177	144
Level 1 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	19	1
Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Level 1 [Member] | Fixed Income Securities [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0
Level 2 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	79	77
Level 2 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	23
Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Level 2 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0
Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Level 2 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	79	77
Level 2 [Member] | Fixed Income Securities [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	23
Level 3 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Level 3 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0
Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Level 3 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0
Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Level 3 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Level 3 [Member] | Fixed Income Securities [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0
Funded Plans [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	51	0
Defined Benefit Plan, Benefit Obligation	52	1	1
Defined Benefit Plan, Plan Assets, Amount	43	1	1
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets		1
Unfunded Plans [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	34	37
Defined Benefit Plan, Benefit Obligation	34	37	47
Defined Benefit Plan, Plan Assets, Amount	$ 0	0	$ 0
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets		$ 0

Retirement Benefits (Benefit Pa

Retirement Benefits (Benefit Payments) (Details) $ in Millions	Dec. 31, 2019USD ($)
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member]
Defined Benefit Plan Disclosure [Line Items]
2020	$ 20	[1]
2021	20
2022	19
2023	18
2024	15
2025-2029	67
Unfunded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2020	7	[1]
2021	8
2022	8
2023	8
2024	7
2025-2029	$ 22
[1]	Expected benefit payments of funded pension plans are less than $1 million for the next ten years.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Accounts payable to related companies	$ 31	$ 59
Revenue	492	431	$ 303
Accounts Receivable, Related Parties, Current	159	111
FGT [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	50	25
Other Related Parties [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	31	44
Phillips 66 Company [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	36	42
Traverse Rover LLC [Member]
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	$ 42	$ 0

Reportable Segments Revenue (De

Reportable Segments Revenue (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	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, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue from External Customer [Line Items]
Revenues	$ 13,720	$ 13,495	$ 13,877	$ 13,121	$ 13,573	$ 14,514	$ 14,118	$ 11,882	$ 54,213	$ 54,087	$ 40,523
Investment In USAC [Member]
Revenue from External Customer [Line Items]
Revenues									698	508	0
Intersegment Eliminations [Member]
Revenue from External Customer [Line Items]
Revenues									(5,951)	(7,039)	(5,609)
Other Segments [Member]
Revenue from External Customer [Line Items]
Revenues									1,689	2,228	2,901
Crude oil transportation and services [Member]
Revenue from External Customer [Line Items]
Revenues									18,447	17,332	11,703
NGL and refined products transportation and services [Member]
Revenue from External Customer [Line Items]
Revenues									11,641	11,123	8,648
Midstream [Member]
Revenue from External Customer [Line Items]
Revenues									6,031	7,522	6,943
Interstate Transportation and Storage [Member]
Revenue from External Customer [Line Items]
Revenues									1,963	1,682	1,131
Intrastate Transportation And Storage [Member]
Revenue from External Customer [Line Items]
Revenues									3,099	3,737	3,083
Investment In Sunoco LP [Member]
Revenue from External Customer [Line Items]
Revenues									16,596	16,994	11,723
Intersegment [Member] | Investment In USAC [Member]
Revenue from External Customer [Line Items]
Revenues									20	13	0
Intersegment [Member] | Other Segments [Member]
Revenue from External Customer [Line Items]
Revenues									81	155	161
Intersegment [Member] | Crude oil transportation and services [Member]
Revenue from External Customer [Line Items]
Revenues									0	96	31
Intersegment [Member] | NGL and refined products transportation and services [Member]
Revenue from External Customer [Line Items]
Revenues									1,721	1,004	763
Intersegment [Member] | Midstream [Member]
Revenue from External Customer [Line Items]
Revenues									3,751	5,432	4,433
Intersegment [Member] | Interstate Transportation and Storage [Member]
Revenue from External Customer [Line Items]
Revenues									22	18	19
Intersegment [Member] | Intrastate Transportation And Storage [Member]
Revenue from External Customer [Line Items]
Revenues									350	309	192
Intersegment [Member] | Investment In Sunoco LP [Member]
Revenue from External Customer [Line Items]
Revenues									6	12	10
External Customers [Member] | Investment In USAC [Member]
Revenue from External Customer [Line Items]
Revenues									678	495	0
External Customers [Member] | Other Segments [Member]
Revenue from External Customer [Line Items]
Revenues									1,608	2,073	2,740
External Customers [Member] | Crude oil transportation and services [Member]
Revenue from External Customer [Line Items]
Revenues									18,447	17,236	11,672
External Customers [Member] | NGL and refined products transportation and services [Member]
Revenue from External Customer [Line Items]
Revenues									9,920	10,119	7,885
External Customers [Member] | Midstream [Member]
Revenue from External Customer [Line Items]
Revenues									2,280	2,090	2,510
External Customers [Member] | Interstate Transportation and Storage [Member]
Revenue from External Customer [Line Items]
Revenues									1,941	1,664	1,112
External Customers [Member] | Intrastate Transportation And Storage [Member]
Revenue from External Customer [Line Items]
Revenues									2,749	3,428	2,891
External Customers [Member] | Investment In Sunoco LP [Member]
Revenue from External Customer [Line Items]
Revenues									$ 16,590	$ 16,982	$ 11,713

Reportable Segments (Operating

Reportable Segments (Operating Segments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cost of Goods and Services Sold	$ 39,727	$ 41,658	$ 30,966
Depreciation, depletion and amortization	3,147	2,859	2,554
Equity in earnings of unconsolidated affiliates	302	344	144
Intrastate Transportation And Storage [Member]
Cost of Goods and Services Sold	1,909	2,665	2,327
Depreciation, depletion and amortization	184	169	147
Equity in earnings of unconsolidated affiliates	18	19	(156)
Investment In Sunoco LP [Member]
Cost of Goods and Services Sold	15,380	15,872	10,615
Depreciation, depletion and amortization	181	167	169
Interstate Transportation and Storage [Member]
Depreciation, depletion and amortization	387	334	254
Equity in earnings of unconsolidated affiliates	222	227	236
Midstream [Member]
Cost of Goods and Services Sold	3,577	5,145	4,761
Depreciation, depletion and amortization	1,066	1,006	954
Equity in earnings of unconsolidated affiliates	20	26	20
NGL and refined products transportation and services [Member]
Cost of Goods and Services Sold	8,393	8,462	6,508
Depreciation, depletion and amortization	613	466	401
Equity in earnings of unconsolidated affiliates	53	64	33
Crude oil transportation and services [Member]
Cost of Goods and Services Sold	14,758	14,439	9,826
Depreciation, depletion and amortization	437	445	402
Equity in earnings of unconsolidated affiliates	(1)	6	4
Other Segments [Member]
Cost of Goods and Services Sold	1,504	2,006	2,509
Depreciation, depletion and amortization	48	103	227
Equity in earnings of unconsolidated affiliates	(10)	2	7
Investment In USAC [Member]
Cost of Goods and Services Sold	91	67	0
Depreciation, depletion and amortization	231	169	0
Intersegment Eliminations [Member]
Cost of Goods and Services Sold	$ (5,885)	$ (6,998)	$ (5,580)

Reportable Segments Reportable

Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	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, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA									$ 11,214	$ 9,510	$ 7,320
Depreciation, depletion and amortization									(3,147)	(2,859)	(2,554)
Interest expense, net of interest capitalized									(2,331)	(2,055)	(1,922)
Impairment losses									(74)	(431)	(1,039)
Gains (losses) on interest rate derivatives									(241)	47	(37)
Unrealized gains (losses) on commodity risk management activities									(113)	(105)	(99)
Non-cash compensation expense									5	11	(59)
Losses on extinguishments of debt									(18)	(112)	(89)
Adjusted EBITDA related to unconsolidated affiliates									79	(85)	24
Equity in earnings of unconsolidated affiliates									0	25	(223)
Impairment of investments in unconsolidated affiliates									0	0	(313)
Impairment of investments in unconsolidated affiliates									(626)	(655)	(716)
Equity in earnings of unconsolidated affiliates									302	344	144
Other, net									54	21	155
Income from continuing operations before income tax (expense) benefit									5,094	3,634	710
Income tax expense (benefit) from continuing operations									(195)	(4)	1,833
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent					$ 852	$ 1,393	$ 659	$ 726	4,899	3,630	2,543
Loss from discontinued operations									0	(265)	(177)
Net income	$ 1,350	$ 1,161	$ 1,208	$ 1,180	$ 852	$ 1,391	$ 633	$ 489	4,899	3,365	2,366
Intrastate Transportation And Storage [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA									999	927	626
Depreciation, depletion and amortization									(184)	(169)	(147)
Equity in earnings of unconsolidated affiliates									18	19	(156)
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA									665	638	732
Depreciation, depletion and amortization									(181)	(167)	(169)
Investment In USAC [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA									420	289	0
Depreciation, depletion and amortization									(231)	(169)	0
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA									98	40	187
Interstate Transportation and Storage [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA									1,792	1,680	1,274
Depreciation, depletion and amortization									(387)	(334)	(254)
Equity in earnings of unconsolidated affiliates									222	227	236
Midstream [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA									1,602	1,627	1,481
Depreciation, depletion and amortization									(1,066)	(1,006)	(954)
Equity in earnings of unconsolidated affiliates									20	26	20
NGL and refined products transportation and services [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA									2,666	1,979	1,641
Depreciation, depletion and amortization									(613)	(466)	(401)
Equity in earnings of unconsolidated affiliates									53	64	33
Crude oil transportation and services [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA									2,972	2,330	1,379
Depreciation, depletion and amortization									(437)	(445)	(402)
Equity in earnings of unconsolidated affiliates									$ (1)	$ 6	$ 4

Reportable Segments (Assets Seg

Reportable Segments (Assets Segments) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Assets	$ 98,880	$ 88,246	$ 86,246
Intrastate Transportation And Storage [Member]
Assets	6,648	6,365	5,020
Interstate Transportation and Storage [Member]
Assets	18,111	15,081	15,316
Midstream [Member]
Assets	20,332	19,745	20,004
NGL and refined products transportation and services [Member]
Assets	19,145	18,267	17,600
Crude oil transportation and services [Member]
Assets	22,840	18,022	17,730
Investment In Sunoco LP [Member]
Assets	5,438	4,879	8,344
Investment In USAC [Member]
Assets	3,730	3,775	0
Corporate and Other [Member]
Assets	$ 2,636	$ 2,112	$ 2,232

Reporting Segments (Additions T

Reporting Segments (Additions To Property Plant And Equipment Including Acquisitions Net Of Contributions In Aid Of Construction Costs Segments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	$ 5,268	$ 5,630	$ 6,006
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	$ 148	$ 103	$ 103
[1]	Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis).

Reportable Segments (Advances t

Reportable Segments (Advances to and investments in affiliates) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	$ 5,268	$ 5,630	$ 6,006
Advances to and investments in unconsolidated affiliates		3,460	2,642	2,705
Intrastate Transportation And Storage [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	124	344	175
Advances to and investments in unconsolidated affiliates		88	83	85
Interstate Transportation and Storage [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	375	812	728
Advances to and investments in unconsolidated affiliates		2,524	2,070	2,118
Midstream [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	827	1,161	1,308
Advances to and investments in unconsolidated affiliates		112	124	126
NGL and refined products transportation and services [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	2,976	2,381	2,971
Advances to and investments in unconsolidated affiliates		461	243	234
Crude oil transportation and services [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	403	474	453
Advances to and investments in unconsolidated affiliates		242	28	22
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	148	103	103
Investment In USAC [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	200	205	0
Other Segments [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	215	150	268
Advances to and investments in unconsolidated affiliates		$ 33	$ 94	$ 120
[1]	Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis).

Quarterly Financial Data (Una_3

Quarterly Financial Data (Unaudited) (Schedule of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	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, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 13,720	$ 13,495	$ 13,877	$ 13,121	$ 13,573	$ 14,514	$ 14,118	$ 11,882	$ 54,213	$ 54,087	$ 40,523
Operating income	1,701	1,830	1,819	1,927	1,419	1,703	1,126	1,100	7,277	5,348	2,721
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent					852	1,393	659	726	4,899	3,630	2,543
Net income	1,350	1,161	1,208	1,180	852	1,391	633	489	4,899	3,365	2,366
Limited Partners’ interest in net income	$ 1,011	$ 831	$ 877	$ 869	$ 617	$ 370	$ 330	$ 341	$ 3,588	$ 1,658	$ 915
Basic	$ 0.38	$ 0.32	$ 0.33	$ 0.33	$ 0.26	$ 0.32	$ 0.30	$ 0.31	$ 1.37	$ 1.16	$ 0.85
Diluted	0.38	0.32	0.33	0.33	0.26	0.32	0.30	0.31	1.36	1.15	0.83
Basic	0.38	0.32	0.33	0.33	0.26	0.32	0.30	0.32	1.37	1.17	0.86
Diluted	$ 0.38	$ 0.32	$ 0.33	$ 0.33	$ 0.26	$ 0.32	$ 0.30	$ 0.32	$ 1.36	$ 1.16	$ 0.84

Quarterly Financial Data (Una_4

Quarterly Financial Data (Unaudited) Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Statement [Abstract]
Impairment losses	$ 74	$ 431	$ 1,039
Impairment of investments in unconsolidated affiliates	$ 0	$ 0	$ 313