0001276187-23-000014 | 10-K | XBRL Viewer

Print Document View Excel Document

Cover Page Cover Page - USD ($) $ in Millions	12 Months Ended
Cover Page Cover Page - USD ($) $ in Millions	Dec. 31, 2022	Feb. 10, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
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
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			$ 26,730
Entity Common Stock, Shares Outstanding		3,094,593,760
Documents Incorporated by Reference	None
Entity Central Index Key	0001276187
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Amendment Flag	false
ICFR Auditor Attestation Flag	true
Document Information [Line Items]
Document Transition Report	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Auditor Firm ID	248
Auditor Location	Dallas, Texas
Auditor Name	GRANT THORNTON LLP
Common Stock
Cover [Abstract]
Title of 12(b) Security	Common Units
Trading Symbol	ET
Security Exchange Name	NYSE
Document Information [Line Items]
Title of 12(b) Security	Common Units
Trading Symbol	ET
Security Exchange Name	NYSE
ETprC
Cover [Abstract]
Title of 12(b) Security	7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprC
Security Exchange Name	NYSE
Document Information [Line Items]
Title of 12(b) Security	7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprC
Security Exchange Name	NYSE
ETprD
Cover [Abstract]
Title of 12(b) Security	7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprD
Security Exchange Name	NYSE
Document Information [Line Items]
Title of 12(b) Security	7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprD
Security Exchange Name	NYSE
ETprE
Cover [Abstract]
Title of 12(b) Security	7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprE
Security Exchange Name	NYSE
Document Information [Line Items]
Title of 12(b) Security	7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprE
Security Exchange Name	NYSE

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
ASSETS
Cash and cash equivalents	$ 257	$ 336
Accounts receivable, net	8,466	7,654
Accounts receivable from related companies	93	54
Inventories	2,461	2,014
Income taxes receivable	68	32
Derivative assets	10	10
Other current assets	726	437
Total current assets	12,081	10,537
Property, plant and equipment	105,996	103,991
Accumulated depreciation and depletion	(25,685)	(22,384)
Property, Plant and Equipment, Net	80,311	81,607
Investments in unconsolidated affiliates	2,893	2,947
Lease right-of-use assets, net	819	838
Other non-current assets, net	1,558	1,645
Intangible assets, net	5,415	5,856
Goodwill	2,566	2,533
Total assets	105,643	105,963
LIABILITIES AND EQUITY
Accounts payable	6,952	6,834
Accounts payable to related companies	17	0
Derivative liabilities	23	203
Operating lease current liabilities	45	47
Accrued and other current liabilities	3,329	3,071
Current maturities of long-term debt	2	680
Total current liabilities	10,368	10,835
Long-term debt, less current maturities	48,260	49,022
Non-current derivative liabilities	23	193
Non-current operating lease liabilities	798	814
Deferred income taxes	3,701	3,648
Other non-current liabilities	1,341	1,323
Commitments and contingencies
Redeemable noncontrolling interests	493	783
Limited Partners:
Preferred Unitholders (72,184,780 and 72,184,780 units authorized, issued and outstanding as of December 31, 2022 and 2021, respectively)	6,051	6,051
Common Unitholders (3,094,445,367 and 3,082,517,494 units authorized, issued and outstanding as of December 31, 2022 and 2021, respectively)	26,960	25,230
General Partner	(2)	(4)
Accumulated other comprehensive income	16	23
Total partners’ capital	33,025	31,300
Noncontrolling interests	7,634	8,045
Total equity	40,659	39,345
Total liabilities and equity	$ 105,643	$ 105,963

Consolidated Balance Sheets Balance Sheet (Paranthetical) - shares	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Authorized	3,094,425,367	3,082,497,494
Issued	3,094,425,367	3,082,497,494
Outstanding	3,094,425,367	3,082,497,494
Preferred Units, Authorized	72,184,780	72,184,780
Preferred Units, Issued	72,184,780	72,184,780
Preferred Units, Outstanding	72,184,780	72,184,780

Consolidated Statements Of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
REVENUES:
Total revenues	$ 89,876	$ 67,417	$ 38,954
COSTS AND EXPENSES:
Cost of products sold	72,232	50,395	25,487
Operating expenses	4,338	3,574	3,218
Depreciation, depletion and amortization	4,164	3,817	3,678
Selling, general and administrative	1,018	818	711
Impairment losses and other	386	21	2,880
Total costs and expenses	82,138	58,625	35,974
OPERATING INCOME	7,738	8,792	2,980
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(2,306)	(2,267)	(2,327)
Equity in earnings of unconsolidated affiliates	257	246	119
Impairment of investments in unconsolidated affiliates	0	0	(129)
Losses on extinguishments of debt	0	(38)	(75)
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments	293	61	(203)
Other, net	90	77	12
Income before income tax expense	6,072	6,871	377
Income tax expense	204	184	237
NET INCOME	5,868	6,687	140
Less: Net income attributable to noncontrolling interests	1,061	1,167	739
Less: Net income attributable to redeemable noncontrolling interests	51	50	49
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS	4,756	5,470	(648)
General Partner’s interest in net income (loss)	4	6	(1)
Preferred Unitholders’ interest in net income	422	285	0
Limited Partners’ interest in net income	$ 4,330	$ 5,179	$ (647)
NET INCOME (LOSS) PER COMMON UNIT:
Basic	$ 1.40	$ 1.89	$ (0.24)
Diluted	$ 1.40	$ 1.89	$ (0.24)
Refined product sales
REVENUES:
REVENUES:	$ 26,020	$ 17,766	$ 10,514
Crude sales
REVENUES:
REVENUES:	23,473	15,299	9,442
Natural gas sales
REVENUES:
REVENUES:	8,535	9,159	2,633
Gathering, transportation and other fees
REVENUES:
REVENUES:	10,907	9,229	8,982
NGL sales
REVENUES:
REVENUES:	20,114	15,243	6,797
Other
REVENUES:
REVENUES:	$ 827	$ 721	$ 586

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 5,868	$ 6,687	$ 140
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	(10)	1	5
Actuarial gain (loss) relating to pension and other postretirement benefits	(12)	12	18
Foreign currency translation adjustment	(6)	4	5
Change in other comprehensive income from unconsolidated affiliates	24	3	(13)
Other comprehensive income (loss), net of tax, total	(4)	20	15
Comprehensive income	5,864	6,707	155
Less: Comprehensive income attributable to noncontrolling interests	1,055	1,170	738
Less: Comprehensive income attributable to redeemable noncontrolling interests	51	50	49
Comprehensive income (loss) attributable to partners	$ 4,758	$ 5,487	$ (632)

Consolidated Statement Of Equity - USD ($) $ in Thousands	Total	General Partner	Accumulated Other Comprehensive Income (Loss)	Common Unitholders	Non- controlling Interests	Preferred Unitholders	Rollup Mergers	Rollup Mergers General Partner	Rollup Mergers Accumulated Other Comprehensive Income (Loss)	Rollup Mergers Common Unitholders	Rollup Mergers Non- controlling Interests	Rollup Mergers Preferred Unitholders
Balance at Dec. 31, 2019	$ 33,938,000	$ (4,000)	$ (11,000)	$ 21,935,000	$ 12,018,000	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(2,802,000)	(3,000)	0	(2,799,000)	0	0
Distributions to noncontrolling interests	(1,651,000)	0	0	0	(1,651,000)	0
Common units repurchased under buyback program	0
Subsidiary unit transactions	1,580,000	0	0	0	1,580,000	0
Capital contributions from noncontrolling interests	222,000	0	0	0	222,000	0
Other, net	(5,000)	0	1,000	42,000	(48,000)	0
Other comprehensive income, net of tax	15,000	0	16,000	0	(1,000)	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	91,000	(1,000)	0	(647,000)	739,000	0
Balance at Dec. 31, 2020	31,388,000	(8,000)	6,000	18,531,000	12,859,000	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(1,898,000)	(2,000)	0	(1,616,000)	0	(280,000)
Distributions to noncontrolling interests	(1,487,000)	0	0	0	(1,487,000)	0
Common units repurchased	(31,000)	0	0	(31,000)	0	0
Common units repurchased under buyback program	(31,000)
Units issued	889,000	0	0	0	0	889,000
Capital contributions from noncontrolling interests	226,000	0	0	0	226,000	0
Other, net	58,000	0	0	50,000	11,000	(3,000)
Partners' Capital Account, Acquisitions	3,543,000	0	0	3,117,000	34,000	392,000	$ 0	$ 0	$ 0	$ 0	$ (4,768,000)	$ 4,768,000
Other comprehensive income, net of tax	20,000	0	17,000	0	3,000	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	6,637,000	6,000	0	5,179,000	1,167,000	285,000
Balance at Dec. 31, 2021	39,345,000	(4,000)	23,000	25,230,000	8,045,000	6,051,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(3,047,000)	(2,000)	0	(2,623,000)	0	(422,000)
Distributions to noncontrolling interests	(1,547,000)	0	0	0	(1,547,000)	0
Common units repurchased under buyback program	0
Capital contributions from noncontrolling interests	405,000	0	0	0	405,000	0
Noncontrolling Interest, Decrease from Deconsolidation	(346,000)	0	(9,000)	0	(337,000)	0
Other, net	36,000	0	0	23,000	13,000	0
Other comprehensive income, net of tax	(4,000)	0	2,000	0	(6,000)	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	5,817,000	4,000	0	4,330,000	1,061,000	422,000
Balance at Dec. 31, 2022	$ 40,659,000	$ (2,000)	$ 16,000	$ 26,960,000	$ 7,634,000	$ 6,051,000

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 5,868	$ 6,687	$ 140
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	4,164	3,817	3,678
Deferred Income Tax Expense (Benefit)	187	141	210
Inventory valuation adjustments	(5)	(190)	82
Non-cash compensation expense	115	111	121
Impairment losses and other	386	21	2,880
Impairment of investment in unconsolidated affiliates	0	0	129
Losses on extinguishments of debt	0	38	75
Distributions on unvested awards	73	47	41
Distributions from unconsolidated affiliates	232	212	220
Equity in earnings of unconsolidated affiliates	(257)	(246)	(119)
Other non-cash	64	(103)	61
Net change in operating assets and liabilities, net of effects of acquisitions	(1,502)	515	47
Net cash provided by operating activities	9,051	11,162	7,361
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	(1,141)	(205)	0
Capital expenditures, excluding allowance for equity funds used during construction	(3,381)	(2,822)	(5,130)
Contributions in aid of construction costs	56	43	67
Contributions to unconsolidated affiliates	0	(4)	(38)
Distributions from unconsolidated affiliates in excess of cumulative earnings	62	167	187
Proceeds from Sale of Equity Method Investments	302	0	0
Proceeds from sales of other assets	78	45	19
Other	2	1	(3)
Net cash used in investing activities	(4,022)	(2,775)	(4,898)
FINANCING ACTIVITIES:
Proceeds from borrowings	28,838	21,267	24,440
Repayments of debt	(29,681)	(27,318)	(24,133)
Preferred units issued for cash	0	889	0
Subsidiary units issued for cash	0	0	1,580
Distributions to partners	(3,047)	(1,898)	(2,802)
Distributions to noncontrolling interests	(1,547)	(1,487)	(1,651)
Distributions to redeemable noncontrolling interests	49	49	49
Common units repurchased under buyback program	0	(31)	0
Debt issuance costs	(27)	(14)	(59)
Capital contributions from noncontrolling interests	405	226	222
Other, net	0	(3)	65
Net cash used in financing activities	(5,108)	(8,418)	(2,387)
Increase (decrease) in cash and cash equivalents	(79)	(31)	76
Cash and cash equivalents, beginning of period	336	367	291
Cash and cash equivalents, end of period	$ 257	$ 336	$ 367

Operations And Organization	12 Months Ended
Operations And Organization	Dec. 31, 2022
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 “Energy Transfer”). On April 1, 2021, Energy Transfer, ETO and certain of ETO’s subsidiaries consummated several internal reorganization transactions (the “Rollup Mergers”). In connection with the Rollup Mergers, ETO merged with and into Energy Transfer, with Energy Transfer surviving. The impacts of the Rollup Mergers also included the following: •All of ETO’s long-term debt was assumed by Energy Transfer, as more fully described in Note 6. •Each issued and outstanding ETO preferred unit was converted into the right to receive one newly created Energy Transfer preferred unit. A description of the Energy Transfer Preferred Units is included in Note 8. •Each of ETO’s issued and outstanding Class K, Class L, Class M and Class N units were converted into an aggregate 675,625,000 newly created Class B Units representing limited partner interests in Energy Transfer. All of the Class B Units are held by ETP Holdco, a wholly-owned subsidiary of Energy Transfer. In November 2022, Energy Transfer and Panhandle completed an internal reorganization which resulted in Energy Transfer assuming all of Panhandle’s notes and debentures, as more fully discussed in Note 6. Our financial statements reflect the following reportable segments: •intrastate transportation and storage; •interstate transportation and storage; •midstream; •NGL and refined products transportation and services; •crude oil transportation and services; •investment in Sunoco LP; •investment in USAC; and •all other. The Partnership owns and operates intrastate natural gas pipeline systems and storage facilities that are engaged in the business of purchasing, gathering, transporting, processing and marketing natural gas and NGLs in the states of Texas, Oklahoma and Louisiana. The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States. The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Permian, Anadarko, Arkoma and Hugoton basins, as well as the Eagle Ford, Haynesville, Barnett, Marcellus and Utica shales. The Partnership owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products. The Partnership owns a controlling interest in Sunoco LP which is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites. As of December 31, 2022, 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, 2022, our interest in USAC consisted of 100% of the general partner and 46.1 million common units. Basis of Presentation. The consolidated financial statements of Energy Transfer LP presented herein for the years ended December 31, 2022, 2021 and 2020, 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 Energy Transfer presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC.

Estimates, Significant Accounting Policies and Balance Sheet Detail

12 Months Ended

Dec. 31, 2022

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.

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, in accordance with Accounting Standards Codification (“ASC”) Topic 980. 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 under ASC Topic 980 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 NGA and NGPA, Panhandle does not currently apply ASC Topic 980 in its GAAP-basis consolidated financial statements, 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,
	2022		2021		2020
Accounts receivable	$	(863)	$	(3,356)	$	1,163
Accounts receivable from related companies	23		38		(290)
Inventories	(361)		(19)		(271)
Other current assets	(326)		(216)		172
Other non-current assets, net	146		1		(7)
Accounts payable	25		3,834		(1,327)
Accounts payable to related companies	6		(34)		367
Accrued and other current liabilities	131		238		163
Other non-current liabilities	66		117		8
Derivative assets and liabilities, net	(349)		(88)		69
Net change in operating assets and liabilities, net of effects of acquisitions	$	(1,502)	$	515	$	47

Non-cash investing and financing activities and supplemental cash flow information are as follows:


	Years Ended December 31,
	2022		2021		2020
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	$	575	$	464	$	604
Units issued in connection with the Enable Acquisition(1)	—		3,509		—
Lease assets obtained in exchange for new lease liabilities	42		18		42
Acquisition of interest in unconsolidated affiliate	—		49		—






SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	2,167	$	2,188	$	2,092
Cash paid for income taxes (net of refunds)	54		41		(64)

(1)See Note 3 for additional information.

Accounts Receivable

Our operations deal with a variety of counterparties across the energy sector. 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 sector. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for credit losses on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Changes in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due.

Inventories

Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2022 and 2021, Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $116 million and $121 million, respectively. For the years ended December 31, 2022, 2021 and 2020, the Partnership’s consolidated statements of operations and comprehensive income did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. For the years ended December 31, 2022 and 2021, the Partnership’s cost of products sold included favorable inventory adjustments of $5 million and $190 million, respectively, and for year ended December 31, 2020, an unfavorable inventory adjustment of $82 million, related to Sunoco LP’s LIFO inventory.

The Partnership’s inventories consisted of the following:


	December 31,
	2022		2021
Natural gas, NGLs and refined products	$	1,802	$	1,259
Crude oil	246		328
Spare parts and other	413		427
Total inventories	$	2,461	$	2,014

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,
	2022		2021
Deposits paid to vendors	$	334	$	215
Prepaid expenses and other	392		222
Total other current assets	$	726	$	437

Property, Plant and Equipment

Property, plant and equipment is 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 is 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 2022 and 2021, USAC recognized fixed asset impairments of $1 million and $5 million, respectively, related to its compression equipment as a result of its evaluation of the future deployment of idle fleet.

In 2020, the Partnership recognized a $58 million fixed asset impairment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. In addition, USAC recorded an $8 million impairment of compression equipment as a result of its evaluations of the future deployment of its idle fleet.

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,
	2022		2021
Land and improvements	$	1,427	$	1,369
Buildings and improvements (1 to 45 years)	3,546		4,598
Pipelines and equipment (5 to 83 years)	82,353		77,112
Product storage and related facilities (2 to 83 years)	7,274		7,410




Right of way (20 to 83 years)	6,252		5,021




Other (1 to 48 years)	2,739		2,816
Construction work-in-process	2,405		5,665
	105,996		103,991
Less – Accumulated depreciation and depletion	(25,685)		(22,384)
Property, plant and equipment, net	$	80,311	$	81,607

We recognized the following amounts for the periods presented:


	Years Ended December 31,
	2022		2021		2020
Depreciation, depletion and amortization expense	$	3,774	$	3,465	$	3,275
Capitalized interest	112		135		189

Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. During the year ended December 31, 2020, the Partnership recorded an impairment of its investment in White Cliffs of $129 million due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline.

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,
	2022		2021
Crude pipeline linefill and tank bottoms	$	489	$	498
Regulatory assets	55		42
Pension assets	129		140
Deferred charges	140		177
Restricted funds	121		164
Other	624		624
Total other non-current assets, net	$	1,558	$	1,645

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, 2022				December 31, 2021
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	7,884	$	(2,807)	$	7,982	$	(2,464)
Patents (10 years)	48		(48)		48		(44)

Trade names (20 years)	66		(41)		66		(38)
Other (5 to 20 years)	12		(13)		19		(20)
Total amortizable intangible assets	8,010		(2,909)		8,115		(2,566)
Non-amortizable intangible assets:
Trademarks	302		—		295		—
Other	12		—		12		—
Total non-amortizable intangible assets	314		—		307		—
Total intangible assets	$	8,324	$	(2,909)	$	8,422	$	(2,566)

Aggregate amortization expense of intangible assets was as follows:


	Years Ended December 31,
	2022		2021		2020
Reported in depreciation, depletion and amortization expense	$	390	$	352	$	403

Estimated aggregate amortization of intangible assets for the next five years is as follows:


Years Ending December 31:
2023	$	357
2024	344
2025	331
2026	327
2027	309

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test was performed during the fourth quarter.

Changes in the carrying amount of goodwill were 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		Investment in USAC		All Other		Total
Balance, December 31, 2020	$	—	$	—	$	—	$	693	$	52	$	1,564	$	—	$	82	$	2,391
Acquired	—		—		—		—		138		4		—		—		142



Balance, December 31, 2021	—		—		—		693		190		1,568		—		82		2,533
Acquired	—		—		—		—		—		33		—		—		33



Balance, December 31, 2022	$	—	$	—	$	—	$	693	$	190	$	1,601	$	—	$	82	$	2,566

During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. The Partnership performed the interim impairment tests consistent with our approach for annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized goodwill impairments of $483 million related to our Ark-La-Tex and South Texas operations within the midstream segment, $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to contractually scheduled reductions in payments for the remainder of the contract term, and $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations.

During the third quarter of 2020, the Partnership performed interim impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $1.28 billion related to our crude operations, $132 million related to our Energy Transfer Canada operations within the all other segment and $43 million related to our interstate operations primarily due to decreases in projected future cash flow as a result of the overall market demand decline.

During the fourth quarter of 2020, the Partnership performed annual impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $10 million related to our intrastate operations, $11 million related to our PEI operations and $15 million related to our Natural Resources operations within the all other segment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. No other impairments of the Partnership’s goodwill were identified.

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 2021, $138 million of goodwill was recorded in conjunction with the acquisition of Enable. In addition, Sunoco LP recorded $4 million of goodwill in conjunction with its acquisition of eight refined product terminals in 2021 and $33 million of goodwill in conjunction with its acquisitions in 2022.

The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. The fair

value estimates used in the long-lived asset and goodwill tests were primarily based on Level 3 inputs of the fair value hierarchy.

Management does not believe that any of the goodwill balances in its reporting units is currently at significant risk of impairment; however, of the $2.57 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2022, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.

Asset Retirement Obligations

We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an ARO in the periods in which management can reasonably estimate the settlement dates.

As of December 31, 2022 and 2021, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $362 million and $369 million, respectively. For the years ended December 31, 2022, 2021 and 2020 aggregate accretion expense related to AROs was $4 million, $12 million and $16 million, respectively.

Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2022 and 2021, in most cases because the settlement dates were indeterminable. Although a number of onshore assets in our systems are subject to agreements or regulations that give rise to an ARO upon discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Our subsidiaries also have legal obligations for several other assets at previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, our subsidiaries are legally or contractually required to abandon in place or remove the asset. We believe we may have additional AROs related to pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP also has AROs related to the estimated future cost to remove underground storage tanks.

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

As of December 31, 2022 and 2021, other non-current assets on the Partnership’s consolidated balance sheets included $27 million and $39 million, respectively, of funds that were legally restricted for the purpose of settling AROs.

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:


	December 31,
	2022		2021
Interest payable	$	559	$	561
Customer advances and deposits	222		188
Accrued capital expenditures	565		461
Accrued wages and benefits	376		297
Taxes payable other than income taxes	519		384


Exchanges payable	224		155
Deferred revenue	268		158
Other	596		867
Total accrued and other current liabilities	$	3,329	$	3,071

In certain circumstances, customer advances and deposits are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interests

Our redeemable noncontrolling interests relate to certain preferred unitholders of one of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in one of our consolidated subsidiaries that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable noncontrolling interests on our consolidated balance sheets. See Note 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.

We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR or SOFR curve, is based on quotes from an active exchange of futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2022, 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, 2022 and 2021 based on inputs used to derive their fair values:


	Fair Value Total		Fair Value Measurements at December 31, 2022
			Level 1		Level 2
Assets:

Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	60	$	60	$	—
Swing Swaps IFERC	75		75		—
Fixed Swaps/Futures	113		113		—


Forward Physical Contracts	10		—		10
Power:
Forwards	52		—		52
Futures	3		3		—


NGLs – Forwards/Swaps	317		317		—
Refined Products – Futures	20		20		—

Crude – Forwards/Swaps	38		38		—

Total commodity derivatives	688		626		62
Other non-current assets	27		18		9
Total assets	$	715	$	644	$	71
Liabilities:
Interest rate derivatives	$	(23)	$	—	$	(23)

Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(25)		(25)		—
Swing Swaps IFERC	(12)		(12)		—
Fixed Swaps/Futures	(4)		(4)		—


Forward Physical Contracts	(2)		—		(2)
Power:
Forwards	(51)		—		(51)
Futures	(3)		(3)		—


NGLs – Forwards/Swaps	(358)		(358)		—
Refined Products – Futures	(59)		(59)		—
Crude – Forwards/Swaps	(12)		(12)		—
Total commodity derivatives	(526)		(473)		(53)
Total liabilities	$	(549)	$	(473)	$	(76)


	Fair Value Total		Fair Value Measurements at December 31, 2021
			Level 1		Level 2
Assets:

Commodity derivatives:

Natural Gas:
Basis Swaps IFERC/NYMEX	$	7	$	7	$	—
Swing Swaps IFERC	38		38		—
Fixed Swaps/Futures	26		26		—


Forward Physical Contracts	7		—		7
Power:
Forwards	17		—		17
Futures	6		6		—


NGLs – Forwards/Swaps	152		152		—
Refined Products – Futures	3		3		—
Crude - Forwards/Swaps	16		16		—
Total commodity derivatives	272		248		24
Other non-current assets	39		26		13
Total assets	$	311	$	274	$	37
Liabilities:
Interest rate derivatives	$	(387)	$	—	$	(387)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(10)		(10)
Swing Swaps IFERC	(6)		(6)		—
Fixed Swaps/Futures	(9)		(9)		—


Forward Physical Contracts	(6)		—		(6)
Power:
Forwards	(15)				(15)
Futures	(4)		(4)		—


NGLs – Forwards/Swaps	(140)		(140)		—
Refined Products – Futures	(18)		(18)		—
Crude - Forwards/Swaps	(3)		(3)		—

Total commodity derivatives	(211)		(190)		(21)
Total liabilities	$	(598)	$	(190)	$	(408)

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, 2022 was $45.42 billion and $48.26 billion, respectively. As of December 31, 2021, the aggregate fair value and carrying amount of our debt obligations was $54.97 billion and $49.70 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

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.

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

Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership and administrative personnel.

We record the collection of taxes to be remitted to government authorities on a net basis, except for consumer excise taxes collected by Sunoco LP on sales of refined products and merchandise which are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income. For the years ended December 31, 2022, 2021 and 2020, excise taxes collected by Sunoco LP were $285 million, $332 million and $301 million, respectively.

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.

Related Party Transactions

The Partnership regularly enters into related party transactions with several of its unconsolidated affiliates. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. While the Partnership believes that such related party transactions generally reflect market rates, the pricing under such agreements may not be comparable to similar transactions with unaffiliated third parties. For the years ended December 31, 2022, 2021 and 2020, the Partnership’s consolidated income statements reflect revenues from related parties of $391 million, $410 million and $466 million, respectively.

Income Taxes

Energy Transfer 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 Partnership Agreement. We do not have access to information regarding each partner’s individual tax basis in our limited partner interests.

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 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, Energy Transfer would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2022, 2021 and 2020, our qualifying income met the statutory requirement.

The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local, and foreign income taxes. These corporate subsidiaries include ETP Holdco, Sunoco Retail LLC, and Aloha, among others. 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

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.

Equity Incentive Compensation

For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of the underlying common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of the underlying common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.

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

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.

Acquisitions and Related Transactions

12 Months Ended

Dec. 31, 2022

Acquisitions and Dispositions [Abstract]

Acquisitions and Related Transactions

ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

Woodford Express Acquisition

On September 13, 2022, Energy Transfer completed the acquisition of 100% of the membership interests in Woodford Express, LLC, which owns a mid-continent gas gathering and processing system, for approximately $485 million plus working capital. The system, which is located in the heart of the SCOOP play, has 450 MMcf/d of cryogenic gas processing and treating capacity and over 200 miles of gathering lines, which are connected to Energy Transfer’s pipeline network. Woodford Express, LLC repaid aggregate principal of $292 million on its revolving credit facility and term loan on the closing date of the acquisition, which amount is included in the total consideration.

Energy Transfer Canada Sale

In August 2022, the Partnership completed the sale of its 51% interest in Energy Transfer Canada. The sale resulted in cash proceeds to Energy Transfer of $302 million.

Energy Transfer Canada’s assets and operations were included in the Partnership’s all other segment until August 2022. Energy Transfer Canada did not meet the criteria to be reflected as discontinued operations in the Partnership’s consolidated statement of operations. Based on the anticipated proceeds upon signing of the share purchase agreement in February 2022, during the three months ended March 31, 2022, the Partnership recorded a write-down on Energy Transfer Canada’s assets of $300 million, of which $164 million was allocated to noncontrolling interests and $136 million was reflected in net income attributable to partners. Upon the completion of the sale in August 2022, the Partnership recorded an $85 million loss on deconsolidation.

Spindletop Assets Purchase

In March 2022, the Partnership purchased the membership interests in Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC), which owns an underground storage facility near Mont Belvieu, Texas, for approximately $325 million.

Sunoco LP’s Acquisitions

On November 30, 2022, Sunoco LP completed the acquisition of Peerless Oil & Chemicals, Inc., an established terminal operator that distributes fuel products to over 100 locations within Puerto Rico and throughout the Caribbean, for $76 million, net of cash acquired.

On April 1, 2022, Sunoco LP completed the acquisition of a transmix processing and terminal facility in Huntington, Indiana for $252 million, net of cash acquired, of which $98 million was allocated to intangible assets, $20 million to goodwill, $73 million to property, plant and equipment and $76 million to working capital.

Enable Acquisition

On December 2, 2021, the Partnership completed the previously announced merger with Enable (the “Enable Acquisition”). Under the terms of the merger agreement, Enable’s common unitholders received 0.8595 of an Energy Transfer common unit in exchange for each Enable common unit. In addition, each outstanding Enable Series A preferred unit was exchanged for 0.0265 of an Energy Transfer Series G Preferred Unit. A total of 384,780 Series G Preferred Units were issued in connection with the Enable Acquisition. The total fair value of Energy Transfer common units and Series G Preferred Units issued was approximately $3.5 billion at the closing date. Energy Transfer also made a $10 million cash payment for Enable’s general partner and assumed $3.18 billion aggregate principal amount of Enable senior notes. In addition, Enable’s $800 million term loan and $35 million revolving credit facility were repaid and terminated in December 2021, immediately subsequent to the close of the Enable Acquisition.

The Enable Acquisition 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 estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the utilization of an independent valuation specialist, if

applicable, and involves the use of significant estimates and assumptions. Acquired assets were valued based on a combination of the discounted cash flow, the guideline company and the reproduction and replacement methods.

The following table summarizes the allocation of the purchase price among the assets acquired and liabilities assumed:


	At December 2, 2021
Total current assets	$	593
Property, plant and equipment, net	7,076
Investments in unconsolidated affiliates	40

Other non-current assets	39
Intangible assets, net	440
Goodwill	138
Total assets	8,326

Total current liabilities	488
Long-term debt, less current maturities(1)	4,267
Other non-current liabilities	18
Total liabilities	4,773

Noncontrolling interests	34

Total consideration	3,519
Cash received	61
Total consideration, net of cash received	$	3,458

(1)Long-term debt at December 2, 2021 includes Enable senior notes with an aggregate principal amount of $3.18 billion in senior notes and a fair value of $3.43 billion. It also includes $800 million outstanding on the Enable 2019 Term Loan Agreement and $35 million outstanding on the Enable Five-Year Revolving Credit Facility, both of which were repaid and terminated in December 2021, immediately subsequent to the close of the Enable Acquisition.

Advances to and Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2022

Investment In Affiliates [Abstract]

Investments In Affiliates

INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

Description of Investments

Following is a summary of the Partnership’s significant unconsolidated investees.

Citrus

Energy Transfer owns a 50% interest in Citrus. 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.

MEP

Energy Transfer owns a 50% interest in MEP, which owns the Midcontinent Express Pipeline, an approximately 500-mile natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment.

White Cliffs

Energy Transfer owns a 51% interest in White Cliffs, which consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline. These pipelines transport crude and NGLs from Platteville, Colorado to Cushing, Oklahoma. The Partnership recorded an impairment of its investment in White Cliffs of $129 million during the year ended December 31, 2020 due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline.

Explorer

Energy Transfer owns a 15% membership interest in Explorer, which consists of a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur, and Houston, Texas and extends to Chicago, Illinois. Our investment in Explorer is reflected in our NGL and refined products transportation and services segment.

Summary of Balances Related to Unconsolidated Affiliates

The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2022 and 2021 were as follows:


	December 31,
	2022		2021
Citrus	$	1,800	$	1,792

MEP	360		378
White Cliffs	218		245
Explorer	69		71
Other	446		461
Total	$	2,893	$	2,947

The following table presents equity in earnings (losses) of unconsolidated affiliates:


	Years Ended December 31,
	2022		2021		2020
Citrus	$	141	$	157	$	162

MEP	10		(17)		(6)
White Cliffs	(8)		—		20
Explorer	25		24		17
Other (1)	89		82		(74)
Total equity in earnings of unconsolidated affiliates	$	257	$	246	$	119

(1)For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million.

Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, MEP, White Cliffs and Explorer (on a 100% basis) for all periods presented:


	December 31,
	2022		2021
Current assets	$	311	$	319
Property, plant and equipment, net	7,722		7,803
Other assets	86		88
Total assets	$	8,119	$	8,210

Current liabilities	$	291	$	547
Non-current liabilities	4,347		4,110
Equity	3,481		3,553
Total liabilities and equity	$	8,119	$	8,210


	Years Ended December 31,
	2022		2021		2020
Revenue	$	1,518	$	1,393	$	1,405
Operating income	704		684		732
Net income	463		446		480

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 Unit

12 Months Ended

Dec. 31, 2022

Earnings Per Share [Abstract]

Net Income Per Limited Partner Unit

NET INCOME PER COMMON UNIT:

Basic net income per common 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 common 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. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from Energy Transfer’s limited partner unit ownership in Sunoco LP that would have resulted assuming the incremental units related to 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,
	2022		2021		2020
Net income	$	5,868	$	6,687	$	140
Less: Net income attributable to redeemable noncontrolling interests	51		50		49
Less: Net income attributable to noncontrolling interests	1,061		1,167		739
Net income (loss), net of noncontrolling interests	4,756		5,470		(648)
Less: General Partner’s interest in income (loss)	4		6		(1)
Less: Preferred Unitholders’ interest in income	422		285		—
Common Unitholders’ interest in net income (loss)	$	4,330	$	5,179	$	(647)
Basic Income (Loss) per Common Unit:
Weighted average common units	3,086.8		2,734.4		2,695.6
Basic income (loss) per common unit	$	1.40	$	1.89	$	(0.24)

Diluted Income (Loss) per Common Unit:
Common Unitholders’ interest in net income (loss)	$	4,330	$	5,179	$	(647)
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units	(2)		(2)		—
Diluted income (loss) available to Common Unitholders	$	4,328	$	5,177	$	(647)
Weighted average common units	3,086.8		2,734.4		2,695.6

Dilutive effect of unvested unit awards	10.2		5.1		—
Weighted average common units, assuming dilutive effect of unvested unit awards	3,097.0		2,739.5		2,695.6
Diluted income (loss) per common unit	$	1.40	$	1.89	$	(0.24)

Debt Obligations

12 Months Ended

Dec. 31, 2022

Debt Obligations [Abstract]

Debt Disclosure [Text Block]

DEBT OBLIGATIONS:

In connection with the Rollup Mergers on April 1, 2021, as discussed in Note 1, Energy Transfer entered into various supplemental indentures and assumed all the obligations of ETO under the respective indentures and credit agreements.

In November 2022, Energy Transfer and Panhandle completed an internal reorganization which resulted in Energy Transfer assuming all of Panhandle’s notes and debentures.

Our debt obligations consist of the following:


	December 31,
	2022		2021
Energy Transfer Indebtedness











4.65% Senior Notes due February 15, 2022(1)	$	—	$	300

5.00% Senior Notes due October 1, 2022(1)	—		700
3.45% Senior Notes due January 15, 2023(2)(3)	350		350
3.60% Senior Notes due February 1, 2023(2)(3)	800		800
4.25% Senior Notes due March 15, 2023(3)	5		5
4.25% Senior Notes due March 15, 2023(3)	995		995
4.20% Senior Notes due September 15, 2023(3)	500		500
4.50% Senior Notes due November 1, 2023(3)	600		600
5.875% Senior Notes due January 15, 2024	23		23
7.60% Senior Notes due February 1, 2024(4)	82		—
5.875% Senior Notes due January 15, 2024	1,127		1,127
4.90% Senior Notes due February 1, 2024	350		350
7.60% Senior Notes due February 1, 2024	277		277
4.25% Senior Notes due April 1, 2024	500		500
4.50% Senior Notes due April 15, 2024	750		750
3.90% Senior Notes due May 15, 2024	600		600
9.00% Debentures due November 1, 2024	65		65
4.05% Senior Notes due March 15, 2025	1,000		1,000
2.90% Senior Notes due May 15, 2025	1,000		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
4.40% Senior Notes due March 15, 2027	700		700
4.20% Senior Notes due April 15, 2027	600		600
5.50% Senior Notes due June 1, 2027	44		44
5.50% Senior Notes due June 1, 2027	956		956
4.00% Senior Notes due October 1, 2027	750		750
5.55% Senior Notes due February 15, 2028	1,000		—
4.95% Senior Notes due May 15, 2028	800		800
4.95% Senior Notes due June 15, 2028	1,000		1,000
5.25% Senior Notes due April 15, 2029	1,500		1,500
7.00% Senior Notes due July 15, 2029(4)	66		—
4.15% Senior Notes due September 15, 2029	547		547
8.25% Senior Notes due November 15, 2029(4)	33		—
8.25% Senior Notes due November 15, 2029	267		267
3.75% Senior Note due May 15, 2030	1,500		1,500
5.75% Senior Notes due February 15, 2033	1,500		—
4.90% Senior Notes due March 15, 2035	500		500
6.625% Senior Notes due October 15, 2036	400		400


5.80% Senior Notes due June 15, 2038	500	500
7.50% Senior Notes due July 1, 2038	550	550
6.85% Senior Notes due February 15, 2040	250	250
6.05% Senior Notes due June 1, 2041	700	700
6.50% Senior Notes due February 1, 2042	1,000	1,000
6.10% Senior Notes due February 15, 2042	300	300
4.95% Senior Notes due January 15, 2043	350	350
5.15% Senior Notes due February 1, 2043	450	450
5.95% Senior Notes due October 1, 2043	450	450
5.30% Senior Notes due April 1, 2044	700	700
5.00% Senior Notes due May 15, 2044	531	531
5.15% Senior Notes due March 15, 2045	1,000	1,000
5.35% Senior Notes due May 15, 2045	800	800
6.125% Senior Notes due December 15, 2045	1,000	1,000
5.30% Senior Notes due April 15, 2047	900	900
5.40% Senior Notes due October 1, 2047	1,500	1,500
6.00% Senior Notes due June 15, 2048	1,000	1,000
6.25% Senior Notes due April 15, 2049	1,750	1,750
5.00% Senior Notes due May 15, 2050	2,000	2,000
Floating Rate Junior Subordinated Notes due November 1, 2066	600	546

Five-Year Credit Facility	793	2,937
Unamortized premiums, discounts and fair value adjustments, net	184	233
Deferred debt issuance costs	(181)	(186)
	40,264	40,717

Subsidiary Indebtedness
Transwestern Debt

5.89% Senior Notes due May 24, 2022(1)	—	150
5.66% Senior Notes due December 9, 2024	175	175
6.16% Senior Notes due May 24, 2037	75	75

	250	400

Panhandle Debt

7.60% Senior Notes due February 1, 2024(4)	—	82
7.00% Senior Notes due July 15, 2029(4)	—	66
8.25% Senior Notes due November 15, 2029(4)	—	33
Floating Rate Junior Subordinated Notes due November 1, 2066(4)	—	54
Unamortized premiums, discounts and fair value adjustments, net(4)	—	8
	—	243


Bakken Project Debt
3.625% Senior Notes due April 1, 2022(1)	—	650
3.90% Senior Notes due April 1, 2024	1,000	1,000
4.625% Senior Notes due April 1, 2029	850	850


Unamortized premiums, discounts and fair value adjustments, net	(1)		(2)
Deferred debt issuance costs	(7)		(9)
	1,842		2,489

Sunoco LP Debt
6.00% Senior Notes Due April 15, 2027	600		600
5.875% Senior Notes Due March 15, 2028	400		400
4.50% Senior Notes due May 15, 2029	800		800
4.50% Senior Notes due April 30, 2030	800		800
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023	900		581
Lease-related obligations	94		100
Deferred debt issuance costs	(23)		(26)
	3,571		3,255

USAC Debt
6.875% Senior Notes due April 1, 2026	725		725
6.875% Senior Notes due September 1, 2027	750		750
USAC $1.60 billion Revolving Credit Facility due December 2026(5)	646		516

Deferred debt issuance costs	(14)		(18)
	2,107		1,973

HFOTCO Debt
HFOTCO Tax Exempt Notes due 2050	225		225
Unamortized premiums, discounts and fair value adjustments, net	—		(1)

	225		224

Energy Transfer Canada Debt

Energy Transfer Canada facilities(6)	—		398


	—		398

Other	3		3
Total debt	48,262		49,702
Less: Current maturities of long-term debt	2		680
Long-term debt, less current maturities	$	48,260	$	49,022

(1)These notes were redeemed in 2022.

(2)These notes were redeemed in the first quarter of 2023.

(3)As of December 31, 2022, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.

(4)As discussed previously, Panhandle’s debt was assumed by Energy Transfer during 2022 as a result of an internal reorganization.

(5)The USAC Credit Facility matures in December 2026, except that if any portion of the 6.875% Senior Notes due 2026 are outstanding on December 31, 2025, the USAC Credit Facility will mature on December 31, 2025.

(6)These facilities were included in the August 2022 Energy Transfer Canada divestiture as discussed in Note 3.

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $42 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net:


2023	$	3,250
2024	5,175
2025	2,400
2026	2,921
2027	6,093
Thereafter	28,465
Total	$	48,304

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

Senior Notes

The Energy Transfer Senior Notes are the Partnership’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. Energy Transfer’s obligations under the Energy Transfer Senior Notes previously were secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the Energy Transfer Term Loan Facility, by a lien on substantially all of Energy Transfer’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 Energy Transfer Term Loan Facility, the collateral securing the Energy Transfer Senior Notes was released. The Energy Transfer Senior Notes are not guaranteed by any of its subsidiaries.

The covenants related to the Energy Transfer 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 Partnership’s assets.

Credit Facilities and Commercial Paper

Five-Year Credit Facility

The Partnership’s Five-Year Credit Facility allows for unsecured borrowings up to $5.00 billion and matures on April 11, 2027. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $7.00 billion under certain conditions.

As of December 31, 2022, the Five-Year Credit Facility had $793 million of outstanding borrowings, of which $750 million consisted of commercial paper. The amount available for future borrowings was $4.18 billion, after accounting for outstanding letters of credit in the amount of $32 million. The weighted average interest rate on the total amount outstanding as of December 31, 2022 was 5.12%.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”). As of December 31, 2022, the Sunoco LP Credit Facility had $900 million of outstanding borrowings and $7 million in standby letters of credit and matures in July 2023. The amount available for future borrowings was $593 million at December 31, 2022. The weighted average interest rate on the total amount outstanding as of December 31, 2022 was 6.17%.

USAC Credit Facility

USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”) which matures on December 8, 2026, except that if any portion of USAC’s senior notes due 2026 are outstanding on December 31, 2025, the USAC Credit Facility will mature on December 31, 2025. The USAC Credit Facility also permits up to $200 million of future increases in borrowing capacity. As of December 31, 2022, USAC had $646 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2022, USAC had $954 million of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $333 million.

The weighted average interest rate on the total amount outstanding as of December 31, 2022 was 6.84%.

Covenants Related to Our Credit Agreements

The agreements relating to the 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 Five-Year Credit Facility contains 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 Five-Year Credit Facility) during certain Defaults (as defined in the Five-Year Credit Facility) and during any Event of Default (as defined in the Five-Year Credit Facility);

•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 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 Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the Five-Year Credit Facility ranges from 0.125% to 0.300%.

The Five-Year Credit Facility contains various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The Five-Year Credit Facility also limits us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreement, of 5.00 to 1.00, which can generally be increased to 5.50 to 1.00 during a Specified Acquisition Period. Our Leverage Ratio was 3.32 to 1.00 at December 31, 2022, as calculated in accordance with the credit agreement.

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 Transwestern

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.

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 specified net leverage ratio and interest coverage ratio.

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;

•enter into transactions with affiliates;

•merge or consolidate;

•sell our assets; and

•make certain acquisitions.

The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain:

•a minimum EBITDA to interest coverage ratio;

•a ratio of total secured indebtedness to EBITDA within a specified range; and

•a maximum funded debt to EBITDA ratio.

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, 2022.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-URI https://asc.fasb.org/topic&trid=2208564

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (h)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-URI https://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (g)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1E
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495348-112611

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (i)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

+ Details

Redeemable Noncontrolling Interest	12 Months Ended
Redeemable Noncontrolling Interest	Dec. 31, 2022
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, 2022 included a balance of $477 million related to the USAC Preferred Units, described below, and a balance of $16 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. As of December 31, 2021, redeemable noncontrolling interests included a balance of $477 million related to the USAC Preferred Units, 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 and a balance of $291 million related to Energy Transfer Canada preferred shares. The Energy Transfer Canada preferred shares were deconsolidated in connection with the sale in August 2022. USAC Series A Preferred Units As of December 31, 2022, USAC had 500,000 preferred units issued and outstanding. 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 are convertible into USAC common units at the election of the holders. As of December 31, 2022, a total of 333,333 USAC Preferred Units are convertible, at the option of the holder, into a maximum of 16,657,088 USAC common units, including unpaid cash distributions. As of April 2, 2023, all of the USAC Preferred Units will be convertible, at the option of the holder, into a maximum of 24,985,633 USAC common units. 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, beginning April 2028, 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 USAC may elect to pay up to 50% of such redemption amount in USAC common units.

Equity

12 Months Ended

Dec. 31, 2021

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 at “Quarterly Distributions of Available Cash.”

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 (which currently holds an approximately 0.1% general partner interest) 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 Energy Transfer Common Units during the years ended December 31, 2022, 2021 and 2020 was as follows:


	Years Ended December 31,
	2022	2021	2020
Number of Common Units, beginning of period	3,082.5	2,702.4	2,689.6

Common Units issued in mergers and acquisitions (1)	—	374.6	—
Common Units repurchased	—	(4.2)	—
Issuance of Common Units (2)	11.9	9.7	12.8
Number of Common Units, end of period	3,094.4	3,082.5	2,702.4

(1)In December 2021, Energy Transfer issued 374.6 million Energy Transfer Common Units in connection with the Enable Acquisition.

(2)Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.

Energy Transfer Class A Units

As of February 10, 2023, the Partnership had outstanding 765,933,429 Class A units (“Energy Transfer Class A Units”) representing limited partner interests in the Partnership to the General Partner. The Energy Transfer Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, Energy Transfer’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 Energy Transfer Class A Units additional Energy Transfer 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 Energy Transfer Class A Units are not entitled to distributions and otherwise have no economic attributes.

Energy Transfer Repurchase Program

In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $2 billion of Energy Transfer 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 did not repurchase any Energy Transfer Common Units under this program in 2022 and repurchased 4.2 million in 2021. As of December 31, 2022, $880 million remained available to repurchase under the current program.

Energy Transfer Distribution Reinvestment Program

During the year ended December 31, 2022, distributions of $61 million were reinvested under the distribution reinvestment program. As of December 31, 2022, a total of 12 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment program.

Energy Transfer Preferred Units

As of December 31, 2022, Energy Transfer’s outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series B Preferred Units, 18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units, 32,000,000 Series E Preferred Units, 500,000 Series F Preferred Units, 1,484,780 Series G Preferred Units and 900,000 Series H Preferred Units.

The following table summarizes changes in the Energy Transfer Preferred Units:


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Total
Balance, December 31, 2020	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Preferred units conversion	943		547		440		434		786		504		1,114		—		4,768
Units issued for cash	—		—		—		—		—		—		—		889		889
Distributions to partners	(30)		(18)		(25)		(25)		(45)		(34)		(79)		(24)		(280)
Units issued in Enable Acquisition	—		—		—		—		—		—		392		—		392
Other, net	—		—		—		—		—		—		—		(3)		(3)
Net income	45		27		25		25		45		26		61		31		285
Balance, December 31, 2021	958		556		440		434		786		496		1,488		893		6,051
Distributions to partners	(59)		(36)		(33)		(34)		(61)		(34)		(106)		(59)		(422)
Net income	59		36		33		34		61		34		106		59		422
Balance, December 31, 2022	$	958	$	556	$	440	$	434	$	786	$	496	$	1,488	$	893	$	6,051

Energy Transfer Series A Preferred Units

Distributions on the Energy Transfer 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 Energy Transfer 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, or a successor rate, in each case determined quarterly by our calculation agent, plus a spread of 4.028% per annum. The Energy Transfer Series A Preferred Units are redeemable at Energy Transfer’s option on or after February 15, 2023 at a redemption price of $1,000 per Energy Transfer Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Energy Transfer Series B Preferred Units

Distributions on the Energy Transfer 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 Energy Transfer 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, or a successor rate, in each case determined quarterly by our calculation agent, plus a spread of 4.155% per annum. The Energy Transfer Series B Preferred Units are redeemable at Energy Transfer’s option on or after February 15, 2028 at a redemption price of $1,000 per Energy Transfer Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Energy Transfer Series C Preferred Units

Distributions on the Energy Transfer 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 Energy Transfer 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, or a successor rate, in each case determined quarterly by our calculation agent, plus a spread of 4.530% per annum. The Energy Transfer Series C Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2023 at a redemption price of $25 per Energy Transfer Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Energy Transfer Series D Preferred Units

Distributions on the Energy Transfer 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 Energy Transfer 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, or a successor rate, in each case determined quarterly by our calculation agent, plus a spread of 4.738% per annum. The Energy Transfer Series D Preferred Units are redeemable at Energy Transfer’s option on or after August 15, 2023 at a redemption price of $25 per Energy Transfer Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Energy Transfer Series E Preferred Units

Distributions on the Energy Transfer 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 Energy Transfer 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, or a successor rate, in each case determined quarterly by our calculation agent, plus a spread of 5.161% per annum. The Energy Transfer Series E Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2024 at a redemption price of $25 per Energy Transfer Series E Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Energy Transfer Series F Preferred Units

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 Energy Transfer 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 Energy Transfer Series F Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2025 at a redemption price of $1,000 per Energy Transfer Series F Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Energy Transfer Series G Preferred Units

Distributions on the Energy Transfer 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 Energy Transfer 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 Energy Transfer Series G Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2030 at a redemption price of $1,000 per Energy Transfer Series G Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. On December 2, 2021, Energy Transfer issued 384,780 Energy Transfer Series G Preferred Units in connection with the Enable Acquisition, as discussed in Note 3.

Energy Transfer Series H Preferred Units

On June 15, 2021, Energy Transfer issued 900,000 of its 6.500% Series H Preferred Units at a price to the public of $1,000 per unit. Distributions on the Series H Preferred Units will accrue and be cumulative to, but excluding, November 15, 2026, at a rate equal to 6.500% per annum of the $1,000 liquidation preference. On and after November 15, 2026 and each fifth anniversary thereafter, the distribution rate on the Series H Preferred Units will reset to be a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.694% per annum. Distributions on the Series H Preferred Units will be payable semi-annually in arrears on the 15th day of May and November of each year. The Series H Preferred Units are redeemable at Energy Transfer’s option during the three-month period prior to, and including, each distribution reset date at a redemption price of $1,000 per Series H Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Sale of Common Units by Subsidiaries

Energy Transfer on a stand-alone basis (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.

Subsidiary Equity Transactions

USAC’s Distribution Reinvestment Program

During the years ended December 31, 2022, 2021 and 2020, USAC issued 124,255, 118,399 and 188,695 USAC common units, respectively, under the USAC distribution reinvestment program.

USAC’s Warrants

In April 2022, USAC issued 534,308 of its common units in connection with the exercise of outstanding warrants.

As of December 31, 2022, one tranche of USAC Warrants with the right to purchase 10,000,000 common units at a strike price of $19.59 per common unit was outstanding and may be exercised by the holders at any time before April 2, 2028.

Energy Transfer Common Unit Distributions

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly.

Our distributions declared and paid with respect to our common units were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2019

February 7, 2020

February 19, 2020

0.3050

March 31, 2020

May 7, 2020

May 19, 2020

0.3050

June 30, 2020

August 7, 2020

August 19, 2020

0.3050

September 30, 2020

November 6, 2020

November 19, 2020

0.1525

December 31, 2020

February 8, 2021

February 19, 2021

0.1525

March 31, 2021

May 11, 2021

May 19, 2021

0.1525

June 30, 2021

August 6, 2021

August 19, 2021

0.1525

September 30, 2021

November 5, 2021

November 19, 2021

0.1525

December 31, 2021

February 8, 2022

February 18, 2022

0.1750

March 31, 2022

May 9, 2022

May 19, 2022

0.2000

June 30, 2022

August 8, 2022

August 19, 2022

0.2300

September 30, 2022

November 4, 2022

November 21, 2022

0.2650

December 31, 2022

February 7, 2023

February 21, 2023

0.3050

Energy Transfer Preferred Unit Distributions

Distributions on Energy Transfer’s Series A, Series B, Series C, Series D, Series E, Series F, Series G and Series H preferred units declared and/or paid by Energy Transfer were as follows:


Period Ended	Record Date	Payment Date	Series A (1)	Series B (1)	Series C	Series D	Series E	Series F (1)	Series G (1)	Series H (1)
March 31, 2021	May 3, 2021	May 17, 2021	$—	$—	$0.4609	$0.4766	$0.4750	$33.7500	$35.63	$—
June 30, 2021	August 2, 2021	August 16, 2021	31.25	33.13	0.4609	0.4766	0.4750	—	—	—
September 30, 2021	November 1, 2021	November 15, 2021	—	—	0.4609	0.4766	0.4750	33.7500	35.63	27.08	*
December 31, 2021	February 1, 2022	February 15, 2022	31.25	33.13	0.4609	0.4766	0.4750	—	—	—
March 31, 2022	May 2, 2022	May 16, 2022	—	—	0.4609	0.4766	0.4750	33.7500	35.63	32.50
June 30, 2022	August 1, 2022	August 15, 2022	31.25	33.13	0.4609	0.4766	0.4750	—	—	—
September 30, 2022	November 1, 2022	November 15, 2022	—	—	0.4609	0.4766	0.4750	33.7500	35.63	32.50
December 31, 2022	February 1, 2023	February 15, 2023	31.25	33.13	0.4609	0.4766	0.4750	—	—	—

* Represents prorated initial distribution.

(1) Series A, Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Pursuant to their terms, distributions on the Series A and Series B preferred units will be paid quarterly beginning after February 15, 2023 and February 15, 2028, respectively

Sunoco LP Cash Distributions

Energy Transfer owns approximately 28.5 million Sunoco LP common units and all of Sunoco LP’s incentive distribution rights. As of December 31, 2022, Sunoco LP had approximately 84.1 million common units outstanding.

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, 2019

February 7, 2020

February 19, 2020

0.8255

March 31, 2020

May 7, 2020

May 19, 2020

0.8255

June 30, 2020

August 7, 2020

August 19, 2020

0.8255

September 30, 2020

November 6, 2020

November 19, 2020

0.8255

December 31, 2020

February 8, 2021

February 19, 2021

0.8255

March 31, 2021

May 11, 2021

May 19, 2021

0.8255

June 30, 2021

August 6, 2021

August 19, 2021

0.8255

September 30, 2021

November 5, 2021

November 19, 2021

0.8255

December 31, 2021

February 8, 2022

February 18, 2022

0.8255

March 31, 2022

May 9, 2022

May 19, 2022

0.8255

June 30, 2022

August 8, 2022

August 19, 2022

0.8255

September 30, 2022

November 4, 2022

November 18, 2022

0.8255

December 31, 2022

February 7, 2023

February 21, 2023

0.8255

USAC Cash Distributions

Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2022, USAC had approximately 98.2 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 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2019

January 27, 2020

February 7, 2020

0.5250

March 31, 2020

April 27, 2020

May 8, 2020

0.5250

June 30, 2020

July 31, 2020

August 10, 2020

0.5250

September 30, 2020

October 26, 2020

November 6, 2020

0.5250

December 31, 2020

January 25, 2021

February 5, 2021

0.5250

March 31, 2021

April 26, 2021

May 7, 2021

0.5250

June 30, 2021

July 26, 2021

August 6, 2021

0.5250

September 30, 2021

October 25, 2021

November 5, 2021

0.5250

December 31, 2021

January 24, 2022

February 4, 2022

0.5250

March 31, 2022

April 25, 2022

May 6, 2022

0.5250

June 30, 2022

July 25, 2022

August 5, 2022

0.5250

September 30, 2022

October 24, 2022

November 4, 2022

0.5250

December 31, 2022

January 23, 2023

February 3, 2023

0.5250

Accumulated Other Comprehensive Income

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


	December 31,
	2022		2021
Available-for-sale securities	$	9	$	19
Foreign currency translation adjustment	1		13

Actuarial gain (loss) related to pensions and other postretirement benefits	(7)		5
Investments in unconsolidated affiliates, net	13		(11)
Total AOCI, net of tax	16		26
Amounts attributable to noncontrolling interests	—		(3)
Total AOCI included in partners’ capital, net of tax	$	16	$	23

The following table sets forth the tax amounts included in the respective components of other comprehensive income:


	December 31,
	2022		2021
Available-for-sale securities	$	1	$	(1)
Foreign currency translation adjustment	6		6
Actuarial loss relating to pension and other postretirement benefits	1		1
Total	$	8	$	6

Equity Incentive Plans

12 Months Ended

Dec. 31, 2022

Share-Based Payment Arrangement, Recognized Amount [Abstract]

Unit-Based Compensation Plans

EQUITY INCENTIVE PLANS:

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 equity-based compensation awards. As of December 31, 2022, an aggregate total of 3.6 million Energy Transfer Common Units remain available to be awarded under our equity incentive plans.

Energy Transfer 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, Energy Transfer 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, 2021	36.1	$	9.49

Awards granted	12.4	11.56
Awards vested	(9.3)	11.79
Awards forfeited	(1.5)	9.39
Unvested awards as of December 31, 2022	37.7	$	9.62

During the years ended December 31, 2022, 2021, and 2020, the weighted average grant-date fair value per unit award granted was $11.56, $8.46 and $6.29, respectively, and the total fair value of awards vested was $103 million, $52 million and $51 million, respectively, based on the market price of the respective Common Units as of the vesting date. As of December 31, 2022, a total of 37.7 million unit awards remain unvested, for which Energy Transfer expects to recognize a total of $248 million in compensation expense over a weighted average period of 3.09 years.

Cash Restricted Units. The Partnership has also granted cash restricted units, which vest through three years of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one Energy Transfer Common Unit upon vesting. For the years ended December 31, 2022, 2021 and 2020, the Partnership granted a total of 3.8 million, 3.9 million and 7.7 million cash restricted units, respectively. As of December 31, 2022, a total of 8.5 million cash restricted units were unvested. As of December 31, 2022, the Partnership’s consolidated balance sheet reflected aggregate liabilities of $4.2 million related to cash restricted units.

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, 2021	2.0	$	30.92	2.2	$	13.57
Awards granted	0.4	43.54		0.6	18.31
Awards vested	(0.5)	29.95		(0.4)	15.89
Awards forfeited	(0.1)	30.31		(0.3)	14.10
Unvested awards as of December 31, 2022	1.8	$	34.29	2.1	$	14.21

The following table summarizes the weighted average grant-date fair value per unit award granted:


	Years Ended December 31,
	2022		2021		2020
Sunoco LP	$	43.54	$	37.72	$	28.63
USAC	18.31		14.92		12.55

The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2022, 2021 and 2020 was $26 million, $24 million, and $16 million, respectively, based on the market price of Sunoco LP and USAC common units as of the vesting date. As of December 31, 2022, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $42 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.2 years.

Income Taxes Income Taxes (Notes)

12 Months Ended

Dec. 31, 2022

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 are summarized as follows:


	Years Ended December 31,
	2022		2021		2020
Current expense (benefit):
Federal	$	—	$	19	$	(6)
State	17		24		32
Foreign	—		—		1
Total	17		43		27
Deferred expense (benefit):
Federal	239		246		176
State	(58)		(106)		41
Foreign	6		1		(7)
Total	187		141		210
Total income tax expense	$	204	$	184	$	237

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, 2022, 2021 and 2020 is as follows:


	Years Ended December 31,
	2022		2021		2020

Income tax expense at United States statutory rate	$	1,275	$	1,443	$	79
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax	(1,086)		(1,211)		88
Noncontrolling interests	26		—		16
State tax, net of federal tax benefit	19		85		58
Statutory rate change	(42)		(46)		—
Valuation allowance	(4)		(63)		—
Uncertain tax positions	(3)		(34)		—
Dividend received deduction	(3)		(4)		—


Foreign taxes	6		1		(7)

Other	16		13		3
Income tax expense	$	204	$	184	$	237

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The following table summarizes the principal components of the deferred tax assets (liabilities) as follows:


	December 31,
	2022		2021
Deferred income tax assets:
Net operating losses and other carryforwards	$	603	$	803


Other	60		35
Total deferred income tax assets	663		838
Valuation allowance	(19)		(34)
Net deferred income tax assets	644		804

Deferred income tax liabilities:
Property, plant and equipment	(218)		(314)

Investments in affiliates	(4,010)		(4,042)
Trademarks	(89)		(79)
Other	(28)		(17)
Total deferred income tax liabilities	(4,345)		(4,452)
Net deferred income taxes	$	(3,701)	$	(3,648)

As of December 31, 2022, ETP Holdco had a federal net operating loss carryforward of $2.4 billion, of which $645 million will expire in 2036 through 2037 while the remaining can be carried forward indefinitely. A total of $341 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in a particular year may be limited. As of December 31, 2022, Sunoco Retail LLC, a corporate subsidiary of Sunoco LP, had a state net operating loss carryforward of $84 million, which we expect to fully utilize. Sunoco Retail LLC has no federal net operating loss carryforward.

Our corporate subsidiaries have state net operating loss carryforward benefits of $82 million, net of federal tax, some of which expire between 2023 and 2041, while others are carried forward indefinitely. Our corporate subsidiaries have cumulative excess business interest expense of $169 million available for carryforward indefinitely, of which $41 million is limited under IRC §382. A valuation allowance of $3 million is applicable to the state net operating loss carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania. A separate valuation allowance of $15 million is attributable to foreign tax credits.

The following table sets forth the changes in unrecognized tax benefits:


	Years Ended December 31,
	2022		2021		2020
Balance at beginning of year	$	56	$	90	$	94



Reduction attributable to tax positions taken in prior years	(4)		(34)		—

Lapse of statute	—		—		(4)
Balance at end of year	$	52	$	56	$	90

As of December 31, 2022, we had $52 million ($48 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.

Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2022, we recognized interest and penalties of less than $2 million. At December 31, 2022, we have interest and penalties accrued of $18 million, net of tax.

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. Certain Pennsylvania taxpayers have subsequently undertaken 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. On December 22, 2021, the Pennsylvania Supreme Court found in General Motors Corporation v. Commonwealth (“GM”) that the taxpayer was entitled to meaningful backwards looking relief under the Due Process Clause, meaning the Commonwealth must equalize the taxpayer’s position with taxpayers who were not affected by the NOL cap in place for the year at issue. The Court therefore held the taxpayer was entitled to a refund by calculating its tax for that year with an uncapped NOL deduction. We believe the Pennsylvania Supreme Court’s ruling in GM will more likely than not be upheld if challenged by the Commonwealth. ETC Sunoco previously 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. In addition, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, ETC Sunoco previously reserved $34 million ($27 million after federal income tax benefits) against the receivable. Subsequent to the Pennsylvania Supreme Court’s decision in GM, the reserve has been reversed and the entire tax benefit of $34 million ($27 million after federal income tax benefit) has been recognized by the Partnership.

The Partnership’s 2020 U.S. Federal income tax return is currently under examination by the Internal Revenue Service. In general, Energy Transfer and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2017 and prior tax years.

USAC is currently under examination by the IRS for years 2019 and 2020. Energy Transfer and its other 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.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 21
-URI https://asc.fasb.org/extlink&oid=121826272&loc=d3e32857-109319

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SAB Topic 11.C)
-URI https://asc.fasb.org/extlink&oid=122134291&loc=d3e330215-122817

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 17
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=121826272&loc=d3e32809-109319

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.5.Q1)
-URI https://asc.fasb.org/extlink&oid=122134291&loc=d3e330036-122817

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 14
-URI https://asc.fasb.org/extlink&oid=121826272&loc=d3e32705-109319

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 270
-Section 50
-Paragraph 1
-URI https://asc.fasb.org/extlink&oid=6424409&loc=d3e44925-109338

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-URI https://asc.fasb.org/topic&trid=2144680

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 30
-Section 50
-Paragraph 2
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=6424122&loc=d3e41874-109331

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(h)(2))
-URI https://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

+ Details

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

12 Months Ended

Dec. 31, 2022

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

Commitments Contingencies and Guarantees

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Winter Storm Impacts

Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Partnership’s consolidated net income and also affected the results of operations in certain segments. The recognition of the impacts of Winter Storm Uri during 2021 required management to make certain estimates and assumptions, including estimates of expected credit losses and assumptions related to the resolution of disputes with counterparties with respect to certain purchases and sales of natural gas. The ultimate realization of credit losses and the resolution of disputed purchases and sales of natural gas could materially impact the Partnership’s financial condition and results of operations in future periods.

FERC Proceedings

Rover – FERC - Stoneman House

In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known as the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain why it should not pay a $20 million civil penalty for alleged violations of FERC regulations requiring certificate holders to be forthright in their submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021 and a surreply on September 15, 2021. FERC issued an order on January 20, 2022 setting the matter for hearing before an administrative law judge. The hearing was set to commence on March 6, 2023.

On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the United States District Court for the Northern District of Texas seeking an order declaring that FERC must bring its enforcement action in federal district court (instead of before an administrative law judge). Also on February 1, 2022, Energy Transfer and Rover filed an expedited request to stay the proceedings before the FERC administrative law judge pending the outcome of the federal district court case. On May 24, 2022, the District Court ordered a stay of the FERC’s enforcement case and the District Court case pending the resolution of two cases pending before the United States Supreme Court. Arguments were heard in those cases on November 7, 2022. Energy Transfer and Rover intend to vigorously defend this claim.

Rover – FERC - Tuscarawas

In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the investigation. In 2019, Enforcement Staff provided Rover with a notice pursuant to Section 1b.19 of the FERC regulations that Enforcement Staff intended to recommend that the FERC pursue an enforcement action against Rover and the Partnership. On December 16, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN17-4-000), ordering Rover and Energy Transfer to show cause why they should not be found to have violated Section 7(e) of the Natural Gas Act, Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of $40 million.

Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and Energy Transfer filed their surreply to this order on May 13, 2022. The primary contractor (and one of the subcontractors) responsible for the HDD operations of the Tuscarawas River site have agreed to indemnify Rover and the Partnership for any and all losses, including any fines and penalties from government agencies, resulting from their actions in conducting such HDD operations. Given the stage of the proceedings, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by Enforcement Staff and intends to vigorously defend itself against the subject claims.

Other FERC Proceedings

By an order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021. On April 26, 2021, Panhandle filed its brief on exceptions to the initial decision. On May 17, 2021, Panhandle filed its brief opposing exceptions in this proceeding. On December 16, 2022, the FERC issued its order on Panhandle’s rate case. On January 17, 2023, Panhandle filed its request for rehearing in the proceeding.

On July 1, 2022, Transwestern filed a rate case pursuant to Section 4 of the Natural Gas Act. By order dated September 9, 2022, a procedural schedule was adopted in this proceeding, setting the commencement of the hearing for June 22, 2023 with an initial decision anticipated by November 15, 2023. By a subsequent order dated February 14, 2023, the procedural schedule was suspended based on representations that the participants have reached an agreement in principle to resolve all issues in this proceeding and a settlement is being prepared for filing at FERC.

In May 2021, the FERC commenced an audit of SPLP for the period from January 1, 2018 to present to evaluate SPLP’s compliance with its FERC oil tariffs, the accounting requirements of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s Form No. 6 reporting requirements. The audit is ongoing.

Commitments

In the normal course of business, Energy Transfer 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. Energy Transfer believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations.

Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon the 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 following table reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:


	Years Ended December 31,
	2022		2021		2020
ROW expense	$	64	$	48	$	47

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. Due to the flammable and combustible nature of natural gas and crude oil, the potential exists for personal injury and/or property damage to occur in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

We or our subsidiaries are parties to various legal proceedings, arbitrations and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

As of December 31, 2022 and 2021, accruals of approximately $200 million and $144 million, respectively, were reflected on our consolidated balance sheets related to contingent obligations that met both the probable and reasonably estimable criteria. In addition, we may recognize additional contingent losses in the future related to (i) contingent matters for which a loss is currently considered reasonably possible but not probable and/or (ii) losses in excess of amounts that have already been accrued for such contingent matters. In some of these cases, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. For such matters where additional contingent losses can be reasonably estimated, the range of additional losses is estimated to be up to approximately $750 million.

The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

The following sections include descriptions of certain matters that could impact the Partnership’s financial position, results of operations and/or cash flows in future periods. The sections below also include updates to certain matters that have previously been disclosed, even if those matters are not anticipated to have a potentially significant impact on future periods. In addition to the matters disclosed below, the Partnership is also involved in multiple other matters that could impact future periods, including other lawsuits and arbitration related to the Partnership’s commercial agreements. With respect to such matters, contingencies that met both the probable and reasonably estimable criteria have been included in the accruals disclosed above, and the range of additional losses disclosed above also reflects any relevant amounts for such matters.

Dakota Access Pipeline

On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) challenging permits issued by the United States Army Corps of Engineers (“USACE”) that allowed Dakota Access to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE that allowed the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the District Court vacated the easement and ordered the Dakota Access Pipeline to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the United States Court of Appeals for the District of Columbia (“Court of Appeals”) which granted an administrative stay of the District Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August 5, 2020, the Court of Appeals 1) granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, 2) denied a motion to stay the March 25 order pending a decision on the merits by the Court of Appeals as to whether the USACE would be required to prepare an EIS, and 3) denied a motion to stay the District Court’s order to vacate the easement during this appeal process. The August 5 order also states that the Court of Appeals expected the USACE to

clarify its position with respect to whether USACE intended to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary.

On August 10, 2020, the District Court ordered the USACE to submit a status report by August 31, 2020, clarifying its position with regard to its decision-making process with respect to the continued operation of the pipeline. On August 31, 2020, the USACE submitted a status report that indicated that it considered the presence of the pipeline at the Lake Oahe crossing without an easement to constitute an encroachment on federal land, and that it was still considering whether to exercise its enforcement discretion regarding this encroachment. The Tribes subsequently filed a motion seeking an injunction to stop the operation of the pipeline and both USACE and Dakota Access filed briefs in opposition of the motion for injunction. The motion for injunction was fully briefed as of January 8, 2021.

On January 26, 2021, the Court of Appeals affirmed the District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order vacating the easement. In this same January 26 order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline shut down and be emptied of oil. Dakota Access filed for rehearing en banc on April 12, 2021, which the Court of Appeals denied. On September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General (December 17, 2021) and the Tribes (December 16, 2021). Dakota Access filed their reply on January 4, 2022. On February 22, 2022, the U.S. Supreme Court declined to hear the case.

The District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. On May 3, 2021, USACE advised the District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. On May 21, 2021, the District Court denied the plaintiffs’ request for an injunction. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice.

The pipeline continues to operate pending completion of the EIS. Energy Transfer anticipates the draft EIS will be completed and published by the USACE in the Spring of 2023, subject to additional delays by the USACE. The release of the draft EIS was paused following the SRST’s withdrawal as a cooperating agency on January 20, 2022. However, the pause has since been lifted and the USACE expects to release the draft EIS in the spring of 2023. Energy Transfer cannot determine when or how future lawsuits will be resolved or the impact they may have on the Bakken pipelines; however, Energy Transfer expects after the law and complete record are fully considered, any such proceeding will be resolved in a manner that will allow the pipeline to continue to operate.

In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.

Mont Belvieu Incident

On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu LP’s (“Lone Star”), now known as Energy Transfer Mont Belvieu NGLs LP, 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 resumed at the facilities in the fall of 2016, with the exception of one of Lone Star’s storage wells at the North Terminal that has not been returned to service. Lone Star has obtained payment for most of the losses it has submitted to the adjacent operator. Lone Star continues to quantify and seek reimbursement for outstanding losses.

MTBE Litigation

ETC Sunoco and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As of December 31, 2022, Sunoco Defendants are defendants in four cases, including one case initiated by the State of Maryland, 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, and Sunoco Partners Marketing & Terminals L.P., now known as Energy Transfer Marketing & Terminals L.P.

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.

Litigation Filed By or Against Williams

In April and May 2016, The William Companies, Inc. (“Williams”) filed two lawsuits (the “Williams Litigation”) against Energy Transfer, LE GP, LLC, and, in one of the lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC (collectively, “Energy Transfer Defendants”), alleging that Energy Transfer Defendants breached their obligations under the Energy Transfer-Williams merger agreement (the “Merger Agreement”). In general, Williams alleges that Energy Transfer 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 Energy Transfer Defendants and issued a declaratory judgment that Energy Transfer 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 certain of 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 (the “Termination Fee”) based on the alleged breaches of the Merger Agreement listed above. Energy Transfer 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 Energy Transfer 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 was held regarding the parties’ amended claims on May 10-17, 2021, and on December 29, 2021, the Court ruled in favor of Williams and awarded it the Termination Fee plus certain fees and expenses, holding that the Issuance breached the Merger Agreement and that Williams had not materially breached the Merger Agreement, though the Court awarded sanctions against Williams due to its CEO’s intentional spoliation of evidence. The Court subsequently awarded Williams approximately $190 million in attorneys’ fees, expenses and pre-judgment interest.

On September 21, 2022, the Court entered a final judgment against the Energy Transfer Defendants in the amount of approximately $601 million plus post-judgment interest at a rate of 3.5% per year. The Energy Transfer Defendants filed the notice of appeal of this matter on October 21, 2022 and filed their opening brief in support of their appeal on December 30, 2022. Williams filed their answering brief on January 20, 2023, and the Energy Transfer Defendants filed their reply brief on February 6, 2023.

Rover - State of Ohio

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (together “the Ohio EPA”) filed suit against Rover and five other defendants seeking to recover civil penalties allegedly owed and certain injunctive relief related to permit compliance. The defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court, which the defendants opposed in briefs filed in February 2020. On April 22, 2020, the Ohio Supreme Court granted the Ohio EPA’s request for review. On March 17, 2022, the Ohio Supreme Court reversed in part and remanded to the Ohio trial court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the Clean Water Act but remanded to the trial court to determine whether any of the allegations fell outside the scope of the waiver.

On remand, the Ohio EPA voluntarily dismissed four of the other five defendants and dismissed one of its counts against Rover. In its Fourth Amended Complaint, the Ohio EPA removed all paragraphs that alleged violations by the four dismissed defendants, including those where the dismissed defendants were alleged to have acted jointly with Rover or others. At a June 2, 2022, status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions to dismiss the Fourth Amended Complaint. On August 1, 2022, Rover and the other remaining defendant each

filed their respective motions. Briefing on those motions was completed on November 4, 2022. The motions remain pending before the court.

Chester County, Pennsylvania Investigation

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

Subsequently, the matter was submitted to an Investigating Grand Jury in Chester County, Pennsylvania, which has issued subpoenas seeking documents and testimony. On September 24, 2019, the Chester County DA sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership responded to the Notice of Intent within the prescribed time period.

In December 2019, the Chester County DA announced charges against a current employee related to the provision of security services. On June 25, 2020, a preliminary hearing was held on the charges against the employee, and the judge dismissed all charges.

On April 22, 2021, the Chester County DA filed a Complaint and Consent Decree in the Court of Common Pleas of Chester County, Pennsylvania constituting a settlement agreement between the Chester County DA and the Partnership. A status conference was held on May 10, 2021, and an Amended Consent Decree was filed on June 16, 2021, which was approved and entered by the Court on December 20, 2021. In accordance with the terms of the Amended Consent Decree, when the Mariner East 2/Mariner East 2X pipelines reached the point of mechanical completion in Chester County on March 23, 2022, the Amended Consent Decree terminated, which the Partnership communicated to the Chester County DA via letter on March 29, 2022. A Joint Motion for Termination of the Amended Consent Decree was filed on August 26, 2022. On January 14, 2023, the Court entered an Order terminating the Amended Consent Decree dated December 20, 2021. This matter is now closed.

Shareholder Litigation Regarding Pipeline Construction

Various purported unitholders of Energy Transfer have filed derivative actions against various past and current members of Energy Transfer’s Board of Directors, LE GP, LLC, and Energy Transfer, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, breach of Energy Transfer’s Partnership Agreement, tortious interference, abuse of control, and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania and Ohio. They also seek damages and changes to Energy Transfer’s corporate governance structure. See Bettiol v. LE GP, Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren, Cause No. DC-20-02322 (44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren, Case No. 2:20-cv-00364-GAM (E.D. Pa.); King v. LE GP, Case No. 3:20-cv-00719-X (N.D. Tex.); Inter-Marketing Group USA, Inc. v. LE GP, et at., Case No. 2022-0139-SG (Del. Ch.); Elliot v. LE GP LLC, Case No. 3:22-cv-01527-B (N.D. Tex.); Chapa v. Kelcy L. Warren, et al., Index No. 611307/2022 (N.Y. Sup. Ct.); Elliott v. LE GP et al, Cause No. DC-22-14194 (Dallas County, Tex.); and King v. LE GP, LLC et al, Cause No. DC-22-14159 (Dallas County, Texas). The King action that was filed in the United States District Court for the Northern District of Texas (Case No. 3:20-cv-00719-X) has been consolidated with the Bettiol action. On August 9, 2022, the Elliot action that was filed in the United States District Court for the Northern District of Texas (Case No. 3:22-cv-01527-B) was voluntarily dismissed.

Another purported unitholder of Energy Transfer, Allegheny County Employees’ Retirement System (“ACERS”), individually and on behalf of all others similarly situated, filed a suit under the federal securities laws purportedly on behalf of a class, against Energy Transfer and three of Energy Transfer’s directors, Kelcy L. Warren, John W. McReynolds, and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP, Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an amended complaint and added as additional defendants Energy Transfer directors Marshall McCrea and Matthew Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The amended complaint asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the construction of pipelines in Pennsylvania. On August 14, 2020, the defendants filed a motion to dismiss ACERS’ amended complaint. On April 6, 2021, the court granted in part and denied in part the defendants’ motion to dismiss. The court held that ACERS could proceed with its claims regarding certain statements put at issue by the amended complaint while also dismissing claims based on other statements. The court also dismissed without prejudice the claims against defendants McReynolds, McGinn, and Hennigan. Fact discovery is ongoing. On August 23, 2022, the Court granted in part and denied in part ACERS’ motion for class certification. The Court certified a class consisting of those who purchased or otherwise acquired common units of Energy Transfer between February 25, 2017 and November 11, 2019.

On June 3, 2022, another purported unitholder of Energy Transfer, Mike Vega, filed suit, purportedly on behalf of a class, against Energy Transfer and Messrs. Warren, Long, McCrea, and Whitehurst. See Vega v. Energy Transfer LP et al., Case No. 1:22-cv-4614 (S.D.N.Y.). The action asserts claims for violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder related primarily to statements made in connection with the construction of the Rover pipeline project.

On August 10, 2022, the Court appointed the New Mexico State Investment Council and Public Employees Retirement Association of New Mexico (the “New Mexico Funds”) as lead plaintiffs. New Mexico Funds filed an amended complaint on September 30, 2022 and added as additional defendants Energy Transfer directors John W. McReynolds and Matthew S. Ramsey. Defendants filed their motion to dismiss the amended complaint on November 4, 2022. On November 7, 2022, the court granted Defendants’ motion to transfer and transferred this action to the United States District Court for the Northern District of Texas.

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.

Cline Class Action

On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco, Inc. (R&M), LLC (now known as Energy Transfer (R&M), LLC) and Energy Transfer Marketing & Terminals L.P. (collectively, “ETMT”) that alleged ETMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012, and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments, and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.

After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $74.8 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $80.7 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees.

On August 27, 2020, ETMT filed its Notice of Appeal with the 10th Circuit and appealed the entirety of the Order. The matter was fully briefed, and oral argument was set for November 15, 2021. However, on November 1, 2021, the 10th Circuit dismissed the appeal due to jurisdictional concerns with finality of the Order. En banc rehearing of this decision was denied on November 29, 2021. On December 1, 2021, ETMT filed a Petition for Writ of Mandamus to the 10th Circuit to correct the jurisdictional problems and secure final judgment. On February 2, 2022, the 10th Circuit denied the Petition for Writ of Mandamus, citing that there are other avenues for ETMT to obtain adequate relief. On February 10, 2022, ETMT filed a Motion to Modify the Plan of Allocation Order and Issue a Rule 58 Judgment with the trial court, requesting the district court to enter a final judgment in compliance with the Rules. ETMT also filed an injunction with the trial court to enjoin all efforts by plaintiffs to execute on any non-final judgment. On March 31, 2022, Judge Gibney denied the Motion to Modify the Plan of Allocation, reiterating his thoughts that the order constitutes a final judgment. Judge Gibney granted the injunction in part (placing a hold on enforcement efforts for 60 days) and denied the injunction in part. The injunction has since been lifted.

Despite the fact that ETMT has taken the position that the judgment is not final and not subject to execution, the Class engaged in asset discovery and actively tried to collect on the judgment through garnishment proceedings from ETMT’s customers. ETMT unsuccessfully tried to deposit the funds into the Court’s Registry. Accordingly, to stop the garnishment proceedings, on December 2, 2022, ETMT wired approximately $161 million to the Plaintiff’s approved Plan Administrator, which represents the full amount of the judgment with attorney’s fees and post-judgment interest. ETMT did so without waiving its ability to pursue its pending appeal or its right to appeal the merits of the judgment. Plaintiff has since dismissed the garnishment actions.

ETMT cannot predict the outcome of the case, nor can ETMT predict the amount of time and expense that will be required to resolve the appeal. A Petition for Writ of Certiorari was filed with the United States Supreme Court on April 28, 2022, seeking review of the 10th Circuit’s dismissal of ETMT’s appeal. The Supreme Court denied ETMT’s Petition on October 3, 2022. Despite the denial of its Petition for Writ of Certiorari, ETMT is still vigorously appealing the finality issues underlying the Order and has appealed the denial of the Motion to Modify to the 10th Circuit in an attempt to get a decision on finality. The appeal to the 10th Circuit has been fully briefed and oral argument is set for March 21, 2023.

Energy Transfer LP and ETC Texas Pipeline, Ltd. v. Culberson Midstream LLC, et al.

On April 8, 2022, Energy Transfer and ETC Texas Pipeline, Ltd. (“ETC,” and together with Energy Transfer, “Plaintiffs”) filed suit against Culberson Midstream LLC (“Culberson”), Culberson Midstream Equity, LLC (“Culberson Equity”), and Moontower Resources Gathering, LLC (“Moontower,” and together with Culberson and Culberson Equity, “Defendants”). On October 1, 2018, ETC and Culberson entered into a Gas Gathering and Processing Agreement (the “Bypass GGPA”) under which Culberson was to gather gas from its dedicated acreage and deliver all committed gas exclusively to ETC. In connection with the Bypass GGPA, on October 18, 2018, Energy Transfer and Culberson Equity also entered into an Option Agreement. Under the Option Agreement, Culberson Equity and Moontower had the right (but not the obligation) to require Energy Transfer to purchase their respective interests in Culberson by way of a put option. Notably, the Option Agreement is only enforceable so long as the parties comply with the Bypass GGPA. In late March 2022, Culberson Equity and Moontower submitted a put notice to Energy Transfer seeking to require Energy Transfer to purchase their respective interests in Culberson for approximately $93 million. On April 8, 2022, Plaintiffs filed suit against Defendants asserting claims for declaratory judgment and breach of contract. Plaintiffs contend that Defendants materially breached the Bypass GGPA by sending some committed gas to third parties and also by failing to send any gas to Plaintiffs since March 2020, and thus that Defendants' put notice is void. Defendants have answered the lawsuit. Culberson filed a counterclaim against ETC for breach of the Bypass GGPA, seeking the recovery of damages and attorneys’ fees. Culberson Equity and Moontower also filed a counterclaim against Energy Transfer for (1) breach of the Option Agreement, and (2) a declaratory judgment concerning Energy Transfer’s alleged obligation to purchase the Culberson interests. The lawsuit is pending in the 193rd Judicial District Court in Dallas County, Texas. On April 27, 2022, Defendants filed an application for a temporary restraining order, temporary injunction, and permanent injunction. The Court held a hearing on the application on April 28 and denied the injunction. In early May, Culberson filed a motion to enforce the appraisal process and confirm the validity of their put price calculation, to which Plaintiffs objected. On July 11, 2022, the Court held a hearing on the motion, and on July 19, 2022, the Court ordered the parties to engage in an appraisal process regarding the put price. An independent appraiser was appointed and issued his decision on October 15, 2022, concluding that the put price totals $93 million. Plaintiffs have consistently reiterated their objection to the appraisal process. Defendants filed a motion for summary judgment, but the Court has postponed considering it until the spring of 2023, after further document discovery and depositions. On December 7, 2022, Plaintiffs amended their petition to add a claim against all Defendants for fraudulent inducement. Plaintiffs cannot predict the ultimate outcome of this litigation or the amount of time and expense that will be required to resolve it.

Massachusetts Attorney General v. New England Gas Company

On July 7, 2011, the Massachusetts Attorney General (the “MA AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“DPU”) against New England Gas Company (“NEG”) with respect to certain environmental cost recoveries. NEG was an operating division of Southern Union Company (“SUG”), and the NEG assets were acquired in connection with the merger transaction with Energy Transfer in March 2012. Subsequent to the merger, in 2013, SUG sold the NEG assets to Liberty Utilities (“Liberty,” and together with NEG and SUG, “Respondents”) and retained certain potential liabilities, including the environmental cost recoveries with respect to the pending complaint before the DPU. Specifically, the MA AG seeks a refund to NEG’s ratepayers for approximately $18 million in legal fees associated with SUG environmental response activities. The MA AG requests that the DPU initiate an investigation into NEG’s collection and reconciliation of recoverable environmental costs, namely: (1) the legal fees charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005; (2) the legal fees charged by the Bishop, London & Dodds firm and passed through the recovery mechanisms since 2005; and (3) the legal fees passed through the recovery mechanism that the MA AG contends only qualify for a lesser (i.e., 50 percent) level of recovery. Respondents maintain that, by tariff, these costs are recoverable through rates charged to NEG customers pursuant to the environmental remediation adjustment clause program. After the Respondents answered the complaint and filed a motion to dismiss in 2011, the Hearing Officer deferred decision on the motion to dismiss and issued a stay of discovery pending resolution of a discovery dispute, which it later lifted on June 24, 2013, permitting the case to resume. However, the MA AG failed to take any further steps to prosecute its claims for nearly seven years. The case remained largely dormant until February 2022, when the Hearing Officer denied the motion to dismiss. After receiving input from the parties, the Hearing Officer entered a procedural schedule on March 16, 2022 (which was amended slightly on August 22, 2022). The parties are now actively engaged in discovery and the preparation of pre-filed testimony. Respondents submitted their pre-filed testimony on July 11, 2022. The MA AG served three sets of discovery requests on Respondents on September 9, September 12, and September 20, respectively, to which Respondents timely responded. On October 5, 2022, the MA AG requested that the DPU issue a ruling on whether the information that Respondents redacted in their attorneys’ fees invoices is protected by the attorney-client privilege. On the same day, the MA AG also filed a Motion to Stay the Procedural Schedule pending a ruling on the privilege issue. On October 6, 2022, without even affording Respondents the opportunity to respond, the DPU granted the MA AG’s request to stay the procedural schedule.

Accordingly, all previous deadlines (including the MA AG’s October 7, 2022, deadline to submit direct pre-filed testimony) are presently stayed. Respondents cannot predict the ultimate outcome of this regulatory proceeding, nor can they predict the amount of time and expense that will be required to resolve these claims; however, Respondents will vigorously defend themselves against the MA AG’s claims.

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.

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

•the Partnership 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, 2022, the Partnership had been named as a PRP at approximately 31 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. The Partnership is usually one of a number of companies identified as a PRP at a site. The Partnership has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon the Partnership’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 following table 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,
	2022		2021
Current	$	54	$	46
Non-current	228		247
Total environmental liabilities	$	282	$	293

We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the years ended December 31, 2022 and 2021, the Partnership recorded $30 million and $28 million, respectively, of expenditures related to environmental cleanup programs.

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

Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

Revenue (Notes)

12 Months Ended

Dec. 31, 2022

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE:

Disaggregation of revenue

The major types of revenue within our reportable segments, are as follows:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services;

•investment in Sunoco LP;

•fuel distribution and marketing;

•all other;

•investment in USAC;

•contract operations;

•retail parts and services; and

•all other.

Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606.

Intrastate transportation and storage revenue

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

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

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

Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.

Interstate transportation and storage revenue

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

The performance obligation with respect to 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 transportation and services 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.

Crude oil transportation and services revenue

Our crude oil transportation and services segment’s 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.

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 is recognized ratably over the term of the underlying lease.

Sunoco LP’s all other revenue

Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided).

USAC’s contract operations revenue

USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years; however, USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract.

Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower.

USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin.

The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date.

There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration.

USAC’s retail parts and services revenue

USAC’s retail parts and services revenue is primarily earned on directly reimbursable freight and crane charges that are the financial responsibility of 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 on 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.

Contract Balances with Customers

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

The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services.

The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed minimum fee, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.

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


	Contract Liabilities
Balance, December 31, 2020	$	309
Additions	849
Revenue recognized	(699)
Balance, December 31, 2021	459
Additions	1,113
Revenue recognized	(944)
Other	(13)
Balance, December 31, 2022	$	615

The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2022 and 2021 were as follows:


	December 31,
	2022		2021
Contract Balances
Contract asset	$	200	$	157
Accounts receivable from contracts with customers	834		463

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 the 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, 2022, 2021 and 2020 was $22 million, $21 million and $18 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 following table.

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 ten years, with an estimated volume-weighted term remaining of approximately five years.

Sunoco LP is party to 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, 2022, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $39.20 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:


	Years Ending December 31,
	2023		2024		2025		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of December 31, 2022	$	7,038	$	6,023	$	5,158	$	20,982	$	39,201

Practical Expedients Utilized by the Partnership

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

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

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

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

•Incremental costs of obtaining a contract: The Partnership generally expenses sales commissions when incurred because the amortization period would have been less than one year. We record these costs within general and administrative expenses. The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less.

•Shipping and handling costs: The Partnership elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities (i.e., an expense) rather than as a promised service.

•Measurement of transaction price: The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership from a customer (i.e., sales tax, value added tax, etc.).

•Variable consideration of wholly unsatisfied performance obligations: The Partnership has elected to exclude the estimate of variable consideration to the allocation of wholly unsatisfied performance obligations.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI https://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 9
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (e)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

+ Details

Lease Accounting (Notes)

12 Months Ended

Dec. 31, 2022

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, 2022 and 2021 were as follows:


	December 31,
	2022		2021
Operating leases:
Lease right-of-use assets, net	$	808	$	826
Operating lease current liabilities	45		47
Accrued and other current liabilities	1		1
Non-current operating lease liabilities	798		814
Finance leases:
Property, plant and equipment, net	$	1	$	1
Lease right-of-use assets, net	11		12
Accrued and other current liabilities	—		1
Current maturities of long-term debt	2		3
Long-term debt, less current maturities	9		9
Other non-current liabilities	1		1

The components of lease expense for the years ended December 31, 2022 and 2021 were as follows:


		Year Ended December 31,
	Income Statement Location	2022		2021
Operating lease costs:
Operating lease cost	Cost of goods sold	$	3	$	10
Operating lease cost	Operating expenses	63		78
Operating lease cost	Selling, general and administrative	22		17
Total operating lease costs		88		105
Finance lease costs:
Amortization of lease assets	Depreciation, depletion and amortization	—		1
Interest on lease liabilities	Interest expense, net of capitalized interest	—		1
Total finance lease costs		—		2
Short-term lease cost	Operating expenses	33		40
Variable lease cost	Operating expenses	13		9
Lease costs, gross		134		156
Less: Sublease income	Other revenue	40		45
Lease costs, net		$	94	$	111

The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2022 and 2021 were as follows:


	December 31,
	2022		2021
Weighted-average remaining lease term (years):
Operating leases	21		19
Finance leases	27		29
Weighted-average discount rate (%):
Operating leases	5	%	5	%
Finance leases	4	%	4	%

Cash flows and non-cash activity related to leases for the years ended December 31, 2022 and 2021 were as follows:


	Year Ended December 31,
	2022		2021


Operating cash flows from operating leases	$	(133)	$	(147)



Lease assets obtained in exchange for new finance lease liabilities	1		9
Lease assets obtained in exchange for new operating lease liabilities	41		9

Maturities of lease liabilities as of December 31, 2022 are as follows:


	Operating leases		Finance leases		Total
2023	$	86	$	3	$	89
2024	81		1		82
2025	79		—		79
2026	77		—		77
2027	71		—		71
Thereafter	1,027		15		1,042
Total lease payments	1,421		19		1,440
Less: present value discount	578		6		584
Present value of lease liabilities	$	843	$	13	$	856

Lessor Accounting

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

Sunoco LP’s future minimum operating lease payments receivable as of December 31, 2022 are as follows:


	Lease Payments
2023	$	67
2024	47
2025	45
2026	43
2027	41
Thereafter	25
Total undiscounted cash flows	$	268

Derivative Assets And Liabilities

12 Months Ended

Dec. 31, 2022

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 natural gas, 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 intrastate 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 intrastate 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, 2022		December 31, 2021
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	145	2023	585	2022-2023
Basis Swaps IFERC/NYMEX(1)	(39,563)	2023	(66,665)	2022


Power (Megawatt):
Forwards	—	2023-2029	653,000	2023-2029
Futures	(21,384)	2023	(604,920)	2022-2023
Options – Puts	119,200	2023	(7,859)	2022
Options – Calls	—	—	(30,932)	2022

(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	42,440	2023-2024	6,738	2022-2023
Swing Swaps IFERC	(202,815)	2023-2024	(106,333)	2022-2023
Fixed Swaps/Futures	(15,758)	2023-2025	(63,898)	2022-2023
Forward Physical Contracts	2,423	2023-2024	(5,950)	2023

NGL (MBbls) – Forwards/Swaps	6,934	2023-2025	8,493	2022-2024
Crude (MBbls) – Forwards/Swaps	795	2023-2024	3,672	2022-2023
Refined Products (MBbls) – Futures	(3,547)	2023-2024	(3,349)	2022-2023

Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(37,448)	2023	(40,533)	2022
Fixed Swaps/Futures	(37,448)	2023	(40,533)	2022
Hedged Item – Inventory	37,448	2023	40,533	2022

(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, 2022		December 31, 2021
July 2022 (2)	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	$	—	$	400
July 2023 (2)(3)	Forward-starting to pay a fixed rate of 3.845% and receive a floating rate	—		200
July 2024 (2)	Forward-starting to pay a fixed rate of 3.512% and receive a floating rate	400		200

(1)Floating rates are based on either SOFR or three-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) This interest rate swap was terminated and settled in 2022.

Credit Risk and Customers

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.

Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, 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, 2022		December 31, 2021		December 31, 2022		December 31, 2021
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	87	$	46	$	(7)	$	(3)
	87		46		(7)		(3)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	506		173		(411)		(156)
Commodity derivatives	95		53		(108)		(52)



Interest rate derivatives	—		—		(23)		(387)
	601		226		(542)		(595)
Total derivatives	$	688	$	272	$	(549)	$	(598)

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, 2022		December 31, 2021		December 31, 2022		December 31, 2021
Derivatives without offsetting agreements	Derivative liabilities	$	—	$	—	$	(23)	$	(387)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	95		53		(108)		(52)
Broker cleared derivative contracts	Other current assets (liabilities)	593		219		(418)		(159)
		688		272		(549)		(598)
Offsetting agreements:

Counterparty netting	Derivative assets (liabilities)	(85)		(43)		85		43
Counterparty netting	Other current assets (liabilities)	(359)		(150)		359		150
Total net derivatives		$	244	$	79	$	(105)	$	(405)

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.

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 on Derivatives
		Years Ended December 31,
		2022		2021		2020
Derivatives not designated as hedging instruments:

Commodity derivatives – Trading	Cost of products sold	$	83	$	(6)	$	8
Commodity derivatives – Non-trading	Cost of products sold	41		(141)		(34)

Interest rate derivatives	Gains (losses) on interest rate derivatives	293		61		(203)

Total		$	417	$	(86)	$	(229)

Retirement Benefits

12 Months Ended

Dec. 31, 2022

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 Sunoco LP and USAC. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $79 million, $65 million and $35 million to these 401(k) savings plans for the years ended December 31, 2022, 2021 and 2020, respectively.

As a result of the economic conditions in 2020, effective June 8, 2020, the Partnership ceased employer matching and profit sharing contributions through December 31, 2020. The Partnership resumed all such contributions in 2021.

Pension and Other Postretirement Benefit Plans

Certain of the Partnership’s subsidiaries sponsor pension and/or other postretirement benefit plans that provide benefits to a defined group of retirees. 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, 2022						December 31, 2021
	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	$	50	$	26	$	195	$	55	$	31	$	208
Service cost	—		—		1		—		—		1
Interest cost	1		1		4		1		1		4

Benefits paid, net	(1)		(3)		(14)		(2)		(4)		(16)

Actuarial gain and other	(8)		(3)		(38)		(2)		(2)		(2)
Settlements	—		—		—		(2)		—		—
Energy Transfer Canada sale	(20)		(2)		—		—		—		—
Benefit obligation at end of period	22		19		148		50		26		195

Change in plan assets:
Fair value of plan assets at beginning of period	44		—		311		45		—		291
Return on plan assets and other	(4)		—		(41)		2		—		26
Employer contributions	1		—		3		1		—		10
Benefits paid, net	(1)		—		(14)		(2)		—		(16)
Settlements	—		—		—		(2)		—		—
Energy Transfer Canada sale	(20)		—		—		—		—		—
Fair value of plan assets at end of period	20		—		259		44		—		311

Amount underfunded (overfunded) at end of period	$	2	$	19	$	(111)	$	6	$	26	$	(116)

Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	$	—	$	—	$	127	$	—	$	—	$	138
Current liabilities	—		(3)		(2)		—		(4)		(2)
Non-current liabilities	(2)		(16)		(14)		(6)		(22)		(20)
	$	(2)	$	(19)	$	111	$	(6)	$	(26)	$	116

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	$	—	$	(2)	$	5	$	—	$	1	$	(27)
Prior service cost (credit)	—		—		(3)		—		—		19
	$	—	$	(2)	$	2	$	—	$	1	$	(8)

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:


	December 31, 2022					December 31, 2021
	Pension Benefits					Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits	Funded Plans		Unfunded Plans		Other Postretirement Benefits
Projected benefit obligation	$	22	$	19	N/A	$	50	$	26	N/A
Accumulated benefit obligation	22		19		148	50		26		195
Fair value of plan assets	20		—		259	44		—		311

Components of Net Periodic Benefit Cost


	December 31, 2022				December 31, 2021
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—	$	1	$	—	$	1
Interest cost	2		4		2		4
Expected return on plan assets	(2)		(11)		(2)		(11)
Prior service cost amortization	—		19		—		19




Net periodic benefit cost	$	—	$	13	$	—	$	13

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the following table:


	December 31, 2022				December 31, 2021
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	5.00	%	2.46	%	2.79	%	2.24	%

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the following table:


	December 31, 2022				December 31, 2021
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	2.70	%	2.58	%	2.57	%	2.18	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	4.76	%	7.00	%
Taxable accounts	—		4.75	%	—		4.75	%

The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.

The assumed health care cost trend weighted-average rates used to measure the expected cost of benefits covered by the plans are shown in the following table:


	December 31,
	2022		2021
Health care cost trend rate	7.48	%	7.14	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.18	%	4.95	%
Year that the rate reaches the ultimate trend rate	2030		2028

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, 2022
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	2	$	2	$	—	$	—
Mutual funds (1)	18		18		—		—

Total	$	20	$	20	$	—	$	—

(1)Comprised of approximately 100% equities as of December 31, 2022.


			Fair Value Measurements at December 31, 2021
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	1	$	1	$	—	$	—
Mutual funds (1)	24		24		—		—
Fixed income securities	19		—		19		—
Total	$	44	$	25	$	19	$	—

(1)Comprised of approximately 100% equities as of December 31, 2021.

The fair value of other postretirement plan assets by asset category at the dates indicated is as follows:


			Fair Value Measurements at December 31, 2022
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Cash and cash equivalents	$	19	$	19	$	—	$	—
Mutual funds(1)	146		146		—		—
Fixed income securities	94		—		94		—
Total	$	259	$	165	$	94	$	—

(1)Primarily composed of market index funds as of December 31, 2022.


			Fair Value Measurements at December 31, 2021
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Cash and cash equivalents	$	22	$	22	$	—	$	—
Mutual funds(1)	175		175		—		—
Fixed income securities	114		—		114		—
Total	$	311	$	197	$	114	$	—

(1)Primarily composed of market index funds as of December 31, 2021.

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 $5 million to pension plans and $1 million to other postretirement plans in 2023. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

Benefit Payments

The Partnership’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 following table:


Years	Pension Benefits - Funded Plans		Pension Benefits - Unfunded Plans		Other Postretirement Benefits (Gross, Before Medicare Part D)
2023	$	1	$	4	$	16
2024	1		3		15
2025	1		3		15
2026	1		2		14
2027	1		2		13
2028 – 2032	7		6		55

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.

The Partnership does not expect to receive any Medicare Part D subsidies in any future periods.

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 55
-Paragraph 17
-URI https://asc.fasb.org/extlink&oid=123450688&loc=d3e4179-114921

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section S99
-Paragraph 2
-URI https://asc.fasb.org/extlink&oid=21916913&loc=d3e273930-122802

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)(i)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (o)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (p)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 70
-Section 50
-Paragraph 1
-URI https://asc.fasb.org/extlink&oid=49170846&loc=d3e28014-114942

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-URI https://asc.fasb.org/topic&trid=2235017

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 60
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=6414203&loc=d3e39689-114964

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (q)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (r)(1)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)(iii)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (l)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (r)(2)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

+ Details

Reportable Segments

12 Months Ended

Dec. 31, 2022

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.

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

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

The following tables present financial information by segment:


	Years Ended December 31,
	2022		2021		2020
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	6,954	$	7,307	$	2,312
Intersegment revenues	864		1,264		232
	7,818		8,571		2,544
Interstate transportation and storage:
Revenues from external customers	2,185		1,802		1,841
Intersegment revenues	66		39		20
	2,251		1,841		1,861
Midstream:
Revenues from external customers	4,114		2,620		1,944
Intersegment revenues	12,987		8,696		3,082
	17,101		11,316		5,026
NGL and refined products transportation and services:
Revenues from external customers	21,414		16,989		8,501
Intersegment revenues	4,243		2,972		2,012
	25,657		19,961		10,513
Crude oil transportation and services:
Revenues from external customers	25,980		17,442		11,674
Intersegment revenues	2		4		5
	25,982		17,446		11,679
Investment in Sunoco LP:
Revenues from external customers	25,677		17,571		10,653
Intersegment revenues	52		25		57
	25,729		17,596		10,710
Investment in USAC:
Revenues from external customers	689		621		655
Intersegment revenues	16		12		12
	705		633		667
All other:
Revenues from external customers	2,863		3,065		1,374
Intersegment revenues	711		411		464
	3,574		3,476		1,838
Eliminations	(18,941)		(13,423)		(5,884)
Total revenues	$	89,876	$	67,417	$	38,954


	Years Ended December 31,
	2022		2021		2020
Cost of products sold:
Intrastate transportation and storage	$	6,000	$	4,769	$	1,478
Interstate transportation and storage	25		11		—
Midstream	12,682		8,569		2,598
NGL and refined products transportation and services	21,656		16,248		7,139
Crude oil transportation and services	22,917		14,759		8,838
Investment in Sunoco LP	24,350		16,246		9,654
Investment in USAC	111		85		82
All other	3,328		3,068		1,527
Eliminations	(18,837)		(13,360)		(5,829)
Total cost of products sold	$	72,232	$	50,395	$	25,487


	Years Ended December 31,
	2022		2021		2020
Depreciation, depletion and amortization:
Intrastate transportation and storage	$	209	$	191	$	185
Interstate transportation and storage	513		457		411
Midstream	1,351		1,190		1,140
NGL and refined products transportation and services	865		778		667
Crude oil transportation and services	663		588		640
Investment in Sunoco LP	193		177		189
Investment in USAC	237		239		239
All other	133		197		207
Total depreciation, depletion and amortization	$	4,164	$	3,817	$	3,678


	Years Ended December 31,
	2022		2021		2020
Equity in earnings (losses) of unconsolidated affiliates:
Intrastate transportation and storage	$	17	$	20	$	18
Interstate transportation and storage	175		140		17
Midstream	19		24		24
NGL and refined products transportation and services	42		51		60
Crude oil transportation and services	—		10		(2)


All other	4		1		2
Total equity in earnings of unconsolidated affiliates	$	257	$	246	$	119


	Years Ended December 31,
	2022		2021		2020
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	1,396	$	3,483	$	863
Interstate transportation and storage	1,753		1,515		1,680
Midstream	3,210		1,868		1,670
NGL and refined products transportation and services	3,025		2,828		2,802
Crude oil transportation and services	2,187		2,023		2,258
Investment in Sunoco LP	919		754		739
Investment in USAC	426		398		414
All Other	177		177		105
Adjusted EBITDA (consolidated)	$	13,093	$	13,046	$	10,531


	Years Ended December 31,
	2022		2021		2020
Reconciliation of net income to Adjusted EBITDA:
Net income	$	5,868	$	6,687	$	140
Depreciation, depletion and amortization	4,164		3,817		3,678
Interest expense, net of interest capitalized	2,306		2,267		2,327
Income tax expense	204		184		237
Impairment losses and other	386		21		2,880
(Gains) losses on interest rate derivatives	(293)		(61)		203
Non-cash compensation expense	115		111		121
Unrealized (gains) losses on commodity risk management activities	(42)		(162)		71
Inventory valuation adjustments	(5)		(190)		82
Losses on extinguishments of debt	—		38		75
Adjusted EBITDA related to unconsolidated affiliates	565		523		628
Equity in earnings of unconsolidated affiliates	(257)		(246)		(119)
Impairment of investments in unconsolidated affiliates	—		—		129
Other, net	82		57		79
Adjusted EBITDA (consolidated)	$	13,093	$	13,046	$	10,531


	December 31,
	2022		2021		2020
Segment assets:
Intrastate transportation and storage	$	6,609	$	7,322	$	6,308
Interstate transportation and storage	17,979		17,774		17,582
Midstream	21,851		21,960		18,583
NGL and refined products transportation and services	27,903		28,160		21,423
Crude oil transportation and services	19,200		19,649		17,960
Investment in Sunoco LP	6,830		5,815		5,267
Investment in USAC	2,666		2,768		2,949
All other and eliminations	2,605		2,515		5,072
Total segment assets	$	105,643	$	105,963	$	95,144


	Years Ended December 31,
	2022		2021		2020
Additions to property, plant and equipment (1):
Intrastate transportation and storage	$	179	$	52	$	49
Interstate transportation and storage	644		159		150
Midstream	1,004		484		487
NGL and refined products transportation and services	507		751		2,403
Crude oil transportation and services	246		343		291
Investment in Sunoco LP	186		174		124
Investment in USAC	169		60		119
All other	91		135		136
Total additions to property, plant and equipment (1)	$	3,026	$	2,158	$	3,759

(1)Amounts are presented on the accrual basis, net of contributions in aid of constructions costs. Amounts exclude acquisitions and include only the Partnership’s proportionate share of capital expenditures related to joint ventures.


	December 31,
	2022		2021		2020
Investments in unconsolidated affiliates:
Intrastate transportation and storage	$	139	$	110	$	89
Interstate transportation and storage	2,201		2,209		2,278
Midstream	54		101		110
NGL and refined products transportation and services	446		476		509
Crude oil transportation and services	—		—		22


All other	53		51		52
Total investments in unconsolidated affiliates	$	2,893	$	2,947	$	3,060

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8924-108599

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8981-108599

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 21
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8721-108599

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e9031-108599

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (f)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8933-108599

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (e)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e9038-108599

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8933-108599

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8736-108599

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e9054-108599

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 15
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8657-108599

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 21
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8721-108599

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-URI https://asc.fasb.org/topic&trid=2134510

+ Details

Operations And Organization Operations and Organization (Policies)	12 Months Ended
	Dec. 31, 2022
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, 2022, 2021 and 2020, 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.

Estimates, Significant Accounting Policies and Balance Sheet Detail (Policy)

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Use of Estimates

Regulatory Accounting - Regulatory Assets and Liabilities

Regulatory Accounting – Regulatory Assets and Liabilities

Cash, Cash Equivalents and Supplemental Cash Flow Information

Accounts Receivable

Inventories

The Partnership’s inventories consisted of the following:


	December 31,
	2022		2021
Natural gas, NGLs and refined products	$	1,802	$	1,259
Crude oil	246		328
Spare parts and other	413		427
Total inventories	$	2,461	$	2,014

Property, Plant and Equipment

capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization.

Intangible Assets

Components and useful lives of intangible assets were as follows:


	December 31, 2022				December 31, 2021
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	7,884	$	(2,807)	$	7,982	$	(2,464)
Patents (10 years)	48		(48)		48		(44)

Trade names (20 years)	66		(41)		66		(38)
Other (5 to 20 years)	12		(13)		19		(20)
Total amortizable intangible assets	8,010		(2,909)		8,115		(2,566)
Non-amortizable intangible assets:
Trademarks	302		—		295		—
Other	12		—		12		—
Total non-amortizable intangible assets	314		—		307		—
Total intangible assets	$	8,324	$	(2,909)	$	8,422	$	(2,566)

Aggregate amortization expense of intangible assets was as follows:


	Years Ended December 31,
	2022		2021		2020
Reported in depreciation, depletion and amortization expense	$	390	$	352	$	403

Estimated aggregate amortization of intangible assets for the next five years is as follows:


Years Ending December 31:
2023	$	357
2024	344
2025	331
2026	327
2027	309

Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test was performed during the fourth quarter.

Changes in the carrying amount of goodwill were 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		Investment in USAC		All Other		Total
Balance, December 31, 2020	$	—	$	—	$	—	$	693	$	52	$	1,564	$	—	$	82	$	2,391
Acquired	—		—		—		—		138		4		—		—		142



Balance, December 31, 2021	—		—		—		693		190		1,568		—		82		2,533
Acquired	—		—		—		—		—		33		—		—		33



Balance, December 31, 2022	$	—	$	—	$	—	$	693	$	190	$	1,601	$	—	$	82	$	2,566

value estimates used in the long-lived asset and goodwill tests were primarily based on Level 3 inputs of the fair value hierarchy.

Asset Retirement Obligation

Asset Retirement Obligations

Redeemable Noncontrolling Interest [Text Block]

Redeemable Noncontrolling Interests Our redeemable noncontrolling interests relate to certain preferred unitholders of one of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in one of our consolidated subsidiaries that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable noncontrolling interests on our consolidated balance sheets. See Note 7 for further information.

Environmental Costs, Policy [Policy Text Block]

Environmental RemediationWe 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.

Contributions In Aid Of Construction Costs Policy Text Block

Contributions in Aid of Construction Costs

Costs and Expenses

Issuances of Subsidiary Units

Issuances of Subsidiary UnitsWe record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interests are adjusted as a change in partners’ capital.

Income Taxes

Accounting for Derivative Instruments and Hedging Activities

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.

Share-based Payment Arrangement [Policy Text Block]

Pension and Other Postretirement Plans, Policy [Policy Text Block]

Pensions and Other Postretirement Benefit PlansThe 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

Equity Method Investments Issuances, Policy

Investments in Unconsolidated Affiliates

Revenue (Policies)	12 Months Ended
Revenue (Policies)	Dec. 31, 2022
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 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of 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 transportation and services 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. Crude oil transportation and services revenue Our crude oil transportation and services segment’s 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. 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 is recognized ratably over the term of the underlying lease. Sunoco LP’s all other revenue Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided). USAC’s contract operations revenue USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years; however, USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract. Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower. USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin. The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date. There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration. USAC’s retail parts and services revenue USAC’s retail parts and services revenue is primarily earned on directly reimbursable freight and crane charges that are the financial responsibility of 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 on 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.

Lease Accounting (Policies)	12 Months Ended
Lease Accounting (Policies)	Dec. 31, 2022
Leases [Abstract]
Lessee, Leases [Policy Text Block]	Lessee Accounting The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet. At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term. To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives. Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance. For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.
Lessor, Leases [Policy Text Block]	Lessor AccountingSunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement.

Estimates, Significant Accounting Policies and Balance Sheet Detail (Tables)

12 Months Ended

Dec. 31, 2022

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,
	2022		2021		2020
Accounts receivable	$	(863)	$	(3,356)	$	1,163
Accounts receivable from related companies	23		38		(290)
Inventories	(361)		(19)		(271)
Other current assets	(326)		(216)		172
Other non-current assets, net	146		1		(7)
Accounts payable	25		3,834		(1,327)
Accounts payable to related companies	6		(34)		367
Accrued and other current liabilities	131		238		163
Other non-current liabilities	66		117		8
Derivative assets and liabilities, net	(349)		(88)		69
Net change in operating assets and liabilities, net of effects of acquisitions	$	(1,502)	$	515	$	47

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,
	2022		2021		2020
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	$	575	$	464	$	604
Units issued in connection with the Enable Acquisition(1)	—		3,509		—
Lease assets obtained in exchange for new lease liabilities	42		18		42
Acquisition of interest in unconsolidated affiliate	—		49		—






SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	2,167	$	2,188	$	2,092
Cash paid for income taxes (net of refunds)	54		41		(64)

(1)See Note 3 for additional information.

Schedule of Inventory

The Partnership’s inventories consisted of the following:


	December 31,
	2022		2021
Natural gas, NGLs and refined products	$	1,802	$	1,259
Crude oil	246		328
Spare parts and other	413		427
Total inventories	$	2,461	$	2,014

Other Current Assets

Other current assets consisted of the following:


	December 31,
	2022		2021
Deposits paid to vendors	$	334	$	215
Prepaid expenses and other	392		222
Total other current assets	$	726	$	437

Property, Plant and Equipment

Components and useful lives of property, plant and equipment were as follows:


	December 31,
	2022		2021
Land and improvements	$	1,427	$	1,369
Buildings and improvements (1 to 45 years)	3,546		4,598
Pipelines and equipment (5 to 83 years)	82,353		77,112
Product storage and related facilities (2 to 83 years)	7,274		7,410




Right of way (20 to 83 years)	6,252		5,021




Other (1 to 48 years)	2,739		2,816
Construction work-in-process	2,405		5,665
	105,996		103,991
Less – Accumulated depreciation and depletion	(25,685)		(22,384)
Property, plant and equipment, net	$	80,311	$	81,607

Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense

We recognized the following amounts for the periods presented:


	Years Ended December 31,
	2022		2021		2020
Depreciation, depletion and amortization expense	$	3,774	$	3,465	$	3,275
Capitalized interest	112		135		189

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,
	2022		2021
Crude pipeline linefill and tank bottoms	$	489	$	498
Regulatory assets	55		42
Pension assets	129		140
Deferred charges	140		177
Restricted funds	121		164
Other	624		624
Total other non-current assets, net	$	1,558	$	1,645

Restricted funds include an immaterial amount of restricted cash primarily held in our wholly-owned captive insurance companies.

Components And Useful Lives Of Intangibles And Other Assets

Components and useful lives of intangible assets were as follows:


	December 31, 2022				December 31, 2021
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	7,884	$	(2,807)	$	7,982	$	(2,464)
Patents (10 years)	48		(48)		48		(44)

Trade names (20 years)	66		(41)		66		(38)
Other (5 to 20 years)	12		(13)		19		(20)
Total amortizable intangible assets	8,010		(2,909)		8,115		(2,566)
Non-amortizable intangible assets:
Trademarks	302		—		295		—
Other	12		—		12		—
Total non-amortizable intangible assets	314		—		307		—
Total intangible assets	$	8,324	$	(2,909)	$	8,422	$	(2,566)

Aggregate Amortization Expense Of Intangibles And Other Assets

Aggregate amortization expense of intangible assets was as follows:


	Years Ended December 31,
	2022		2021		2020
Reported in depreciation, depletion and amortization expense	$	390	$	352	$	403

Estimated Aggregate Amortization Expense

Estimated aggregate amortization of intangible assets for the next five years is as follows:


Years Ending December 31:
2023	$	357
2024	344
2025	331
2026	327
2027	309

Schedule of Goodwill

Changes in the carrying amount of goodwill were 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		Investment in USAC		All Other		Total
Balance, December 31, 2020	$	—	$	—	$	—	$	693	$	52	$	1,564	$	—	$	82	$	2,391
Acquired	—		—		—		—		138		4		—		—		142



Balance, December 31, 2021	—		—		—		693		190		1,568		—		82		2,533
Acquired	—		—		—		—		—		33		—		—		33



Balance, December 31, 2022	$	—	$	—	$	—	$	693	$	190	$	1,601	$	—	$	82	$	2,566

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:


	December 31,
	2022		2021
Interest payable	$	559	$	561
Customer advances and deposits	222		188
Accrued capital expenditures	565		461
Accrued wages and benefits	376		297
Taxes payable other than income taxes	519		384


Exchanges payable	224		155
Deferred revenue	268		158
Other	596		867
Total accrued and other current liabilities	$	3,329	$	3,071

Schedule of Derivative Assets at Fair Value


	Fair Value Total		Fair Value Measurements at December 31, 2022
			Level 1		Level 2
Assets:

Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	60	$	60	$	—
Swing Swaps IFERC	75		75		—
Fixed Swaps/Futures	113		113		—


Forward Physical Contracts	10		—		10
Power:
Forwards	52		—		52
Futures	3		3		—


NGLs – Forwards/Swaps	317		317		—
Refined Products – Futures	20		20		—

Crude – Forwards/Swaps	38		38		—

Total commodity derivatives	688		626		62
Other non-current assets	27		18		9
Total assets	$	715	$	644	$	71
Liabilities:
Interest rate derivatives	$	(23)	$	—	$	(23)

Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(25)		(25)		—
Swing Swaps IFERC	(12)		(12)		—
Fixed Swaps/Futures	(4)		(4)		—


Forward Physical Contracts	(2)		—		(2)
Power:
Forwards	(51)		—		(51)
Futures	(3)		(3)		—


NGLs – Forwards/Swaps	(358)		(358)		—
Refined Products – Futures	(59)		(59)		—
Crude – Forwards/Swaps	(12)		(12)		—
Total commodity derivatives	(526)		(473)		(53)
Total liabilities	$	(549)	$	(473)	$	(76)


	Fair Value Total		Fair Value Measurements at December 31, 2021
			Level 1		Level 2
Assets:

Commodity derivatives:

Natural Gas:
Basis Swaps IFERC/NYMEX	$	7	$	7	$	—
Swing Swaps IFERC	38		38		—
Fixed Swaps/Futures	26		26		—


Forward Physical Contracts	7		—		7
Power:
Forwards	17		—		17
Futures	6		6		—


NGLs – Forwards/Swaps	152		152		—
Refined Products – Futures	3		3		—
Crude - Forwards/Swaps	16		16		—
Total commodity derivatives	272		248		24
Other non-current assets	39		26		13
Total assets	$	311	$	274	$	37
Liabilities:
Interest rate derivatives	$	(387)	$	—	$	(387)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(10)		(10)
Swing Swaps IFERC	(6)		(6)		—
Fixed Swaps/Futures	(9)		(9)		—


Forward Physical Contracts	(6)		—		(6)
Power:
Forwards	(15)				(15)
Futures	(4)		(4)		—


NGLs – Forwards/Swaps	(140)		(140)		—
Refined Products – Futures	(18)		(18)		—
Crude - Forwards/Swaps	(3)		(3)		—

Total commodity derivatives	(211)		(190)		(21)
Total liabilities	$	(598)	$	(190)	$	(408)

Acquisitions and Related Transactions (Tables)

12 Months Ended

Dec. 31, 2022

Enable

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following table summarizes the allocation of the purchase price among the assets acquired and liabilities assumed:


	At December 2, 2021
Total current assets	$	593
Property, plant and equipment, net	7,076
Investments in unconsolidated affiliates	40

Other non-current assets	39
Intangible assets, net	440
Goodwill	138
Total assets	8,326

Total current liabilities	488
Long-term debt, less current maturities(1)	4,267
Other non-current liabilities	18
Total liabilities	4,773

Noncontrolling interests	34

Total consideration	3,519
Cash received	61
Total consideration, net of cash received	$	3,458

Advances to and Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2022

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 in unconsolidated affiliates as of December 31, 2022 and 2021 were as follows:


	December 31,
	2022		2021
Citrus	$	1,800	$	1,792

MEP	360		378
White Cliffs	218		245
Explorer	69		71
Other	446		461
Total	$	2,893	$	2,947

The following table presents equity in earnings (losses) of unconsolidated affiliates:


	Years Ended December 31,
	2022		2021		2020
Citrus	$	141	$	157	$	162

MEP	10		(17)		(6)
White Cliffs	(8)		—		20
Explorer	25		24		17
Other (1)	89		82		(74)
Total equity in earnings of unconsolidated affiliates	$	257	$	246	$	119

Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block]


	December 31,
	2022		2021
Current assets	$	311	$	319
Property, plant and equipment, net	7,722		7,803
Other assets	86		88
Total assets	$	8,119	$	8,210

Current liabilities	$	291	$	547
Non-current liabilities	4,347		4,110
Equity	3,481		3,553
Total liabilities and equity	$	8,119	$	8,210


	Years Ended December 31,
	2022		2021		2020
Revenue	$	1,518	$	1,393	$	1,405
Operating income	704		684		732
Net income	463		446		480

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 Unit (Tables)

12 Months Ended

Dec. 31, 2022

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,
	2022		2021		2020
Net income	$	5,868	$	6,687	$	140
Less: Net income attributable to redeemable noncontrolling interests	51		50		49
Less: Net income attributable to noncontrolling interests	1,061		1,167		739
Net income (loss), net of noncontrolling interests	4,756		5,470		(648)
Less: General Partner’s interest in income (loss)	4		6		(1)
Less: Preferred Unitholders’ interest in income	422		285		—
Common Unitholders’ interest in net income (loss)	$	4,330	$	5,179	$	(647)
Basic Income (Loss) per Common Unit:
Weighted average common units	3,086.8		2,734.4		2,695.6
Basic income (loss) per common unit	$	1.40	$	1.89	$	(0.24)

Diluted Income (Loss) per Common Unit:
Common Unitholders’ interest in net income (loss)	$	4,330	$	5,179	$	(647)
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units	(2)		(2)		—
Diluted income (loss) available to Common Unitholders	$	4,328	$	5,177	$	(647)
Weighted average common units	3,086.8		2,734.4		2,695.6

Dilutive effect of unvested unit awards	10.2		5.1		—
Weighted average common units, assuming dilutive effect of unvested unit awards	3,097.0		2,739.5		2,695.6
Diluted income (loss) per common unit	$	1.40	$	1.89	$	(0.24)

Debt Obligations Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2022

Debt Obligations [Abstract]

Schedule of debt obligations

Our debt obligations consist of the following:


	December 31,
	2022		2021
Energy Transfer Indebtedness











4.65% Senior Notes due February 15, 2022(1)	$	—	$	300

5.00% Senior Notes due October 1, 2022(1)	—		700
3.45% Senior Notes due January 15, 2023(2)(3)	350		350
3.60% Senior Notes due February 1, 2023(2)(3)	800		800
4.25% Senior Notes due March 15, 2023(3)	5		5
4.25% Senior Notes due March 15, 2023(3)	995		995
4.20% Senior Notes due September 15, 2023(3)	500		500
4.50% Senior Notes due November 1, 2023(3)	600		600
5.875% Senior Notes due January 15, 2024	23		23
7.60% Senior Notes due February 1, 2024(4)	82		—
5.875% Senior Notes due January 15, 2024	1,127		1,127
4.90% Senior Notes due February 1, 2024	350		350
7.60% Senior Notes due February 1, 2024	277		277
4.25% Senior Notes due April 1, 2024	500		500
4.50% Senior Notes due April 15, 2024	750		750
3.90% Senior Notes due May 15, 2024	600		600
9.00% Debentures due November 1, 2024	65		65
4.05% Senior Notes due March 15, 2025	1,000		1,000
2.90% Senior Notes due May 15, 2025	1,000		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
4.40% Senior Notes due March 15, 2027	700		700
4.20% Senior Notes due April 15, 2027	600		600
5.50% Senior Notes due June 1, 2027	44		44
5.50% Senior Notes due June 1, 2027	956		956
4.00% Senior Notes due October 1, 2027	750		750
5.55% Senior Notes due February 15, 2028	1,000		—
4.95% Senior Notes due May 15, 2028	800		800
4.95% Senior Notes due June 15, 2028	1,000		1,000
5.25% Senior Notes due April 15, 2029	1,500		1,500
7.00% Senior Notes due July 15, 2029(4)	66		—
4.15% Senior Notes due September 15, 2029	547		547
8.25% Senior Notes due November 15, 2029(4)	33		—
8.25% Senior Notes due November 15, 2029	267		267
3.75% Senior Note due May 15, 2030	1,500		1,500
5.75% Senior Notes due February 15, 2033	1,500		—
4.90% Senior Notes due March 15, 2035	500		500
6.625% Senior Notes due October 15, 2036	400		400


5.80% Senior Notes due June 15, 2038	500	500
7.50% Senior Notes due July 1, 2038	550	550
6.85% Senior Notes due February 15, 2040	250	250
6.05% Senior Notes due June 1, 2041	700	700
6.50% Senior Notes due February 1, 2042	1,000	1,000
6.10% Senior Notes due February 15, 2042	300	300
4.95% Senior Notes due January 15, 2043	350	350
5.15% Senior Notes due February 1, 2043	450	450
5.95% Senior Notes due October 1, 2043	450	450
5.30% Senior Notes due April 1, 2044	700	700
5.00% Senior Notes due May 15, 2044	531	531
5.15% Senior Notes due March 15, 2045	1,000	1,000
5.35% Senior Notes due May 15, 2045	800	800
6.125% Senior Notes due December 15, 2045	1,000	1,000
5.30% Senior Notes due April 15, 2047	900	900
5.40% Senior Notes due October 1, 2047	1,500	1,500
6.00% Senior Notes due June 15, 2048	1,000	1,000
6.25% Senior Notes due April 15, 2049	1,750	1,750
5.00% Senior Notes due May 15, 2050	2,000	2,000
Floating Rate Junior Subordinated Notes due November 1, 2066	600	546

Five-Year Credit Facility	793	2,937
Unamortized premiums, discounts and fair value adjustments, net	184	233
Deferred debt issuance costs	(181)	(186)
	40,264	40,717

Subsidiary Indebtedness
Transwestern Debt

5.89% Senior Notes due May 24, 2022(1)	—	150
5.66% Senior Notes due December 9, 2024	175	175
6.16% Senior Notes due May 24, 2037	75	75

	250	400

Panhandle Debt

7.60% Senior Notes due February 1, 2024(4)	—	82
7.00% Senior Notes due July 15, 2029(4)	—	66
8.25% Senior Notes due November 15, 2029(4)	—	33
Floating Rate Junior Subordinated Notes due November 1, 2066(4)	—	54
Unamortized premiums, discounts and fair value adjustments, net(4)	—	8
	—	243


Bakken Project Debt
3.625% Senior Notes due April 1, 2022(1)	—	650
3.90% Senior Notes due April 1, 2024	1,000	1,000
4.625% Senior Notes due April 1, 2029	850	850


Unamortized premiums, discounts and fair value adjustments, net	(1)		(2)
Deferred debt issuance costs	(7)		(9)
	1,842		2,489

Sunoco LP Debt
6.00% Senior Notes Due April 15, 2027	600		600
5.875% Senior Notes Due March 15, 2028	400		400
4.50% Senior Notes due May 15, 2029	800		800
4.50% Senior Notes due April 30, 2030	800		800
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023	900		581
Lease-related obligations	94		100
Deferred debt issuance costs	(23)		(26)
	3,571		3,255

USAC Debt
6.875% Senior Notes due April 1, 2026	725		725
6.875% Senior Notes due September 1, 2027	750		750
USAC $1.60 billion Revolving Credit Facility due December 2026(5)	646		516

Deferred debt issuance costs	(14)		(18)
	2,107		1,973

HFOTCO Debt
HFOTCO Tax Exempt Notes due 2050	225		225
Unamortized premiums, discounts and fair value adjustments, net	—		(1)

	225		224

Energy Transfer Canada Debt

Energy Transfer Canada facilities(6)	—		398


	—		398

Other	3		3
Total debt	48,262		49,702
Less: Current maturities of long-term debt	2		680
Long-term debt, less current maturities	$	48,260	$	49,022

Future maturities of long-term debt


2023	$	3,250
2024	5,175
2025	2,400
2026	2,921
2027	6,093
Thereafter	28,465
Total	$	48,304

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI https://asc.fasb.org/extlink&oid=120391452&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 3
-Subparagraph (SX 210.12-04(a))
-URI https://asc.fasb.org/extlink&oid=120395691&loc=d3e24072-122690

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI https://asc.fasb.org/extlink&oid=124435984&loc=d3e28541-108399

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI https://asc.fasb.org/extlink&oid=126973232&loc=d3e21506-112644

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 55
-Paragraph 69B
-URI https://asc.fasb.org/extlink&oid=123466577&loc=SL123495735-112612

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI https://asc.fasb.org/extlink&oid=124435984&loc=d3e28551-108399

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 55
-Paragraph 69E
-URI https://asc.fasb.org/extlink&oid=123466577&loc=SL123495743-112612

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI https://asc.fasb.org/extlink&oid=126973232&loc=d3e21521-112644

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI https://asc.fasb.org/extlink&oid=126973232&loc=d3e21538-112644

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI https://asc.fasb.org/extlink&oid=123599511&loc=d3e64711-112823

Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI https://asc.fasb.org/extlink&oid=114775985&loc=d3e28878-108400

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI https://asc.fasb.org/extlink&oid=126973232&loc=d3e21475-112644

+ Details

Equity (Tables)

12 Months Ended

Dec. 31, 2022

Change In ETE Common Units

The change in Energy Transfer Common Units during the years ended December 31, 2022, 2021 and 2020 was as follows:


	Years Ended December 31,
	2022	2021	2020
Number of Common Units, beginning of period	3,082.5	2,702.4	2,689.6

Common Units issued in mergers and acquisitions (1)	—	374.6	—
Common Units repurchased	—	(4.2)	—
Issuance of Common Units (2)	11.9	9.7	12.8
Number of Common Units, end of period	3,094.4	3,082.5	2,702.4

Accumulated Other Comprehensive Income (Loss)

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


	December 31,
	2022		2021
Available-for-sale securities	$	9	$	19
Foreign currency translation adjustment	1		13

Actuarial gain (loss) related to pensions and other postretirement benefits	(7)		5
Investments in unconsolidated affiliates, net	13		(11)
Total AOCI, net of tax	16		26
Amounts attributable to noncontrolling interests	—		(3)
Total AOCI included in partners’ capital, net of tax	$	16	$	23

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The following table sets forth the tax amounts included in the respective components of other comprehensive income:


	December 31,
	2022		2021
Available-for-sale securities	$	1	$	(1)
Foreign currency translation adjustment	6		6
Actuarial loss relating to pension and other postretirement benefits	1		1
Total	$	8	$	6

Schedule of Preferred Units

The following table summarizes changes in the Energy Transfer Preferred Units:


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Total
Balance, December 31, 2020	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Preferred units conversion	943		547		440		434		786		504		1,114		—		4,768
Units issued for cash	—		—		—		—		—		—		—		889		889
Distributions to partners	(30)		(18)		(25)		(25)		(45)		(34)		(79)		(24)		(280)
Units issued in Enable Acquisition	—		—		—		—		—		—		392		—		392
Other, net	—		—		—		—		—		—		—		(3)		(3)
Net income	45		27		25		25		45		26		61		31		285
Balance, December 31, 2021	958		556		440		434		786		496		1,488		893		6,051
Distributions to partners	(59)		(36)		(33)		(34)		(61)		(34)		(106)		(59)		(422)
Net income	59		36		33		34		61		34		106		59		422
Balance, December 31, 2022	$	958	$	556	$	440	$	434	$	786	$	496	$	1,488	$	893	$	6,051

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, 2019

February 7, 2020

February 19, 2020

0.8255

March 31, 2020

May 7, 2020

May 19, 2020

0.8255

June 30, 2020

August 7, 2020

August 19, 2020

0.8255

September 30, 2020

November 6, 2020

November 19, 2020

0.8255

December 31, 2020

February 8, 2021

February 19, 2021

0.8255

March 31, 2021

May 11, 2021

May 19, 2021

0.8255

June 30, 2021

August 6, 2021

August 19, 2021

0.8255

September 30, 2021

November 5, 2021

November 19, 2021

0.8255

December 31, 2021

February 8, 2022

February 18, 2022

0.8255

March 31, 2022

May 9, 2022

May 19, 2022

0.8255

June 30, 2022

August 8, 2022

August 19, 2022

0.8255

September 30, 2022

November 4, 2022

November 18, 2022

0.8255

December 31, 2022

February 7, 2023

February 21, 2023

0.8255

Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution [Table Text Block]


		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

Distributions on USAC’s units declared and/or paid by USAC were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2019

January 27, 2020

February 7, 2020

0.5250

March 31, 2020

April 27, 2020

May 8, 2020

0.5250

June 30, 2020

July 31, 2020

August 10, 2020

0.5250

September 30, 2020

October 26, 2020

November 6, 2020

0.5250

December 31, 2020

January 25, 2021

February 5, 2021

0.5250

March 31, 2021

April 26, 2021

May 7, 2021

0.5250

June 30, 2021

July 26, 2021

August 6, 2021

0.5250

September 30, 2021

October 25, 2021

November 5, 2021

0.5250

December 31, 2021

January 24, 2022

February 4, 2022

0.5250

March 31, 2022

April 25, 2022

May 6, 2022

0.5250

June 30, 2022

July 25, 2022

August 5, 2022

0.5250

September 30, 2022

October 24, 2022

November 4, 2022

0.5250

December 31, 2022

January 23, 2023

February 3, 2023

0.5250

ET [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, 2019

February 7, 2020

February 19, 2020

0.3050

March 31, 2020

May 7, 2020

May 19, 2020

0.3050

June 30, 2020

August 7, 2020

August 19, 2020

0.3050

September 30, 2020

November 6, 2020

November 19, 2020

0.1525

December 31, 2020

February 8, 2021

February 19, 2021

0.1525

March 31, 2021

May 11, 2021

May 19, 2021

0.1525

June 30, 2021

August 6, 2021

August 19, 2021

0.1525

September 30, 2021

November 5, 2021

November 19, 2021

0.1525

December 31, 2021

February 8, 2022

February 18, 2022

0.1750

March 31, 2022

May 9, 2022

May 19, 2022

0.2000

June 30, 2022

August 8, 2022

August 19, 2022

0.2300

September 30, 2022

November 4, 2022

November 21, 2022

0.2650

December 31, 2022

February 7, 2023

February 21, 2023

0.3050

Preferred Units [Member]

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

Distributions on Energy Transfer’s Series A, Series B, Series C, Series D, Series E, Series F, Series G and Series H preferred units declared and/or paid by Energy Transfer were as follows:


Period Ended	Record Date	Payment Date	Series A (1)	Series B (1)	Series C	Series D	Series E	Series F (1)	Series G (1)	Series H (1)
March 31, 2021	May 3, 2021	May 17, 2021	$—	$—	$0.4609	$0.4766	$0.4750	$33.7500	$35.63	$—
June 30, 2021	August 2, 2021	August 16, 2021	31.25	33.13	0.4609	0.4766	0.4750	—	—	—
September 30, 2021	November 1, 2021	November 15, 2021	—	—	0.4609	0.4766	0.4750	33.7500	35.63	27.08	*
December 31, 2021	February 1, 2022	February 15, 2022	31.25	33.13	0.4609	0.4766	0.4750	—	—	—
March 31, 2022	May 2, 2022	May 16, 2022	—	—	0.4609	0.4766	0.4750	33.7500	35.63	32.50
June 30, 2022	August 1, 2022	August 15, 2022	31.25	33.13	0.4609	0.4766	0.4750	—	—	—
September 30, 2022	November 1, 2022	November 15, 2022	—	—	0.4609	0.4766	0.4750	33.7500	35.63	32.50
December 31, 2022	February 1, 2023	February 15, 2023	31.25	33.13	0.4609	0.4766	0.4750	—	—	—

* Represents prorated initial distribution.

Equity Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2022

Schedule of weighted average grant-date fair values

The following table summarizes the weighted average grant-date fair value per unit award granted:


	Years Ended December 31,
	2022		2021		2020
Sunoco LP	$	43.54	$	37.72	$	28.63
USAC	18.31		14.92		12.55

Schedule of Subsidiary Awards Granted To Employees And Non-Employee Directors

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, 2021	36.1	$	9.49

Awards granted	12.4	11.56
Awards vested	(9.3)	11.79
Awards forfeited	(1.5)	9.39
Unvested awards as of December 31, 2022	37.7	$	9.62

Subsidiaries [Member]

Schedule of Subsidiary Awards Granted To Employees And Non-Employee Directors

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, 2021	2.0	$	30.92	2.2	$	13.57
Awards granted	0.4	43.54		0.6	18.31
Awards vested	(0.5)	29.95		(0.4)	15.89
Awards forfeited	(0.1)	30.31		(0.3)	14.10
Unvested awards as of December 31, 2022	1.8	$	34.29	2.1	$	14.21

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [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 are summarized as follows:


	Years Ended December 31,
	2022		2021		2020
Current expense (benefit):
Federal	$	—	$	19	$	(6)
State	17		24		32
Foreign	—		—		1
Total	17		43		27
Deferred expense (benefit):
Federal	239		246		176
State	(58)		(106)		41
Foreign	6		1		(7)
Total	187		141		210
Total income tax expense	$	204	$	184	$	237

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]


	Years Ended December 31,
	2022		2021		2020

Income tax expense at United States statutory rate	$	1,275	$	1,443	$	79
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax	(1,086)		(1,211)		88
Noncontrolling interests	26		—		16
State tax, net of federal tax benefit	19		85		58
Statutory rate change	(42)		(46)		—
Valuation allowance	(4)		(63)		—
Uncertain tax positions	(3)		(34)		—
Dividend received deduction	(3)		(4)		—


Foreign taxes	6		1		(7)

Other	16		13		3
Income tax expense	$	204	$	184	$	237

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]


	December 31,
	2022		2021
Deferred income tax assets:
Net operating losses and other carryforwards	$	603	$	803


Other	60		35
Total deferred income tax assets	663		838
Valuation allowance	(19)		(34)
Net deferred income tax assets	644		804

Deferred income tax liabilities:
Property, plant and equipment	(218)		(314)

Investments in affiliates	(4,010)		(4,042)
Trademarks	(89)		(79)
Other	(28)		(17)
Total deferred income tax liabilities	(4,345)		(4,452)
Net deferred income taxes	$	(3,701)	$	(3,648)

ScheduleOfUnrecognizedTaxBenefits [Table Text Block]

The following table sets forth the changes in unrecognized tax benefits:


	Years Ended December 31,
	2022		2021		2020
Balance at beginning of year	$	56	$	90	$	94



Reduction attributable to tax positions taken in prior years	(4)		(34)		—

Lapse of statute	—		—		(4)
Balance at end of year	$	52	$	56	$	90

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

12 Months Ended

Dec. 31, 2022

Environmental Exit Costs by Cost [Table Text Block]

have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.


	December 31,
	2022		2021
Current	$	54	$	46
Non-current	228		247
Total environmental liabilities	$	282	$	293

Right of way (20 to 83 years)

Other Commitments


	Years Ended December 31,
	2022		2021		2020
ROW expense	$	64	$	48	$	47

Revenue (Tables)

12 Months Ended

Dec. 31, 2022

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

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


	Contract Liabilities
Balance, December 31, 2020	$	309
Additions	849
Revenue recognized	(699)
Balance, December 31, 2021	459
Additions	1,113
Revenue recognized	(944)
Other	(13)
Balance, December 31, 2022	$	615

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


	Years Ending December 31,
	2023		2024		2025		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of December 31, 2022	$	7,038	$	6,023	$	5,158	$	20,982	$	39,201

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, 2022 and 2021 were as follows:


	December 31,
	2022		2021
Contract Balances
Contract asset	$	200	$	157
Accounts receivable from contracts with customers	834		463

Lease Accounting (Tables)

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

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

The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of December 31, 2022 and 2021 were as follows:


	December 31,
	2022		2021
Operating leases:
Lease right-of-use assets, net	$	808	$	826
Operating lease current liabilities	45		47
Accrued and other current liabilities	1		1
Non-current operating lease liabilities	798		814
Finance leases:
Property, plant and equipment, net	$	1	$	1
Lease right-of-use assets, net	11		12
Accrued and other current liabilities	—		1
Current maturities of long-term debt	2		3
Long-term debt, less current maturities	9		9
Other non-current liabilities	1		1

Lease, Cost [Table Text Block]

The components of lease expense for the years ended December 31, 2022 and 2021 were as follows:


		Year Ended December 31,
	Income Statement Location	2022		2021
Operating lease costs:
Operating lease cost	Cost of goods sold	$	3	$	10
Operating lease cost	Operating expenses	63		78
Operating lease cost	Selling, general and administrative	22		17
Total operating lease costs		88		105
Finance lease costs:
Amortization of lease assets	Depreciation, depletion and amortization	—		1
Interest on lease liabilities	Interest expense, net of capitalized interest	—		1
Total finance lease costs		—		2
Short-term lease cost	Operating expenses	33		40
Variable lease cost	Operating expenses	13		9
Lease costs, gross		134		156
Less: Sublease income	Other revenue	40		45
Lease costs, net		$	94	$	111

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

The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2022 and 2021 were as follows:


	December 31,
	2022		2021
Weighted-average remaining lease term (years):
Operating leases	21		19
Finance leases	27		29
Weighted-average discount rate (%):
Operating leases	5	%	5	%
Finance leases	4	%	4	%

Maturities of lease liabilities as of December 31, 2022 are as follows:


	Operating leases		Finance leases		Total
2023	$	86	$	3	$	89
2024	81		1		82
2025	79		—		79
2026	77		—		77
2027	71		—		71
Thereafter	1,027		15		1,042
Total lease payments	1,421		19		1,440
Less: present value discount	578		6		584
Present value of lease liabilities	$	843	$	13	$	856

Schedule of additional lease information [Table Text Block]

Cash flows and non-cash activity related to leases for the years ended December 31, 2022 and 2021 were as follows:


	Year Ended December 31,
	2022		2021


Operating cash flows from operating leases	$	(133)	$	(147)



Lease assets obtained in exchange for new finance lease liabilities	1		9
Lease assets obtained in exchange for new operating lease liabilities	41		9

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

Sunoco LP’s future minimum operating lease payments receivable as of December 31, 2022 are as follows:


	Lease Payments
2023	$	67
2024	47
2025	45
2026	43
2027	41
Thereafter	25
Total undiscounted cash flows	$	268

Derivative Assets And Liabilities (Tables)

12 Months Ended

Dec. 31, 2022

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Offsetting Assets [Table Text Block]


		Asset Derivatives				Liability Derivatives
	Balance Sheet Location	December 31, 2022		December 31, 2021		December 31, 2022		December 31, 2021
Derivatives without offsetting agreements	Derivative liabilities	$	—	$	—	$	(23)	$	(387)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	95		53		(108)		(52)
Broker cleared derivative contracts	Other current assets (liabilities)	593		219		(418)		(159)
		688		272		(549)		(598)
Offsetting agreements:

Counterparty netting	Derivative assets (liabilities)	(85)		(43)		85		43
Counterparty netting	Other current assets (liabilities)	(359)		(150)		359		150
Total net derivatives		$	244	$	79	$	(105)	$	(405)

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:


	December 31, 2022		December 31, 2021
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	145	2023	585	2022-2023
Basis Swaps IFERC/NYMEX(1)	(39,563)	2023	(66,665)	2022


Power (Megawatt):
Forwards	—	2023-2029	653,000	2023-2029
Futures	(21,384)	2023	(604,920)	2022-2023
Options – Puts	119,200	2023	(7,859)	2022
Options – Calls	—	—	(30,932)	2022

(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	42,440	2023-2024	6,738	2022-2023
Swing Swaps IFERC	(202,815)	2023-2024	(106,333)	2022-2023
Fixed Swaps/Futures	(15,758)	2023-2025	(63,898)	2022-2023
Forward Physical Contracts	2,423	2023-2024	(5,950)	2023

NGL (MBbls) – Forwards/Swaps	6,934	2023-2025	8,493	2022-2024
Crude (MBbls) – Forwards/Swaps	795	2023-2024	3,672	2022-2023
Refined Products (MBbls) – Futures	(3,547)	2023-2024	(3,349)	2022-2023

Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(37,448)	2023	(40,533)	2022
Fixed Swaps/Futures	(37,448)	2023	(40,533)	2022
Hedged Item – Inventory	37,448	2023	40,533	2022

(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, 2022		December 31, 2021
July 2022 (2)	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	$	—	$	400
July 2023 (2)(3)	Forward-starting to pay a fixed rate of 3.845% and receive a floating rate	—		200
July 2024 (2)	Forward-starting to pay a fixed rate of 3.512% and receive a floating rate	400		200

(1)Floating rates are based on either SOFR or three-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) This interest rate swap was terminated and settled in 2022.

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, 2022		December 31, 2021		December 31, 2022		December 31, 2021
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	87	$	46	$	(7)	$	(3)
	87		46		(7)		(3)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	506		173		(411)		(156)
Commodity derivatives	95		53		(108)		(52)



Interest rate derivatives	—		—		(23)		(387)
	601		226		(542)		(595)
Total derivatives	$	688	$	272	$	(549)	$	(598)

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,
		2022		2021		2020
Derivatives not designated as hedging instruments:

Commodity derivatives – Trading	Cost of products sold	$	83	$	(6)	$	8
Commodity derivatives – Non-trading	Cost of products sold	41		(141)		(34)

Interest rate derivatives	Gains (losses) on interest rate derivatives	293		61		(203)

Total		$	417	$	(86)	$	(229)

- Definition

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

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI https://asc.fasb.org/extlink&oid=125515794&loc=SL5624163-113959

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI https://asc.fasb.org/extlink&oid=125515794&loc=SL5580258-113959

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI https://asc.fasb.org/extlink&oid=125515794&loc=d3e41620-113959

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI https://asc.fasb.org/extlink&oid=125515794&loc=SL5579245-113959

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI https://asc.fasb.org/extlink&oid=125515794&loc=d3e41638-113959

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI https://asc.fasb.org/extlink&oid=125515794&loc=d3e41678-113959

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI https://asc.fasb.org/extlink&oid=125515794&loc=d3e41641-113959

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI https://asc.fasb.org/extlink&oid=125515794&loc=SL5624171-113959

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI https://asc.fasb.org/extlink&oid=125515794&loc=SL5579240-113959

+ Details

Retirement Benefits Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2022

Retirement Benefits [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]


	December 31, 2022						December 31, 2021
	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	$	50	$	26	$	195	$	55	$	31	$	208
Service cost	—		—		1		—		—		1
Interest cost	1		1		4		1		1		4

Benefits paid, net	(1)		(3)		(14)		(2)		(4)		(16)

Actuarial gain and other	(8)		(3)		(38)		(2)		(2)		(2)
Settlements	—		—		—		(2)		—		—
Energy Transfer Canada sale	(20)		(2)		—		—		—		—
Benefit obligation at end of period	22		19		148		50		26		195

Change in plan assets:
Fair value of plan assets at beginning of period	44		—		311		45		—		291
Return on plan assets and other	(4)		—		(41)		2		—		26
Employer contributions	1		—		3		1		—		10
Benefits paid, net	(1)		—		(14)		(2)		—		(16)
Settlements	—		—		—		(2)		—		—
Energy Transfer Canada sale	(20)		—		—		—		—		—
Fair value of plan assets at end of period	20		—		259		44		—		311

Amount underfunded (overfunded) at end of period	$	2	$	19	$	(111)	$	6	$	26	$	(116)

Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	$	—	$	—	$	127	$	—	$	—	$	138
Current liabilities	—		(3)		(2)		—		(4)		(2)
Non-current liabilities	(2)		(16)		(14)		(6)		(22)		(20)
	$	(2)	$	(19)	$	111	$	(6)	$	(26)	$	116

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	$	—	$	(2)	$	5	$	—	$	1	$	(27)
Prior service cost (credit)	—		—		(3)		—		—		19
	$	—	$	(2)	$	2	$	—	$	1	$	(8)

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, 2022					December 31, 2021
	Pension Benefits					Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits	Funded Plans		Unfunded Plans		Other Postretirement Benefits
Projected benefit obligation	$	22	$	19	N/A	$	50	$	26	N/A
Accumulated benefit obligation	22		19		148	50		26		195
Fair value of plan assets	20		—		259	44		—		311

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 following table:


	December 31,
	2022		2021
Health care cost trend rate	7.48	%	7.14	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.18	%	4.95	%
Year that the rate reaches the ultimate trend rate	2030		2028

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, 2022
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	2	$	2	$	—	$	—
Mutual funds (1)	18		18		—		—

Total	$	20	$	20	$	—	$	—

(1)Comprised of approximately 100% equities as of December 31, 2022.


			Fair Value Measurements at December 31, 2021
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	1	$	1	$	—	$	—
Mutual funds (1)	24		24		—		—
Fixed income securities	19		—		19		—
Total	$	44	$	25	$	19	$	—

(1)Comprised of approximately 100% equities as of December 31, 2021.

The fair value of other postretirement plan assets by asset category at the dates indicated is as follows:


			Fair Value Measurements at December 31, 2022
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Cash and cash equivalents	$	19	$	19	$	—	$	—
Mutual funds(1)	146		146		—		—
Fixed income securities	94		—		94		—
Total	$	259	$	165	$	94	$	—

(1)Primarily composed of market index funds as of December 31, 2022.


			Fair Value Measurements at December 31, 2021
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Cash and cash equivalents	$	22	$	22	$	—	$	—
Mutual funds(1)	175		175		—		—
Fixed income securities	114		—		114		—
Total	$	311	$	197	$	114	$	—

(1)Primarily composed of market index funds as of December 31, 2021.

Schedule of Expected Benefit Payments [Table Text Block]

Benefit Payments


Years	Pension Benefits - Funded Plans		Pension Benefits - Unfunded Plans		Other Postretirement Benefits (Gross, Before Medicare Part D)
2023	$	1	$	4	$	16
2024	1		3		15
2025	1		3		15
2026	1		2		14
2027	1		2		13
2028 – 2032	7		6		55

Schedule of Net Benefit Costs [Table Text Block]

Components of Net Periodic Benefit Cost


	December 31, 2022				December 31, 2021
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—	$	1	$	—	$	1
Interest cost	2		4		2		4
Expected return on plan assets	(2)		(11)		(2)		(11)
Prior service cost amortization	—		19		—		19




Net periodic benefit cost	$	—	$	13	$	—	$	13

Defined Benefit Plan, Assumptions [Table Text Block]

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the following table:


	December 31, 2022				December 31, 2021
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	5.00	%	2.46	%	2.79	%	2.24	%

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the following table:


	December 31, 2022				December 31, 2021
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	2.70	%	2.58	%	2.57	%	2.18	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	4.76	%	7.00	%
Taxable accounts	—		4.75	%	—		4.75	%

Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2022

Financial Information By Segment

The following tables present financial information by segment:


	Years Ended December 31,
	2022		2021		2020
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	6,954	$	7,307	$	2,312
Intersegment revenues	864		1,264		232
	7,818		8,571		2,544
Interstate transportation and storage:
Revenues from external customers	2,185		1,802		1,841
Intersegment revenues	66		39		20
	2,251		1,841		1,861
Midstream:
Revenues from external customers	4,114		2,620		1,944
Intersegment revenues	12,987		8,696		3,082
	17,101		11,316		5,026
NGL and refined products transportation and services:
Revenues from external customers	21,414		16,989		8,501
Intersegment revenues	4,243		2,972		2,012
	25,657		19,961		10,513
Crude oil transportation and services:
Revenues from external customers	25,980		17,442		11,674
Intersegment revenues	2		4		5
	25,982		17,446		11,679
Investment in Sunoco LP:
Revenues from external customers	25,677		17,571		10,653
Intersegment revenues	52		25		57
	25,729		17,596		10,710
Investment in USAC:
Revenues from external customers	689		621		655
Intersegment revenues	16		12		12
	705		633		667
All other:
Revenues from external customers	2,863		3,065		1,374
Intersegment revenues	711		411		464
	3,574		3,476		1,838
Eliminations	(18,941)		(13,423)		(5,884)
Total revenues	$	89,876	$	67,417	$	38,954


	Years Ended December 31,
	2022		2021		2020
Cost of products sold:
Intrastate transportation and storage	$	6,000	$	4,769	$	1,478
Interstate transportation and storage	25		11		—
Midstream	12,682		8,569		2,598
NGL and refined products transportation and services	21,656		16,248		7,139
Crude oil transportation and services	22,917		14,759		8,838
Investment in Sunoco LP	24,350		16,246		9,654
Investment in USAC	111		85		82
All other	3,328		3,068		1,527
Eliminations	(18,837)		(13,360)		(5,829)
Total cost of products sold	$	72,232	$	50,395	$	25,487


	Years Ended December 31,
	2022		2021		2020
Depreciation, depletion and amortization:
Intrastate transportation and storage	$	209	$	191	$	185
Interstate transportation and storage	513		457		411
Midstream	1,351		1,190		1,140
NGL and refined products transportation and services	865		778		667
Crude oil transportation and services	663		588		640
Investment in Sunoco LP	193		177		189
Investment in USAC	237		239		239
All other	133		197		207
Total depreciation, depletion and amortization	$	4,164	$	3,817	$	3,678


	Years Ended December 31,
	2022		2021		2020
Equity in earnings (losses) of unconsolidated affiliates:
Intrastate transportation and storage	$	17	$	20	$	18
Interstate transportation and storage	175		140		17
Midstream	19		24		24
NGL and refined products transportation and services	42		51		60
Crude oil transportation and services	—		10		(2)


All other	4		1		2
Total equity in earnings of unconsolidated affiliates	$	257	$	246	$	119


	Years Ended December 31,
	2022		2021		2020
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	1,396	$	3,483	$	863
Interstate transportation and storage	1,753		1,515		1,680
Midstream	3,210		1,868		1,670
NGL and refined products transportation and services	3,025		2,828		2,802
Crude oil transportation and services	2,187		2,023		2,258
Investment in Sunoco LP	919		754		739
Investment in USAC	426		398		414
All Other	177		177		105
Adjusted EBITDA (consolidated)	$	13,093	$	13,046	$	10,531


	Years Ended December 31,
	2022		2021		2020
Reconciliation of net income to Adjusted EBITDA:
Net income	$	5,868	$	6,687	$	140
Depreciation, depletion and amortization	4,164		3,817		3,678
Interest expense, net of interest capitalized	2,306		2,267		2,327
Income tax expense	204		184		237
Impairment losses and other	386		21		2,880
(Gains) losses on interest rate derivatives	(293)		(61)		203
Non-cash compensation expense	115		111		121
Unrealized (gains) losses on commodity risk management activities	(42)		(162)		71
Inventory valuation adjustments	(5)		(190)		82
Losses on extinguishments of debt	—		38		75
Adjusted EBITDA related to unconsolidated affiliates	565		523		628
Equity in earnings of unconsolidated affiliates	(257)		(246)		(119)
Impairment of investments in unconsolidated affiliates	—		—		129
Other, net	82		57		79
Adjusted EBITDA (consolidated)	$	13,093	$	13,046	$	10,531


	December 31,
	2022		2021		2020
Segment assets:
Intrastate transportation and storage	$	6,609	$	7,322	$	6,308
Interstate transportation and storage	17,979		17,774		17,582
Midstream	21,851		21,960		18,583
NGL and refined products transportation and services	27,903		28,160		21,423
Crude oil transportation and services	19,200		19,649		17,960
Investment in Sunoco LP	6,830		5,815		5,267
Investment in USAC	2,666		2,768		2,949
All other and eliminations	2,605		2,515		5,072
Total segment assets	$	105,643	$	105,963	$	95,144


	Years Ended December 31,
	2022		2021		2020
Additions to property, plant and equipment (1):
Intrastate transportation and storage	$	179	$	52	$	49
Interstate transportation and storage	644		159		150
Midstream	1,004		484		487
NGL and refined products transportation and services	507		751		2,403
Crude oil transportation and services	246		343		291
Investment in Sunoco LP	186		174		124
Investment in USAC	169		60		119
All other	91		135		136
Total additions to property, plant and equipment (1)	$	3,026	$	2,158	$	3,759


	December 31,
	2022		2021		2020
Investments in unconsolidated affiliates:
Intrastate transportation and storage	$	139	$	110	$	89
Interstate transportation and storage	2,201		2,209		2,278
Midstream	54		101		110
NGL and refined products transportation and services	446		476		509
Crude oil transportation and services	—		—		22


All other	53		51		52
Total investments in unconsolidated affiliates	$	2,893	$	2,947	$	3,060

Operations And Organization (Narrative) (Details) - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Apr. 01, 2021
Incentive Distribution Rights	0.00%
Issued	3,094,425,367	3,082,497,494
Class B Preferred Units [Member]
Issued			675,625,000
Sunoco LP [Member]
Incentive Distribution Rights	10000.00%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	28.5
USAC [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	46,100,000
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	100.00%

Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) - USD ($) $ in Millions			3 Months Ended				12 Months Ended
	Apr. 01, 2022	Dec. 02, 2021	Dec. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Impairment losses and other							$ 386	$ 21	$ 2,880
Asset Retirement Obligation			$ 369				362	369
Costs Incurred, Asset Retirement Obligation Incurred							4	12	16
Asset Retirement Obligation, Legally Restricted Assets, Fair Value			39				27	39
Long-term Debt, Fair Value			54,970				45,420	54,970
Goodwill							33	142
Goodwill			2,533	$ 2,391			2,566	2,533	2,391
Long-term Debt			49,702				48,262	49,702
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net							0
Inventory Write-down							5	190	82
Inventory Valuation Reserves			121				116	121
Impairment of investment in unconsolidated affiliates							0	0	129
Revenue from Related Parties							391	410	466
Reporting units for which the estimated FV exceeds the carrying value by less than 20%
Goodwill							368
White Cliffs
Impairment of investment in unconsolidated affiliates								129	129
Midstream
Impairment losses						$ (483)
Goodwill							0	0
Goodwill			0	0			0	0	0
All Other
Impairment losses				(15)	$ (132)	(40)
Goodwill							0	0
Goodwill			82	82			82	82	82
Investment in Sunoco LP
Goodwill							33	4
Goodwill			1,568	1,564			1,601	1,568	1,564
Retail Marketing [Member]
Excise Taxes Collected							285	332	301
Interstate Transportation and Storage
Impairment losses and other									58
Impairment losses					(43)	(183)
Goodwill							0	0
Goodwill			0	0			0	0	0
Investment in USAC
Impairment losses						$ (619)
Goodwill							0	0
Goodwill			0	0			0	0	0
Crude Oil Transportation and Services
Impairment losses					$ (1,280)
Goodwill							0	138
Goodwill			190	52			190	190	52
Intrastate Transportation and Storage
Impairment losses				(10)
Goodwill							0	0
Goodwill			0	0			0	0	0
Sunoco LP [Member]
Goodwill	$ 20
Long-term Debt			3,255				3,571	3,255
USAC [Member]
Impairment losses and other							1	$ 5	$ 8
PEI [Member] \| All Other
Impairment losses				$ (11)
Enable
Long-term Debt, Fair Value		$ 3,430
Goodwill		$ 138	138
Sunoco LP [Member]
Goodwill			$ 4				$ 33

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Cash Flow Information [Abstract]
Accounts receivable	$ (863)	$ (3,356)	$ 1,163
Accounts receivable from related companies	23	38	(290)
Inventories	(361)	(19)	(271)
Other current assets	326	216	(172)
Other non-current assets, net	146	1	(7)
Accounts payable	25	3,834	(1,327)
Accounts payable to related companies	6	(34)	367
Accrued and other current liabilities	131	238	163
Other non-current liabilities	66	117	8
Derivative assets and liabilities, net	(349)	(88)	69
Net change in operating assets and liabilities, net of effects of acquisitions	$ (1,502)	$ 515	$ 47

Estimates (Schedule Of Non-Cash Investing And Financing Activities) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

NON-CASH INVESTING ACTIVITIES: [Abstract]

Cash paid for interest, net of interest capitalized

$ 2,167

$ 2,188

$ 2,092

Cash paid for income taxes (net of refunds)

(64)

Accrued capital expenditures

575

464

604

Units issued in connection with the Enable Acquisition(1)

^[1]

3,509

Lease assets obtained in exchange for new lease liabilities

Acquisition of interest in unconsolidated affiliate

$ 0

$ 49

$ 0

[1]	See Note 3 for additional information.

Estimates (Schedule of Inventory) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Inventory, Net [Abstract]
Natural gas, NGLs and refined products	$ 1,802	$ 1,259
Crude oil	246	328
Spare parts and other	413	427
Total inventories	$ 2,461	$ 2,014

Estimates (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Other Information [Abstract]
Deposits paid to vendors	$ 334	$ 215
Prepaid expenses and other	392	222
Total other current assets	$ 726	$ 437

Estimates (Property, Plant and Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 105,996	$ 103,991
Less - Accumulated depreciation	(25,685)	(22,384)
Property, plant and equipment, net	80,311	81,607
Land and improvements
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,427	1,369
Buildings and improvements (1 to 45 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	3,546	4,598
Pipelines and equipment (5 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	82,353	77,112
Product storage and related facilities (2 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	7,274	7,410
Right of way (20 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	6,252	5,021
Other (1 to 48 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	2,739	2,816
Construction work-in-process
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 2,405	$ 5,665

Estimates (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Depreciation, depletion and amortization expense	$ 3,774	$ 3,465	$ 3,275
Capitalized interest	$ 112	$ 135	$ 189

Estimates (Schedule of Other Non-Current Assets, net) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Crude pipeline linefill and tank bottoms	$ 489	$ 498
Regulatory assets	55	42
Pension assets	129	140
Deferred charges	140	177
Restricted funds	121	164
Other	624	624
Total other non-current assets, net	$ 1,558	$ 1,645

Estimates (Components Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Gross Carrying Amount	$ 8,324	$ 8,422
Accumulated Amortization	(2,909)	(2,566)
Customer relationships, contracts and agreements (3 to 46 years)
Gross Carrying Amount	7,884	7,982
Accumulated Amortization	(2,807)	(2,464)
Patents (10 years)
Gross Carrying Amount	48	48
Accumulated Amortization	(48)	(44)
Trade names (20 years)
Gross Carrying Amount	66	66
Accumulated Amortization	(41)	(38)
Other (5 to 20 years)
Gross Carrying Amount	12	19
Accumulated Amortization	(13)	(20)
Total Amortizable Intangible Assets [Member]
Gross Carrying Amount	8,010	8,115
Accumulated Amortization	(2,909)	(2,566)
Trademarks [Member]
Gross Carrying Amount	302	295
Accumulated Amortization	0	0
Other
Gross Carrying Amount	12	12
Accumulated Amortization	0	0
Non-amortizable intangible assets [Member]
Gross Carrying Amount	314	307
Accumulated Amortization	$ 0	$ 0

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Useful Lives) (Details) (Details)	12 Months Ended
	Dec. 31, 2022
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
Product storage and related facilities (2 to 83 years) \| Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	2 years
Product storage and related facilities (2 to 83 years) \| Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Right of way (20 to 83 years) \| Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	20 years
Right of way (20 to 83 years) \| Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Other (1 to 48 years) \| Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Other (1 to 48 years) \| Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	48 years

Estimates (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Reported in depreciation and amortization	$ 390	$ 352	$ 403

Estimates (Estimated Aggregate Amortization Expense) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2023	$ 357
2024	344
2025	331
2026	327
2027	$ 309

Estimates (Schedule Of Goodwill) (Details) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021
Goodwill [Roll Forward]
Goodwill				$ 2,533	$ 2,391
Goodwill				33	142
Goodwill	$ 2,391			2,566	2,533
Intrastate Transportation and Storage
Goodwill [Roll Forward]
Goodwill				0	0
Goodwill				0	0
Goodwill	0			0	0
Goodwill impairment	(10)
Interstate Transportation and Storage
Goodwill [Roll Forward]
Goodwill				0	0
Goodwill				0	0
Goodwill	0			0	0
Goodwill impairment		$ (43)	$ (183)
Midstream
Goodwill [Roll Forward]
Goodwill				0	0
Goodwill				0	0
Goodwill	0			0	0
Goodwill impairment			(483)
NGL and Refined Products Transportation and Services
Goodwill [Roll Forward]
Goodwill				693	693
Goodwill				0	0
Goodwill	693			693	693
Crude Oil Transportation and Services
Goodwill [Roll Forward]
Goodwill				190	52
Goodwill				0	138
Goodwill	52			190	190
Goodwill impairment		(1,280)
Investment in Sunoco LP
Goodwill [Roll Forward]
Goodwill				1,568	1,564
Goodwill				33	4
Goodwill	1,564			1,601	1,568
Investment in USAC
Goodwill [Roll Forward]
Goodwill				0	0
Goodwill				0	0
Goodwill	0			0	0
Goodwill impairment			(619)
All Other
Goodwill [Roll Forward]
Goodwill				82	82
Goodwill				0	0
Goodwill	82			$ 82	$ 82
Goodwill impairment	$ (15)	$ (132)	$ (40)

Estimates (Accrued And Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Other Information [Abstract]
Interest payable	$ 559	$ 561
Customer advances and deposits	222	188
Accrued capital expenditures	565	461
Accrued wages and benefits	376	297
Taxes payable other than income taxes	519	384
Exchanges payable	224	155
Deferred Revenue	268	158
Other	596	867
Accrued and other current liabilities	$ 3,329	$ 3,071

Estimates (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Commodity derivatives:	$ 688	$ 272
Other Assets, Fair Value Disclosure	27	39
Total assets	715	311
Interest rate derivatives	(23)	(387)
Commodity derivatives:	(526)	(211)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(549)	(598)
Level 1 [Member]
Commodity derivatives:	626	248
Other Assets, Fair Value Disclosure	18	26
Total assets	644	274
Interest rate derivatives	0	0
Commodity derivatives:	(473)	(190)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(473)	(190)
Level 2 [Member]
Commodity derivatives:	62	24
Other Assets, Fair Value Disclosure	9	13
Total assets	71	37
Interest rate derivatives	(23)	(387)
Commodity derivatives:	(53)	(21)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(76)	(408)
Commodity Derivatives - Power [Member] \| Forwards Swaps [Member]
Commodity derivatives:	52	17
Commodity derivatives:	(51)	(15)
Commodity Derivatives - Power [Member] \| Future [Member]
Commodity derivatives:	3	6
Commodity derivatives:	(3)	(4)
Commodity Derivatives - Power [Member] \| Level 1 [Member] \| Forwards Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0
Commodity Derivatives - Power [Member] \| Level 1 [Member] \| Future [Member]
Commodity derivatives:	3	6
Commodity derivatives:	(3)	(4)
Commodity Derivatives - Power [Member] \| Level 2 [Member] \| Forwards Swaps [Member]
Commodity derivatives:	52	17
Commodity derivatives:	(51)	(15)
Commodity Derivatives - Power [Member] \| Level 2 [Member] \| Future [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Commodity Derivatives - Refined Products [Member] \| Future [Member]
Commodity derivatives:	20	3
Commodity derivatives:	(59)	(18)
Commodity Derivatives - Refined Products [Member] \| Level 1 [Member] \| Future [Member]
Commodity derivatives:	20	3
Commodity derivatives:	(59)	(18)
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:	38	16
Commodity derivatives:	(12)	(3)
Commodity Derivatives - Crude [Member] \| Level 1 [Member] \| Forwards Swaps [Member]
Commodity derivatives:	38	16
Commodity derivatives:	(12)	(3)
Commodity Derivatives - Crude [Member] \| Level 2 [Member] \| Forwards Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	60	7
Commodity derivatives:	(25)	(10)
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives:	75	38
Commodity derivatives:	(12)	(6)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives:	113	26
Commodity derivatives:	(4)	(9)
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Contracts [Member]
Commodity derivatives:	(2)	(6)
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Swaps [Member]
Commodity derivatives:	10	7
Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	60	7
Commodity derivatives:	(25)	(10)
Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives:	75	38
Commodity derivatives:	(12)	(6)
Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives:	113	26
Commodity derivatives:	(4)	(9)
Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Forward Physical Contracts [Member]
Commodity derivatives:	0	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
Commodity Derivatives - Natural Gas [Member] \| Level 2 [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
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:	(2)	(6)
Commodity Derivatives - Natural Gas [Member] \| Level 2 [Member] \| Forward Physical Swaps [Member]
Commodity derivatives:	10	7
Commodity Derivatives - NGLs [Member] \| Forwards Swaps [Member]
Commodity derivatives:	317	152
Commodity derivatives:	(358)	(140)
Commodity Derivatives - NGLs [Member] \| Level 1 [Member] \| Forwards Swaps [Member]
Commodity derivatives:	317	152
Commodity derivatives:	(358)	(140)
Commodity Derivatives - NGLs [Member] \| Level 2 [Member] \| Forwards Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	$ 0	$ 0

Acquisitions and Related Transactions Acquisitions (Current Transactions) (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
	Apr. 01, 2022	Nov. 30, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Business Acquisition [Line Items]
Goodwill			$ 33	$ 142
Impairment losses and other			386	$ 21	$ 2,880
Deconsolidation, Gain (Loss), Amount			85
Sunoco LP [Member]
Business Acquisition [Line Items]
Goodwill	$ 20
Other Payments to Acquire Businesses	252
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill	98
Total assets acquired	73
Spindletop Assets
Business Acquisition [Line Items]
Asset Acquisition, Consideration Transferred			$ 325
ET Canada
Business Acquisition [Line Items]
Sale of Stock, Percentage of Ownership before Transaction			51.00%
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates			$ 302
Impairment losses and other			300
ET Canada \| Noncontrolling Interest
Business Acquisition [Line Items]
Impairment losses and other			164
ET Canada \| Common Unitholders
Business Acquisition [Line Items]
Impairment losses and other			136
Woodford Express Acquisition
Business Acquisition [Line Items]
Repayments of Debt			292
Total consideration, net of cash received			$ 485
Working Capital \| Sunoco LP [Member]
Business Acquisition [Line Items]
Total assets acquired	$ 76
Peerless \| Sunoco LP [Member]
Business Acquisition [Line Items]
Other Payments to Acquire Businesses		$ 76

Acquisitions and Related Transactions Acquisitions (PreviousTransactions) (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Dec. 02, 2021

Feb. 28, 2021

Dec. 31, 2021

Dec. 31, 2022

Dec. 31, 2021

Business Acquisition [Line Items]

Preferred Units, Issued

72,184,780

Long-term Debt, Fair Value

$ 54,970

$ 45,420

$ 54,970

Goodwill

$ 33

$ 142

Enable

Business Acquisition [Line Items]

Total consideration, net of cash received

$ 3,458

$ 10

Long-term debt, less current maturities(1)

^[1]

4,267

Senior Notes

3,180

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares

0.8595

Long-term Debt, Fair Value

3,430

Goodwill

138

$ 138

Enable | Enable Five-Year Revolving Credit Facility

Business Acquisition [Line Items]

Line of Credit Facility, Current Borrowing Capacity

Enable | Enable 2019 Term Loan Agreement

Business Acquisition [Line Items]

Line of Credit Facility, Current Borrowing Capacity

$ 800

Enable | Series G Preferred Units [Member]

Business Acquisition [Line Items]

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares

0.0265

Preferred Units, Issued

384,780

[1]

Long-term debt at December 2, 2021 includes Enable senior notes with an aggregate principal amount of $3.18 billion in senior notes and a fair value of $3.43 billion. It also includes $800 million outstanding on the Enable 2019 Term Loan Agreement and $35 million outstanding on the Enable Five-Year Revolving Credit Facility, both of which were repaid and terminated in December 2021, immediately subsequent to the close of the Enable Acquisition.

Acquisitions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition Table) (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Dec. 02, 2021

Feb. 28, 2021

Dec. 31, 2021

Dec. 31, 2022

Dec. 31, 2021

Business Acquisition [Line Items]

Goodwill

$ 33

$ 142

Enable

Business Acquisition [Line Items]

Total current assets

$ 593

Property, plant and equipment, net

7,076

Intangible assets, net

440

Goodwill

138

$ 138

Total consideration

3,519

Total assets acquired

8,326

Total current liabilities

488

Long-term debt, less current maturities(1)

^[1]

4,267

Other non-current liabilities

Total liabilities assumed

4,773

Cash received

Noncontrolling interests

Other non-current assets

Total consideration, net of cash received

3,458

$ 10

Enable | Enable Five-Year Revolving Credit Facility

Business Acquisition [Line Items]

Line of Credit Facility, Current Borrowing Capacity

Enable | Investments in Unconsolidated Affiliates

Business Acquisition [Line Items]

Investments in unconsolidated affiliates

$ 40

Woodford Express Acquisition

Business Acquisition [Line Items]

Total consideration, net of cash received

$ 485

[1]

Advances to and Investments in Unconsolidated Affiliates Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Impairment of investment in unconsolidated affiliates	$ 0	$ 0	$ 129
Citrus [Member]
Interest ownership	50.00%
FGT [Member]
Interest ownership	100.00%
Midcontinent Express Pipeline, LLC [Member]
Interest ownership	50.00%
White Cliffs
Interest ownership	51.00%
Explorer
Interest ownership	15.00%

Advances to and Investments in Unconsolidated Affiliates Investment in Affiliates (Carrying Values) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Investments in unconsolidated affiliates

$ 2,893

$ 2,947

$ 3,060

Equity in earnings of unconsolidated affiliates

257

246

119

Impairment losses and other

386

2,880

Other Affiliates [Member]

Equity in earnings of unconsolidated affiliates

^[1]

(74)

Citrus [Member]

Investments in unconsolidated affiliates

1,800

1,792

Equity in earnings of unconsolidated affiliates

141

157

162

MEP [Member]

Investments in unconsolidated affiliates

360

378

Equity in earnings of unconsolidated affiliates

(17)

(6)

White Cliffs

Investments in unconsolidated affiliates

218

245

Equity in earnings of unconsolidated affiliates

(8)

Other

Investments in unconsolidated affiliates

446

461

FEP [Member]

Impairment losses and other

208

Explorer

Investments in unconsolidated affiliates

Equity in earnings of unconsolidated affiliates

$ 25

$ 24

$ 17

[1]	For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million.

Investments in Affiliates (Summarized Balance Sheet Information) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Schedule of Investments [Line Items]
Assets, Current	$ 12,081	$ 10,537
Other non-current assets, net	1,558	1,645
Assets	105,643	105,963	$ 95,144
Current Liabilities	10,368	10,835
Equity	40,659	39,345	$ 31,388	$ 33,938
Liabilities and Equity	105,643	105,963
Equity Method Investments [Member]
Schedule of Investments [Line Items]
Assets, Current	311	319
Property, plant and equipment, net	7,722	7,803
Other non-current assets, net	86	88
Assets	8,119	8,210
Current Liabilities	291	547
Non-current liabilities	4,347	4,110
Equity	3,481	3,553
Liabilities and Equity	$ 8,119	$ 8,210

Investments in Affiliates (Summarized Income Statement Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Schedule of Equity Method Investments [Line Items]
Revenues	$ 89,876	$ 67,417	$ 38,954
Net income	5,868	6,687	140
Equity Method Investments [Member]
Schedule of Equity Method Investments [Line Items]
Revenues	1,518	1,393	1,405
Equity Method Investments Summarized Financial Information, Operating Income	704	684	732
Net income	$ 463	$ 446	$ 480

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(ii))
-URI https://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1A
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126968391&loc=SL7669619-108580

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 1A
-Subparagraph (a)(1)
-URI https://asc.fasb.org/extlink&oid=109239629&loc=SL4573702-111684

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 9
-URI https://asc.fasb.org/extlink&oid=124431687&loc=d3e22663-107794

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(i))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(i))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8736-108599

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8933-108599

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 40
-Section 65
-Paragraph 1
-Subparagraph (f)
-URI https://asc.fasb.org/extlink&oid=126732423&loc=SL123482106-238011

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(5))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iv))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 12: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 50
-Paragraph 6
-URI https://asc.fasb.org/extlink&oid=124431353&loc=SL124452729-227067

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8906-108599

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 2
-URI https://asc.fasb.org/extlink&oid=126954810&loc=d3e3000-108585

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 45
-Paragraph 19
-URI https://asc.fasb.org/extlink&oid=126929396&loc=SL4569616-111683

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=114001798&loc=d3e33918-111571

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (f)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8933-108599

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(A))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 7
-URI https://asc.fasb.org/extlink&oid=109222650&loc=SL51721683-107760

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (b)(2)
-URI https://asc.fasb.org/extlink&oid=124431687&loc=d3e22499-107794

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-Subparagraph (f)
-URI https://asc.fasb.org/extlink&oid=123596393&loc=d3e14064-108612

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 235
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-05(b)(2))
-URI https://asc.fasb.org/extlink&oid=120399901&loc=d3e537907-122884

Reference 23: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8924-108599

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1B
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126968391&loc=SL7669625-108580

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iv))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iii)(A))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 27: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(5))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(B))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 29: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(ii))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 30: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 1A
-Subparagraph (c)(1)
-URI https://asc.fasb.org/extlink&oid=109239629&loc=SL4573702-111684

Reference 31: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4J
-URI https://asc.fasb.org/extlink&oid=120409616&loc=SL4591551-111686

Reference 32: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 55
-Paragraph 4K
-URI https://asc.fasb.org/extlink&oid=120409616&loc=SL4591552-111686

Reference 33: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 8
-URI https://asc.fasb.org/extlink&oid=124431687&loc=d3e22658-107794

+ Details

- Definition

Amount of revenue recognized from goods sold, services rendered, insurance premiums, or other activities that constitute an earning process. Includes, but is not limited to, investment and interest income before deduction of interest expense when recognized as a component of revenue, and sales and trading gain (loss).

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8736-108599

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=114001798&loc=d3e33918-111571

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-Subparagraph (f)
-URI https://asc.fasb.org/extlink&oid=123596393&loc=d3e14064-108612

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8933-108599

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8933-108599

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iv))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8736-108599

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iv))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(A))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e9031-108599

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(i))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(i))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8906-108599

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(5))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e9038-108599

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iii)(A))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(5))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e9054-108599

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(ii))
-URI https://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 235
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-05(b)(2))
-URI https://asc.fasb.org/extlink&oid=120399901&loc=d3e537907-122884

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(B))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 22: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(ii))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(1))
-URI https://asc.fasb.org/extlink&oid=126953954&loc=SL114868664-224227

+ Details

Net Income Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share [Abstract]
NET INCOME	$ 5,868	$ 6,687	$ 140
Less: Net income attributable to redeemable noncontrolling interests	51	50	49
NET INCOME ATTRIBUTABLE TO PARTNERS	4,756	5,470	(648)
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units	(2)	(2)	0
Diluted income (loss) available to Common Unitholders	$ 4,328	$ 5,177	$ (647)
Weighted average common units	3,086.8	2,734.4	2,695.6
Basic	$ 1.40	$ 1.89	$ (0.24)
Dilutive effect of unconverted unit awards and ET Series A Convertible Preferred Units	10.2	5.1	0.0
Weighted average common units, assuming dilutive effect of unvested unit awards	3,097.0	2,739.5	2,695.6
Diluted	$ 1.40	$ 1.89	$ (0.24)
Limited Partners’ interest in net income	$ 4,330	$ 5,179	$ (647)

Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Debt Instrument [Line Items]

Other Long-term Debt

$ 3

Long-term Debt

48,262

49,702

Current maturities of long-term debt

680

Long-term debt, less current maturities

48,260

49,022

Five Year Credit Facility

Debt Instrument [Line Items]

Long-term Line of Credit

793

Bakken Project [Member]

Debt Instrument [Line Items]

Debt Instrument, Unamortized Discount (Premium), Net

(1)

(2)

Deferred Finance Costs, Noncurrent, Net

(7)

(9)

Long-term Debt

1,842

2,489

Bakken Project [Member] | 3.625% Senior Notes due 2022 [Member]

Debt Instrument [Line Items]

Senior Notes

^[1]

$ 0

650

Long-term Debt, Description

3.625% Senior Notes due April 1, 2022(1)

Bakken Project [Member] | 3.90% Senior Notes due 2024 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

3.90% Senior Notes due April 1, 2024

Bakken Project [Member] | 4.625% Senior Notes due 2029 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 850

850

Long-term Debt, Description

4.625% Senior Notes due April 1, 2029

Sunoco LP [Member]

Debt Instrument [Line Items]

Capital Lease Obligations

$ 94

100

Deferred Finance Costs, Noncurrent, Net

(23)

(26)

Long-term Debt

3,571

3,255

Sunoco LP [Member] | 6.00% Senior Notes due April 15, 2027 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 600

600

Long-term Debt, Description

6.00% Senior Notes Due April 15, 2027

Sunoco LP [Member] | Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member]

Debt Instrument [Line Items]

Long-term Line of Credit

$ 900

581

Long-term Debt, Description

Sunoco LP $1.50 billion Revolving Credit Facility due July 2023

Sunoco LP [Member] | 5.875% senior notes due 2028 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 400

400

Long-term Debt, Description

5.875% Senior Notes Due March 15, 2028

Sunoco LP [Member] | 4.50% Senior Notes due May 15, 2029

Debt Instrument [Line Items]

Senior Notes

$ 800

800

Long-term Debt, Description

4.50% Senior Notes due May 15, 2029

Sunoco LP [Member] | 4.50% Senior Notes due April 30, 2030

Debt Instrument [Line Items]

Senior Notes

$ 800

800

Long-term Debt, Description

4.50% Senior Notes due April 30, 2030

Transwestern [Member]

Debt Instrument [Line Items]

Long-term Debt

$ 250

400

Transwestern [Member] | 5.89% Senior Unsecured Notes, due May 24, 2022 [Member]

Debt Instrument [Line Items]

Senior Notes

^[2]

$ 0

150

Long-term Debt, Description

^[2]

5.89% Senior Notes due May 24, 2022(1)

Transwestern [Member] | 5.66% Senior Unsecured Notes, due December 9, 2024 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 175

175

Long-term Debt, Description

5.66% Senior Notes due December 9, 2024

Transwestern [Member] | 6.16% Senior Unsecured Notes, due May 24, 2037 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 75

Long-term Debt, Description

6.16% Senior Notes due May 24, 2037

Panhandle [Member]

Debt Instrument [Line Items]

Debt Instrument, Unamortized Discount (Premium), Net

^[3]

$ 0

Long-term Debt

243

Panhandle [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]

Debt Instrument [Line Items]

Senior Notes

^[3]

$ 0

Long-term Debt, Description

7.60% Senior Notes due February 1, 2024(4)

Panhandle [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]

Debt Instrument [Line Items]

Senior Notes

^[3]

$ 0

Long-term Debt, Description

8.25% Senior Notes due November 15, 2029(4)

Panhandle [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member]

Debt Instrument [Line Items]

Junior Subordinated Notes

^[3]

$ 0

Long-term Debt, Description

Floating Rate Junior Subordinated Notes due November 1, 2066(4)

Panhandle [Member] | 7.00% Senior Notes, due July 15, 2029 [Member]

Debt Instrument [Line Items]

Senior Notes

^[3]

$ 0

Long-term Debt, Description

7.00% Senior Notes due July 15, 2029(4)

USA Compression Partners, LP [Member]

Debt Instrument [Line Items]

Long-term Line of Credit

^[4]

$ 646

516

Deferred Finance Costs, Noncurrent, Net

(14)

(18)

Long-term Debt

$ 2,107

1,973

Long-term Debt, Description

USAC $1.60 billion Revolving Credit Facility due December 2026(5)

USA Compression Partners, LP [Member] | 6.875% Senior notes due April 2026 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 725

725

Long-term Debt, Description

6.875% Senior Notes due April 1, 2026

USA Compression Partners, LP [Member] | 6.875% Senior Notes due September 2027 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 750

750

Long-term Debt, Description

6.875% Senior Notes due September 1, 2027

SemGroup [Member]

Debt Instrument [Line Items]

Debt Instrument, Unamortized Discount (Premium), Net

$ 0

(1)

Long-term Debt

225

224

SemGroup [Member] | HFOTCO Tax Exempt Notes due 2050 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 225

225

Long-term Debt, Description

HFOTCO Tax Exempt Notes due 2050

ET [Member]

Debt Instrument [Line Items]

Debt Instrument, Unamortized Discount (Premium), Net

$ 184

233

Deferred Finance Costs, Noncurrent, Net

(181)

(186)

Long-term Debt

40,264

40,717

ET [Member] | 5.875% Senior Notes due January 15, 2024 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,127

1,127

Long-term Debt, Description

5.875% Senior Notes due January 15, 2024

ET [Member] | 5.5% Senior Notes due June 1, 2027 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 956

956

Long-term Debt, Description

5.50% Senior Notes due June 1, 2027

ET [Member] | 4.25% Senior Notes due March 15, 2023 [Member]

Debt Instrument [Line Items]

Senior Notes

^[2]

$ 995

995

Long-term Debt, Description

4.25% Senior Notes due March 15, 2023(3)

ET [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 277

277

Long-term Debt, Description

7.60% Senior Notes due February 1, 2024

ET [Member] | 4.05% Senior Notes due March 2025 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

4.05% Senior Notes due March 15, 2025

ET [Member] | 4.75% Senior Notes due January 2026 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

4.75% Senior Notes due January 15, 2026

ET [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 267

267

Long-term Debt, Description

8.25% Senior Notes due November 15, 2029

ET [Member] | 4.90% Senior Notes due March 2035 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 500

500

Long-term Debt, Description

4.90% Senior Notes due March 15, 2035

ET [Member] | 6.625% Senior Notes, due October 15, 2036 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 400

400

Long-term Debt, Description

6.625% Senior Notes due October 15, 2036

ET [Member] | 5.80% Senior Notes due 2038 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 500

500

Long-term Debt, Description

5.80% Senior Notes due June 15, 2038

ET [Member] | 7.5% Senior Notes, due July 1, 2038 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 550

550

Long-term Debt, Description

7.50% Senior Notes due July 1, 2038

ET [Member] | Senior Notes 6.05% Due June 1, 2041 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 700

700

Long-term Debt, Description

6.05% Senior Notes due June 1, 2041

ET [Member] | Senior Notes 6.50% Due February 1, 2042 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

6.50% Senior Notes due February 1, 2042

ET [Member] | 5.15% Senior Notes due February 1, 2043 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 450

450

Long-term Debt, Description

5.15% Senior Notes due February 1, 2043

ET [Member] | 5.95% Senior Notes due October 1, 2043 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 450

450

Long-term Debt, Description

5.95% Senior Notes due October 1, 2043

ET [Member] | 5.15% Senior Notes due March 2045 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

5.15% Senior Notes due March 15, 2045

ET [Member] | 6.125% Senior Notes due December 2045 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

6.125% Senior Notes due December 15, 2045

ET [Member] | 5.30% Senior Notes due April 2047 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 900

900

Long-term Debt, Description

5.30% Senior Notes due April 15, 2047

ET [Member] | 5.40% Senior Notes due October 1, 2047 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,500

1,500

Long-term Debt, Description

5.40% Senior Notes due October 1, 2047

ET [Member] | 6.0% Senior Notes due 2048 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

6.00% Senior Notes due June 15, 2048

ET [Member] | 6.25% Senior Notes due 2049 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,750

1,750

Long-term Debt, Description

6.25% Senior Notes due April 15, 2049

ET [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member]

Debt Instrument [Line Items]

Junior Subordinated Notes

$ 600

546

ET [Member] | 9.00% Debentures, due 2024 [Member]

Debt Instrument [Line Items]

Subordinated Debt

$ 65

Long-term Debt, Description

9.00% Debentures due November 1, 2024

ET [Member] | Senior Note 4.65% Due February 15, 2022 [Member]

Debt Instrument [Line Items]

Senior Notes

^[1]

$ 0

300

Long-term Debt, Description

4.65% Senior Notes due February 15, 2022(1)

ET [Member] | 3.45% Senior Notes due January 2023 [Member]

Debt Instrument [Line Items]

Senior Notes

^[2],[5]

$ 350

350

Long-term Debt, Description

3.45% Senior Notes due January 15, 2023(2)(3)

ET [Member] | 6.85% Senior Notes, due February 15, 2040 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 250

250

Long-term Debt, Description

6.85% Senior Notes due February 15, 2040

ET [Member] | 4.25% Senior Notes due April 1, 2024 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 500

500

Long-term Debt, Description

4.25% Senior Notes due April 1, 2024

ET [Member] | 4.5% Senior Notes due 2024 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 750

750

Long-term Debt, Description

4.50% Senior Notes due April 15, 2024

ET [Member] | 5.95% Senior Notes due December 2025 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 400

400

Long-term Debt, Description

5.95% Senior Notes due December 1, 2025

ET [Member] | 3.90% Senior Notes due July 15, 2026 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 550

550

Long-term Debt, Description

3.90% Senior Notes due July 15, 2026

ET [Member] | 4.20% Senior Notes due April 2027 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 600

600

Long-term Debt, Description

4.20% Senior Notes due April 15, 2027

ET [Member] | 4.00% Senior Notes due October 1, 2027 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 750

750

Long-term Debt, Description

4.00% Senior Notes due October 1, 2027

ET [Member] | 4.95% Senior Notes due 2028 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

4.95% Senior Notes due June 15, 2028

ET [Member] | 5.25% Senior Notes due 2029 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,500

1,500

Long-term Debt, Description

5.25% Senior Notes due April 15, 2029

ET [Member] | Senior Note 6.10%, due February 15, 2042 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 300

300

Long-term Debt, Description

6.10% Senior Notes due February 15, 2042

ET [Member] | 5.30% Senior Notes due April 1, 2044 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 700

700

Long-term Debt, Description

5.30% Senior Notes due April 1, 2044

ET [Member] | 5.35% Senior Notes due May 15, 2045 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 800

800

Long-term Debt, Description

5.35% Senior Notes due May 15, 2045

ET [Member] | 4.95% Senior Notes due January 2043 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 350

350

Long-term Debt, Description

4.95% Senior Notes due January 15, 2043

ET [Member] | 7.00% Senior Notes, due July 15, 2029 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 66

Long-term Debt, Description

7.00% Senior Notes due July 15, 2029(4)

ET [Member] | 4.5% Senior Notes due November 1, 2023 [Member]

Debt Instrument [Line Items]

Senior Notes

^[2]

$ 600

600

Long-term Debt, Description

4.50% Senior Notes due November 1, 2023(3)

ET [Member] | 4.9% Senior Notes due February 1, 2024 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 350

350

Long-term Debt, Description

4.90% Senior Notes due February 1, 2024

ET [Member] | 5.0% Senior Notes due October 1, 2022 [Member]

Debt Instrument [Line Items]

Senior Notes

^[1]

$ 0

700

Long-term Debt, Description

^[2]

5.00% Senior Notes due October 1, 2022(1)

ET [Member] | 3.6% Senior Notes due February 1, 2023 [Member]

Debt Instrument [Line Items]

Senior Notes

^[2],[5]

$ 800

800

Long-term Debt, Description

3.60% Senior Notes due February 1, 2023(2)(3)

ET [Member] | 4.20% Senior Notes due 2023 [Member]

Debt Instrument [Line Items]

Senior Notes

^[2]

$ 500

500

Long-term Debt, Description

4.20% Senior Notes due September 15, 2023(3)

ET [Member] | 2.9% Senior Notes due May 15, 2025

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

2.90% Senior Notes due May 15, 2025

ET [Member] | 3.75 Senior Notes due May 15, 2030

Debt Instrument [Line Items]

Senior Notes

$ 1,500

1,500

Long-term Debt, Description

3.75% Senior Note due May 15, 2030

ET [Member] | 5.00% Senior Notes due May 15, 2050

Debt Instrument [Line Items]

Senior Notes

$ 2,000

2,000

Long-term Debt, Description

5.00% Senior Notes due May 15, 2050

ET [Member] | Five Year Credit Facility

Debt Instrument [Line Items]

Long-term Line of Credit

$ 793

2,937

ET [Member] | 5.00% Senior Notes due May 15, 2044

Debt Instrument [Line Items]

Senior Notes

^[6]

$ 531

531

Long-term Debt, Description

^[6]

5.00% Senior Notes due May 15, 2044

ET [Member] | 3.90% Senior Notes due May 15, 2024

Debt Instrument [Line Items]

Senior Notes

$ 600

600

Long-term Debt, Description

3.90% Senior Notes due May 15, 2024

ET [Member] | 4.40% Senior Notes due March 15, 2027

Debt Instrument [Line Items]

Senior Notes

$ 700

700

Long-term Debt, Description

4.40% Senior Notes due March 15, 2027

ET [Member] | 4.95% Senior Notes due May 15, 2028

Debt Instrument [Line Items]

Senior Notes

$ 800

800

Long-term Debt, Description

^[6]

4.95% Senior Notes due May 15, 2028

ET [Member] | 4.15% Senior Notes due September 15, 2029

Debt Instrument [Line Items]

Senior Notes

$ 547

547

Long-term Debt, Description

^[6]

4.15% Senior Notes due September 15, 2029

ET [Member] | 4.25% Senior Notes due March 15, 2023

Debt Instrument [Line Items]

Senior Notes

^[2]

$ 5

Long-term Debt, Description

4.25% Senior Notes due March 15, 2023(3)

ET [Member] | 5.875% Senior Notes due January 15, 2024

Debt Instrument [Line Items]

Senior Notes

$ 23

Long-term Debt, Description

5.875% Senior Notes due January 15, 2024

ET [Member] | 5.5% Senior Notes due June 1, 2027

Debt Instrument [Line Items]

Senior Notes

$ 44

Long-term Debt, Description

5.50% Senior Notes due June 1, 2027

ET [Member] | 5.55% Senior Notes due February 15, 2028

Debt Instrument [Line Items]

Senior Notes

$ 1,000

Long-term Debt, Description

5.55% Senior Notes due February 15, 2028

ET [Member] | 5.75% Senior Notes due February 15, 2023

Debt Instrument [Line Items]

Senior Notes

$ 1,500

Long-term Debt, Description

5.75% Senior Notes due February 15, 2033

ET [Member] | 8.25% Senior Notes due to November 15, 2029 - Previously held by Panhandle

Debt Instrument [Line Items]

Senior Notes

^[3]

$ 33

Long-term Debt, Description

8.25% Senior Notes due November 15, 2029(4)

ET [Member] | 7.60% Senior Notes, due February 1, 2024, previously held by Panhandle

Debt Instrument [Line Items]

Senior Notes

^[3]

$ 82

Long-term Debt, Description

^[3]

7.60% Senior Notes due February 1, 2024(4)

Energy Transfer Canada

Debt Instrument [Line Items]

Long-term Debt

$ 0

398

Energy Transfer Canada | Energy Transfer Canada Revolver

Debt Instrument [Line Items]

Long-term Line of Credit

^[6]

$ 0

$ 398

Long-term Debt, Description

Energy Transfer Canada facilities(6)

[1]	These notes were redeemed in 2022.(2)These notes were redeemed in the first quarter of 2023.
[2]	As of December 31, 2022, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.
[3]	As discussed previously, Panhandle’s debt was assumed by Energy Transfer during 2022 as a result of an internal reorganization.
[4]	The USAC Credit Facility matures in December 2026, except that if any portion of the 6.875% Senior Notes due 2026 are outstanding on December 31, 2025, the USAC Credit Facility will mature on December 31, 2025.
[5]	These notes were redeemed in the first quarter of 2023
[6]	(6)These facilities were included in the August 2022 Energy Transfer Canada divestiture as discussed in Note 3.

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Debt Obligations [Abstract]
2023	$ 3,250
2024	5,175
2025	2,400
2026	2,921
2027	6,093
Thereafter	28,465
Long-term Debt	$ 48,304

Debt Obligations (Debt Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Unamortized Discounts, Premiums, Fair Value Adjustments and Deferred Debt Issuance Costs	$ (42)
Five Year Credit Facility
Line of Credit Facility, Current Borrowing Capacity	5,000
Letters of Credit Outstanding, Amount	32
Line of Credit Facility, Remaining Borrowing Capacity	$ 4,180
Line of Credit Facility, Interest Rate at Period End	5.12%
Outstanding borrowings	$ 793
Long-term Commercial Paper, Noncurrent	750
USAC [Member] \| USAC Credit Facility, due 2023 [Member]
Line of Credit Facility, Current Borrowing Capacity	954
Letters of Credit Outstanding, Amount	0
Line of Credit Facility, Remaining Borrowing Capacity	$ 333
Line of Credit Facility, Interest Rate at Period End	6.84%
Outstanding borrowings	$ 646
Line of Credit Facility, Maximum Borrowing Capacity	1,600
Sunoco LP [Member] \| Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member]
Line of Credit Facility, Current Borrowing Capacity	1,500
Letters of Credit Outstanding, Amount	7
Line of Credit Facility, Remaining Borrowing Capacity	$ 593
Line of Credit Facility, Interest Rate at Period End	6.17%
Outstanding borrowings	$ 900	$ 581
Accordion feature [Member] \| Five Year Credit Facility
Line of Credit Facility, Current Borrowing Capacity	7,000
Accordion feature [Member] \| USAC [Member] \| USAC Credit Facility, due 2023 [Member]
Line of Credit Facility, Maximum Borrowing Capacity	$ 200

Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2022
USAC Credit Facility, due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain:•a minimum EBITDA to interest coverage ratio;•a ratio of total secured indebtedness to EBITDA within a specified range; and •a maximum funded debt to EBITDA ratio.
Five Year Credit Facility \| ET [Member]
Debt Instrument [Line Items]
Leverage Ratio Maximum	5.00
Maximum Leverage Ratio Permitted	5.50
Supplementary Leverage Ratio	3.32
Five Year Credit Facility \| Minimum [Member] \| ET [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.125%
Five Year Credit Facility \| Minimum [Member] \| ET [Member] \| Eurodollar [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.125%
Five Year Credit Facility \| Minimum [Member] \| ET [Member] \| Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.125%
Five Year Credit Facility \| Maximum [Member] \| ET [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%
Five Year Credit Facility \| Maximum [Member] \| ET [Member] \| Eurodollar [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%
Five Year Credit Facility \| Maximum [Member] \| ET [Member] \| Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Sunoco LP Credit Facility
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	Sunoco LP’s Credit Facility requires Sunoco LP to maintain a specified net leverage ratio and interest coverage ratio.

Redeemable Preferred Units (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2018	Dec. 31, 2022	Apr. 02, 2023	Dec. 31, 2021	Apr. 02, 2018
Redeemable noncontrolling interests		$ 493		$ 783
Preferred Units, Issued		72,184,780		72,184,780
Preferred Units, Outstanding		72,184,780		72,184,780
USAC [Member]
Redeemable noncontrolling interests		$ 477
Convertible Preferred Stock, Shares Issued upon Conversion		16,657,088	24,985,633
ET [Member]
Redeemable noncontrolling interests		$ 16
Preferred Units [Member] \| USAC [Member]
Preferred Units, Issued					500,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 24.375
Preferred Units, Outstanding		333,333
Preferred Units, Description		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 USAC may elect to pay up to 50% of such redemption amount in USAC common units
USAC Preferred Units
Redeemable Noncontrolling Interest, Equity, Carrying Amount				$ 477
Noncontrolling Interest
Redeemable noncontrolling interests				15
Energy Transfer Canada preferred shares
Redeemable noncontrolling interests				$ 291

Equity (Narrative) (Details) - USD ($)
$ / shares in Units, $ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Jan. 01, 2020

Apr. 30, 2019

Oct. 31, 2018

Jul. 31, 2018

Apr. 30, 2018

Nov. 30, 2017

Dec. 31, 2022

Sep. 30, 2022

Jun. 30, 2022

Mar. 31, 2022

Dec. 31, 2021

Sep. 30, 2021

Jun. 30, 2021

Mar. 31, 2021

Dec. 31, 2020

Sep. 30, 2020

Jun. 30, 2020

Mar. 31, 2020

Dec. 31, 2019

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Apr. 27, 2022

Jan. 31, 2020

Issuance of Common Units (2)

^[1]

11,900,000

9,700,000

12,800,000

Stock Repurchase Program, Authorized Amount

$ 2,000

Stock Repurchase Program, Remaining Authorized Repurchase Amount

$ 880

Minimum beneficial percentage ownership, other than the Partnership's General Partner and its affiliates, no voting rights, not considered outstanding

20.00%

Limited Partners' Capital Account, Units Outstanding

3,094,425,367

3,082,497,494

2,702,400,000

2,689,600,000

3,094,425,367

3,082,497,494

2,702,400,000

Stock Issued During Period, Value, Dividend Reinvestment Plan

$ 61

Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan

12,000,000

Preferred Units, Issued

72,184,780

Partners' Capital Account, Units, Treasury Units Purchased

4,200,000

Incentive Distribution Rights

0.00%

Issued

3,094,425,367

3,082,497,494

3,094,425,367

3,082,497,494

Series A Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[2]

$ 31.25

$ 0

$ 31.25

$ 0

$ 31.25

$ 0

^[3]

$ 31.25

$ 0

Units issued for cash

Preferred Stock, Shares Outstanding

950,000

Series C Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.4609

0.4609

^[3]

0.4609

Units issued for cash

Preferred Stock, Shares Outstanding

18,000,000

Series D Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.4766

0.4766

^[3]

0.4766

Units issued for cash

Preferred Stock, Shares Outstanding

17,800,000

Series E Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.4750

0.4750

^[3]

0.4750

Units issued for cash

Preferred Stock, Shares Outstanding

32,000,000

Series F Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[2]

$ 0

33.7500

^[3]

33.7500

Units issued for cash

Preferred Stock, Shares Outstanding

500,000

Series G Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[2]

$ 0

35.63

^[3]

35.63

Units issued for cash

Preferred Stock, Shares Outstanding

1,484,780

Series B Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[2]

$ 33.13

33.13

^[3]

33.13

Units issued for cash

Preferred Stock, Shares Outstanding

550,000

Series H Preferred Units

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[2]

$ 0

32.50

27.08

^[3]

Units issued for cash

889,000,000

Preferred Stock, Shares Outstanding

900,000

LE GP, LLC, the general partner of Energy Transfer

Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest

0.10%

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

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.8255

0.8255

$ 0.8255

Limited Partners' Capital Account, Units Outstanding

84,100,000

USAC [Member]

Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.

46,100,000

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.5250

Limited Partners' Capital Account, Units Outstanding

98,200,000

Stock Issued During Period, Shares, Dividend Reinvestment Plan

124,255

118,399

Class of Warrant or Right, Exercise Price of Warrants or Rights

$ 19.59

Warrants and Rights Outstanding

$ 10

Series A Preferred Units [Member]

Preferred Stock, Dividend Rate, Percentage

6.25%

Shares Issued, Price Per Share

$ 1,000

Preferred Units, Liquidation Spread, Percent

4.028%

Series C Preferred Units [Member]

Preferred Stock, Dividend Rate, Percentage

7.375%

Shares Issued, Price Per Share

$ 25

Preferred Units, Liquidation Spread, Percent

4.53%

Series B Preferred Units [Member]

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

Preferred Units, Liquidation Spread, Percent

4.738%

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%

Series F Preferred Units [Member]

Preferred Stock, Dividend Rate, Percentage

6.75%

Shares Issued, Price Per Share

$ 1,000

Preferred Units, Liquidation Spread, Percent

5.134%

Series G Preferred Units [Member]

Preferred Stock, Dividend Rate, Percentage

7.125%

Shares Issued, Price Per Share

$ 1,000

Preferred Units, Liquidation Spread, Percent

5.306%

Series H Preferred Units

Preferred Stock, Dividend Rate, Percentage

6.50%

Shares Issued, Price Per Share

$ 1,000

Preferred Units, Liquidation Spread, Percent

5.694%

ETE Class A Units [Member] | ETE Merger [Member]

Sale of Stock, Number of Shares Issued in Transaction

765,933,429

USAC Issue Tranche 1 | USAC [Member]

Issued

534,308

[1]	Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.
[2]	(1) Series A, Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Pursuant to their terms, distributions on the Series A and Series B preferred units will be paid quarterly beginning after February 15, 2023 and February 15, 2028, respectively
[3]	* Represents prorated initial distribution.

Equity (Change In ETE Common Units) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Dec. 31, 2019

Issuance of Common Units (2)

^[1]

11,900,000

9,700,000

12,800,000

Outstanding

3,094,425,367

3,082,497,494

2,702,400,000

2,689,600,000

Issuance of restricted Common Units under long-term incentive plans

^[2]

(374,600,000)

Common Units repurchased

(4,200,000)

Number of Common Units, end of period

3,094,425,367

3,082,497,494

2,702,400,000

Equity

$ 40,659

$ 39,345

$ 31,388

$ 33,938

Distributions to partners

(3,047)

(1,898)

(2,802)

Units issued in connection with the Enable Acquisition(1)

^[3]

3,509

Series A Preferred Units [Member]

Equity

958

Preferred units conversion

$ 943

Units issued for cash

Distributions to partners

(59)

$ (30)

Units issued in connection with the Enable Acquisition(1)

Other, net

Net income

Series B Preferred Units [Member]

Equity

556

Preferred units conversion

$ 547

Units issued for cash

Distributions to partners

(36)

$ (18)

Units issued in connection with the Enable Acquisition(1)

Other, net

Net income

Series C Preferred Units [Member]

Equity

440

Preferred units conversion

$ 440

Units issued for cash

Distributions to partners

(33)

$ (25)

Units issued in connection with the Enable Acquisition(1)

Other, net

Net income

Series D Preferred Units [Member]

Equity

434

Preferred units conversion

$ 434

Units issued for cash

Distributions to partners

(34)

$ (25)

Units issued in connection with the Enable Acquisition(1)

Other, net

Net income

Series E Preferred Units [Member]

Equity

786

Preferred units conversion

$ 786

Units issued for cash

Distributions to partners

(61)

$ (45)

Units issued in connection with the Enable Acquisition(1)

Other, net

Net income

Series F Preferred Units [Member]

Equity

496

Preferred units conversion

$ 504

Units issued for cash

Distributions to partners

(34)

$ (34)

Units issued in connection with the Enable Acquisition(1)

Other, net

Net income

Series G Preferred Units [Member]

Equity

1,488

Preferred units conversion

$ 1,114

Units issued for cash

Distributions to partners

(106)

$ (79)

Units issued in connection with the Enable Acquisition(1)

392

Other, net

Net income

106

Series H Preferred Units

Equity

893

Preferred units conversion

$ 0

Units issued for cash

889,000,000

Distributions to partners

(59)

$ (24)

Units issued in connection with the Enable Acquisition(1)

Other, net

(3)

Net income

Preferred Units [Member]

Equity

6,051

$ 0

Preferred units conversion

$ 4,768

Units issued for cash

889,000,000

Distributions to partners

(422)

$ (280)

Units issued in connection with the Enable Acquisition(1)

392

Other, net

(3)

Net income

$ 422

$ 285

[1]	Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.
[2]	In December 2021, Energy Transfer issued 374.6 million Energy Transfer Common Units in connection with the Enable Acquisition.
[3]	See Note 3 for additional information.

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

3 Months Ended

12 Months Ended

Dec. 31, 2022

Sep. 30, 2022

Jun. 30, 2022

Mar. 31, 2022

Dec. 31, 2021

Sep. 30, 2021

Jun. 30, 2021

Mar. 31, 2021

Dec. 31, 2020

Sep. 30, 2020

Jun. 30, 2020

Mar. 31, 2020

Dec. 31, 2019

Dec. 31, 2022

Parent Company [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.3050

$ 0.2650

$ 0.2300

$ 0.2000

$ 0.1750

$ 0.1525

$ 0.3050

USAC [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.5250

Sunoco LP [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.8255

$ 0.8255

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

Common Stock | Minimum Quarterly Distribution [Member]

Distribution Payment Targets

100%

Common Stock | First Target Distribution [Member]

Distribution Payment Targets

100%

Common Stock | Second Target Distribution [Member]

Distribution Payment Targets

85%

Common Stock | Third Target Distribution [Member]

Distribution Payment Targets

75%

Common Stock | Thereafter [Member]

Distribution Payment Targets

50%

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%

Series A Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

31.25

^[2]

31.25

Series B Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

33.13

^[2]

33.13

Series C Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.4609

^[2]

0.4609

Series D Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.4766

^[2]

0.4766

Series E Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.4750

^[2]

0.4750

Series F Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

33.7500

^[2]

33.7500

Series G Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

35.63

^[2]

35.63

Series H Preferred Units

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

$ 0

$ 32.50

$ 0

$ 32.50

$ 0

$ 27.08

^[2]

$ 0

[1]	(1) Series A, Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Pursuant to their terms, distributions on the Series A and Series B preferred units will be paid quarterly beginning after February 15, 2023 and February 15, 2028, respectively
[2]	* Represents prorated initial distribution.

Equity (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 9	$ 19
Foreign currency translation adjustment	1	13
Actuarial gain (loss) related to pensions and other postretirement benefits	(7)	5
Investments in unconsolidated affiliates, net	13	(11)
Total AOCI, net of tax	16	26
Amounts attributable to noncontrolling interests	0	(3)
Total AOCI included in partners’ capital, net of tax	$ 16	$ 23

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References + Details

Equity Tax amounts in components of other comprehensive income (loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Available-for-sale securities	$ 1	$ (1)
Foreign currency translation adjustment	6	6
Actuarial loss relating to pension and other postretirement benefits	1	1
Other Comprehensive Income (Loss), Tax	$ 8	$ 6

- Definition

Amount of tax expense (benefit) allocated to other comprehensive income (loss).

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 20
-Section 45
-Paragraph 11
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=123586238&loc=d3e39076-109324

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 830
-SubTopic 30
-Section 45
-Paragraph 17
-URI https://asc.fasb.org/extlink&oid=118261656&loc=d3e32136-110900

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 830
-SubTopic 30
-Section 45
-Paragraph 20
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=118261656&loc=d3e32211-110900

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 20
-Section 45
-Paragraph 2
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=123586238&loc=d3e38679-109324

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 50
-Paragraph 4
-URI https://asc.fasb.org/extlink&oid=124431353&loc=SL124442407-227067

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04(23))
-URI https://asc.fasb.org/extlink&oid=120399700&loc=SL114874048-224260

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(21))
-URI https://asc.fasb.org/extlink&oid=126953954&loc=SL114868664-224227

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 10
-URI https://asc.fasb.org/extlink&oid=121826272&loc=d3e32672-109319

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 830
-SubTopic 30
-Section 50
-Paragraph 1
-URI https://asc.fasb.org/extlink&oid=6450520&loc=d3e32583-110901

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 12
-URI https://asc.fasb.org/extlink&oid=126968391&loc=d3e640-108580

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(19))
-URI https://asc.fasb.org/extlink&oid=120400993&loc=SL114874131-224263

+ Details

Equity Incentive Narrative (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Awards granted	$ 11.56
Unvested awards	37.7	36.1
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	3 years 2 months 12 days
Awards granted	12.4
ETE Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	3.6
ET Unit Based Compensation Plans [Member]
Awards granted		$ 8.46	$ 6.29
Fair Value Of Units As Of The Vesting Date	$ 103.0	$ 52.0	$ 51.0
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 248.0
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	3 years 1 month 2 days
Subsidiary Unit Based Compensation [Member]
Fair Value Of Units As Of The Vesting Date	$ 26.0	$ 24.0	$ 16.0
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 42.0
ET Cash Restricted Unit Plan [Member]
Unvested awards	8.5
Awards granted	3.8	3.9	7.7
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 4.2

ET Equity Incentive Plans (Details) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Awards granted	12.4
Awards granted	$ 11.56
Unvested awards	37.7	36.1
Unvested awards	$ 9,620,000	$ 9.49
Awards vested	(9.3)
Awards vested	$ 11.79
Awards forfeited	(1.5)
Awards forfeited	$ 9.39

Subsidiary Equity Incentive Plans (Details) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	37.7	36.1
Unvested awards	$ 9,620,000	$ 9.49
Awards granted	12.4
Awards granted	$ 11.56
Awards vested	(9.3)
Awards vested	$ 11.79
Awards forfeited	1.5
Awards forfeited	$ 9.39
Sunoco LP Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	1.8	2.0
Unvested awards	$ 34.29	$ 30.92
Awards granted	0.4
Awards granted	$ 43.54	$ 37.72	$ 28.63
Awards vested	(0.5)
Awards vested	$ 29.95
Awards forfeited	0.1
Awards forfeited	$ 30.31
USAC Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	2.1	2.2
Unvested awards	$ 14.21	$ 13.57
Awards granted	0.6
Awards granted	$ 18.31	$ 14.92	$ 12.55
Awards vested	(0.4)
Awards vested	$ 15.89
Awards forfeited	0.3
Awards forfeited	$ 14.10

Income Taxes Narrative (Details) - USD ($)	12 Months Ended
Income Taxes Narrative (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating Loss Carryforwards [Line Items]
Deferred Tax Liabilities, Gross	$ 4,345,000,000	$ 4,452,000,000
Net operating losses and other carryforwards	603,000,000	803,000,000
Valuation allowance	(19,000,000)	(34,000,000)
State	17,000,000	24,000,000	$ 32,000,000
Deferred Income Tax Expense (Benefit)	187,000,000	$ 141,000,000	$ 210,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	52,000,000
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, After Tax	48,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Expense	2,000,000
Income Tax Examination, Penalties and Interest Accrued	18,000,000
Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset, Interest Carryforward	169,000,000
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	82,000,000
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	15,000,000
Sunoco Property Company LLC [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	84,000,000
Sunoco Retail LLC
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	0
ETP Holdco
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	645,000,000
Operating Loss Carryforwards	2,400,000,000
PENNSYLVANIA
Operating Loss Carryforwards [Line Items]
State	67,000,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	34,000,000
PENNSYLVANIA \| Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforward, Valuation Allowance	3,000,000
Net of federal tax benefits \| PENNSYLVANIA
Operating Loss Carryforwards [Line Items]
State	53,000,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	27,000,000
Limited NOL Carryforward \| ETP Holdco
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	341,000,000
Limited Under IRC §382 \| Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset, Interest Carryforward	$ 41,000,000

Income Taxes Components of Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current expense (benefit):
Federal	$ 0	$ 19	$ (6)
State	17	24	32
Current Foreign Tax Expense (Benefit)	0	0	1
Total	17	43	27
Deferred expense (benefit):
Federal	239	246	176
State	(58)	(106)	41
Deferred Foreign Income Tax Expense (Benefit)	6	1	(7)
Total	187	141	210
Total income tax expense	$ 204	$ 184	$ 237

Income Taxes Reconciliation of Income Tax Satutory Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income tax expense at United States statutory rate	$ 1,275	$ 1,443	$ 79
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax	(1,086)	(1,211)	88
Noncontrolling interests	26	0	16
State tax, net of federal tax benefit	19	85	58
Statutory rate change	(42)	(46)	0
Valuation allowance	(4)	(63)	0
Uncertain tax positions	(3)	(34)	0
Dividend received deduction	(3)	(4)	0
Foreign taxes	6	1	(7)
Other	16	13	3
Income tax expense	$ 204	$ 184	$ 237

Income Taxes Effects of Temporary Differences That Comprise Net Deffered Income Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Deferred income tax assets:
Net operating losses and other carryforwards	$ 603	$ 803
Other	60	35
Deferred Tax Assets, Gross	663	838
Valuation allowance	(19)	(34)
Net deferred income tax assets	644	804
Deferred income tax liabilities:
Property, plant and equipment	(218)	(314)
Investments in affiliates	(4,010)	(4,042)
Trademarks	(89)	(79)
Other	(28)	(17)
Deferred Tax Liabilities, Gross	4,345	4,452
Deferred Tax Liabilities	$ (3,701)	$ (3,648)

Income Taxes Components of Net Deferred Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Components of Net Deferred Income Tax [Abstract]
Total deferred income tax assets	$ 663	$ 838
Deferred Tax Liabilities, Net	(3,701)	(3,648)
Valuation allowance	19	34
Net deferred income tax assets	$ 644	$ 804

Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Changes in Unrecognized Tax Benefits [Abstract]
Balance at beginning of year	$ 56	$ 90	$ 94
Reduction attributable to tax positions taken in prior years	(4)	(34)	0
Lapse of statute	0	0	4
Balance at end of year	$ 52	$ 56	$ 90

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details)				12 Months Ended
	Sep. 21, 2022 USD ($)	Dec. 29, 2021 USD ($)	Aug. 01, 2020 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Operating Leases, Rent Expense				$ 64,000,000	$ 48,000,000	$ 47,000,000
Payments for Environmental Liabilities				30,000,000	28,000,000
Total environmental liabilities				$ 282,000,000	$ 293,000,000
Site Contingency, Number of Sites Needing Remediation				31
Loss Contingency, Estimate of Possible Loss				$ 750,000,000
Litigation Settlement, Expense				161,000,000
Legal Fees				$ 18,000,000
Environmental Loss Contingency, Statement of Financial Position [Extensible Enumeration]				Other non-current liabilities	Other non-current liabilities
Williams
Loss Contingency, Damages Sought, Value				$ 410,000,000
Litigation Settlement, Expense	$ 601,000,000
Debt Instrument, Interest Rate, Stated Percentage	3.50%
Litigation Settlement, Amount Awarded to Other Party		$ 190,000,000
Cline Class Action \| Actual Damages
Payments for Legal Settlements			$ 74,800,000
Cline Class Action \| Punitive Damages [Member]
Payments for Legal Settlements			75,000,000
Cline Class Action \| Amended Actual Damages
Payments for Legal Settlements			$ 80,700,000
Proposed Civil Penalty
Payments for Legal Settlements				20,000,000
Litigation Settlement, Expense				40,000,000
Culberson
Loss Contingency, Damages Sought, Value				93,000,000
Related To Deductibles [Member]
Loss Contingency Accrual				$ 200,000,000	$ 144,000,000

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) $ in Millions	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Environmental Remediation Obligations [Abstract]
Current	$ 54	$ 46
Non-current	228	247
Total environmental liabilities	$ 282	$ 293
Site Contingency, Number of Sites Needing Remediation	31

Revenue Narrative (Details) - USD ($) $ in Millions	12 Months Ended
Revenue Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Sunoco LP [Member]
Capitalized Contract Cost, Amortization	$ 22	$ 21	$ 18

Revenue Contracts with customers (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jan. 01, 2019
Contract with Customer, Liability	$ 615	$ 459	$ 309
Additions	1,113	849
Deferred Revenue, Revenue Recognized	(944)	(699)
Deferred Revenue, Period Increase (Decrease)	$ (13)
Sunoco LP [Member]
Accounts receivable from contracts with customers		463		$ 834
Contract asset		$ 157		$ 200

Revenue from Contract with Customer - Performance Obligation (Details) $ in Millions	Dec. 31, 2022 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 39,201
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 7,038
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2023
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 6,023
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2024
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	2 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 5,158
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2025
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	3 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 20,982
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2026
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	4 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2027

Lease Accounting Narrative (Details)	Dec. 31, 2022
Real estate leases
Lessee, Operating Lease, Term of Contract	40 years
Minimum [Member]
Lessee, Operating Lease, Renewal Term	1 year
Minimum [Member] \| Terminal facilities, tank cars, office space, land and equipment
Lessee, Operating Lease, Term of Contract	5 years
Maximum [Member]
Lessee, Operating Lease, Renewal Term	20 years
Maximum [Member] \| Terminal facilities, tank cars, office space, land and equipment
Lessee, Operating Lease, Term of Contract	15 years

Lease Accounting - Components of Leases on BS (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Operating lease current liabilities	$ 45	$ 47
Accrued and other current liabilities	3,329	3,071
Non-current operating lease liabilities	798	814
Property, plant and equipment, net	80,311	81,607
Current maturities of long-term debt	2	680
Long-term debt, less current maturities	48,260	49,022
Other non-current liabilities	1,341	1,323
Operating Leases [Member]
Lessee, Lease, Description [Line Items]
Lease right-of-use assets, net	808	826
Operating lease current liabilities	45	47
Accrued and other current liabilities	1	1
Non-current operating lease liabilities	798	814
Finance Leases [Member]
Lessee, Lease, Description [Line Items]
Accrued and other current liabilities	0	1
Property, plant and equipment, net	1	1
Lease right-of-use assets, net	11	12
Current maturities of long-term debt	2	3
Long-term debt, less current maturities	9	9
Other non-current liabilities	$ 1	$ 1

Lease Accounting - Components of Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	$ 88	$ 105
Interest on lease liabilities	0	1
Lease, Cost	94	111
Lease costs, gross	134	156
Finance Leases [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost	0	2
Cost of goods sold
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	3	10
Operating expenses
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	63	78
Short-term lease cost	33	40
Variable lease cost	13	9
Selling, general and administrative
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	22	17
Depreciation, depletion and amortization
Lessee, Lease, Description [Line Items]
Amortization of lease assets	0	1
Other Revenue [Member]
Lessee, Lease, Description [Line Items]
Sublease Income	$ 40	$ 45

Lease Accounting - Remaining term and rate (Details)	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating leases	21 years	19 years
Finance leases	27 years	29 years
Operating leases	5.00%	5.00%
Finance leases	4.00%	4.00%

Lease Accounting - Cash flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Net cash provided by operating activities	$ 9,051	$ 11,162	$ 7,361
Lease assets obtained in exchange for new finance lease liabilities	1	9
Lease assets obtained in exchange for new operating lease liabilities	41	9
Operating Leases [Member]
Lessee, Lease, Description [Line Items]
Net cash provided by operating activities	$ (133)	$ (147)

Lease Accounting - Lease Maturities (Details) $ in Millions	Dec. 31, 2022 USD ($)
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
2023	$ 86
2023	3
2023	89
2024	81
2024	1
2024	82
2025	79
2025	0
2025	79
2026	77
2026	0
2026	77
2027	71
2027	0
2027	71
Thereafter	1,027
Thereafter	15
Thereafter	1,042
Total lease payments	1,421
Total lease payments	19
Lease Liabilities, Due	1,440
Less: present value discount	578
Less: present value discount	6
Less: present value discount	$ 584
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]	Non-current operating lease liabilities
Operating Lease, Liability	$ 843
Finance Lease, Liability	13
Lease, Liabilities	$ 856
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2023
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2024
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2025
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2026
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2027

Lease Accounting - Lessor (Details) $ in Millions	Dec. 31, 2022 USD ($)
Thereafter	$ 1,027
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
Sunoco LP [Member]
2023	$ 67
2024	47
2025	45
2026	43
2027	41
Thereafter	25
Total undiscounted cash flows	$ 268
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2023
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2024
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2025
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2026
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2027

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

Dec. 31, 2022

BBtu

MB_bls

barrels

Dec. 31, 2021

BBtu

MB_bls

barrels

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

Derivative, Nonmonetary Notional Amount, Volume

202,815

106,333

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

Derivative, Nonmonetary Notional Amount, Volume

15,758

63,898

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

Derivative, Nonmonetary Notional Amount, Volume

5,950

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

Derivative, Nonmonetary Notional Amount, Volume

^[1]

39,563

66,665

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

Derivative, Nonmonetary Notional Amount, Volume

37,448

40,533

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

Derivative, Nonmonetary Notional Amount, Volume

37,448

40,533

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

Derivative, Nonmonetary Notional Amount, Volume

42,440

6,738

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

Derivative, Nonmonetary Notional Amount, Volume

2,423

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

Derivative, Nonmonetary Notional Amount, Volume

145

585

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

Derivative, Nonmonetary Notional Amount, Volume

37,448

40,533

Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]

Derivative, Nonmonetary Notional Amount, Volume | MW

30,932

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

Derivative, Nonmonetary Notional Amount, Volume | MW

21,384

604,920

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

Derivative, Nonmonetary Notional Amount, Volume | MW

7,859

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

Derivative, Nonmonetary Notional Amount, Volume | MW

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

Derivative, Nonmonetary Notional Amount, Volume | MW

653,000

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

Derivative, Nonmonetary Notional Amount, Volume | MW

119,200

Natural Gas Liquids [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member]

Derivative, Nonmonetary Notional Amount, Volume | MB_bls

6,934

8,493

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

Derivative, Nonmonetary Notional Amount, Volume | MB_bls

3,547

3,349

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

Derivative, Nonmonetary Notional Amount, Volume | barrels

795

3,672

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

Derivative Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) - Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member] - Forward-Starting Swaps [Member] - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

July 2022 [Member]

Description of Interest Rate Derivative Activities

^[1],[2]

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

Derivative, Notional Amount

^[2]

$ 0

$ 400

July 2023

Description of Interest Rate Derivative Activities

^[1],[2],[3]

Forward-starting to pay a fixed rate of 3.845% and receive a floating rate

Derivative, Notional Amount

^[2],[3]

$ 0

200

July 2024

Description of Interest Rate Derivative Activities

^[1],[2]

Forward-starting to pay a fixed rate of 3.512% and receive a floating rate

Derivative, Notional Amount

^[2]

$ 400

$ 200

[1]	Floating rates are based on either SOFR or three-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]	This interest rate swap was terminated and settled in 2022.

Derivative Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Asset Derivatives	$ 688	$ 272
Liability Derivatives	(549)	(598)
Designated as Hedging Instrument [Member]
Asset Derivatives	87	46
Liability Derivatives	(7)	(3)
Not Designated as Hedging Instrument [Member]
Asset Derivatives	601	226
Liability Derivatives	(542)	(595)
Broker cleared derivative contracts [Member]
Asset Derivatives	593	219
Liability Derivatives	(418)	(159)
Commodity Derivatives [Member] \| Not Designated as Hedging Instrument [Member]
Asset Derivatives	95	53
Liability Derivatives	(108)	(52)
Commodity Derivatives (Margin Deposits) [Member] \| Designated as Hedging Instrument [Member]
Asset Derivatives	87	46
Liability Derivatives	(7)	(3)
Commodity Derivatives (Margin Deposits) [Member] \| Not Designated as Hedging Instrument [Member]
Asset Derivatives	506	173
Liability Derivatives	(411)	(156)
Interest Rate Derivatives [Member] \| Not Designated as Hedging Instrument [Member]
Asset Derivatives	0	0
Liability Derivatives	$ (23)	$ (387)

Derivative Assets And Liabilities Derivative Assets and Lianilities (Offsetting Agreements Netting Table) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Asset Derivatives	$ 688	$ 272
Derivative Liabilities	(549)	(598)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(85)	(43)
Derivative Liability, Fair Value, Amount Offset Against Collateral	85	43
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(359)	(150)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	359	150
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	244	79
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	105	405
Without offsetting agreements [Member]
Asset Derivatives	0	0
Derivative Liabilities	(23)	(387)
OTC Contracts [Member]
Asset Derivatives	95	53
Derivative Liabilities	(108)	(52)
Broker cleared derivative contracts [Member]
Asset Derivatives	593	219
Derivative Liabilities	$ (418)	$ (159)

Derivative Assets And Liabilities (Derivative Amount Of Gain (Loss) Recognized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 417	$ (86)	$ (229)
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments	293	61	(203)
Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 83	(6)	8
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Cost of products sold
Non Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 41	$ (141)	$ (34)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Cost of products sold

Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Retirement Benefits [Line Items]
Defined Contribution Plan, Cost	$ 79	$ 65	$ 35
Pension Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 5
Large Cap US Equitiies	100.00%	100.00%
Other Postretirement Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 1
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%

Retirement Benefits (Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Change in benefit obligation:
Settlements	$ 0	$ 0
Defined Benefit Plan, Plan Assets, Divestiture	0	0
Defined Benefit Plan, Benefit Obligation, Divestiture	0	0
Change in plan assets:
Settlements	0	0
Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	50	55
Service cost	0	0
Interest cost	2	2
Defined Benefit Plan, Benefit Obligation		50
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	44
Defined Benefit Plan, Plan Assets, Amount	20	44
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position		(6)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		0
Other Postretirement Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	195	208
Service cost	1	1
Interest cost	4	4
Benefits paid, net	(14)	(16)
Actuarial gain and other	(38)	(2)
Defined Benefit Plan, Benefit Obligation	148	195
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	311	291
Return on plan assets and other	(41)	26
Employer contributions	3	10
Benefits paid, net	(14)	(16)
Defined Benefit Plan, Plan Assets, Amount	259	311
Amount underfunded (overfunded) at end of period	(111)	(116)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	127	138
Current liabilities	(2)	(2)
Non-current liabilities	(14)	(20)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	111	116
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	5	(27)
Prior service cost (credit)	(3)	19
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	2	(8)
Funded Plans [Member] \| Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	50
Interest cost	1	1
Benefits paid, net	(1)	(2)
Actuarial gain and other	(8)	(2)
Settlements	0	(2)
Defined Benefit Plan, Plan Assets, Divestiture	(20)	0
Defined Benefit Plan, Benefit Obligation, Divestiture	(20)	0
Defined Benefit Plan, Benefit Obligation	22	50
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	44	45
Return on plan assets and other	(4)	2
Employer contributions	1	1
Benefits paid, net	(1)	(2)
Settlements	0	(2)
Defined Benefit Plan, Plan Assets, Amount	20	44
Amount underfunded (overfunded) at end of period	2	6
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Current liabilities	0	0
Non-current liabilities	(2)	(6)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	(2)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	0	0
Prior service cost (credit)	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	0
Unfunded Plans [Member]
Change in benefit obligation:
Settlements	0	0
Defined Benefit Plan, Plan Assets, Divestiture	0	0
Defined Benefit Plan, Benefit Obligation, Divestiture	(2)	0
Change in plan assets:
Settlements	0	0
Unfunded Plans [Member] \| Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	26	31
Service cost	0	0
Interest cost	1	1
Benefits paid, net	(3)	(4)
Actuarial gain and other	(3)	(2)
Defined Benefit Plan, Benefit Obligation	19	26
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	0	0
Return on plan assets and other	0	0
Employer contributions	0	0
Benefits paid, net	0	0
Defined Benefit Plan, Plan Assets, Amount	0	0
Amount underfunded (overfunded) at end of period	19	26
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Current liabilities	(3)	(4)
Non-current liabilities	(16)	(22)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	(19)	(26)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	(2)	1
Prior service cost (credit)	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	$ (2)	$ 1

Retirement Benefits (Accumulated Benefit Obligation In Excess of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation		$ 50	$ 55
Fair value of plan assets	$ 20	44
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	148	195	208
Fair value of plan assets	259	311	291
Funded Plans [Member] \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	22	50
Accumulated benefit obligation	22	50
Fair value of plan assets	20	44	45
Unfunded Plans [Member] \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	19	26
Accumulated benefit obligation	19	26	31
Fair value of plan assets	$ 0	$ 0	$ 0

- Definition

Amount of asset segregated and restricted to provide benefit under defined benefit plan. Asset includes, but is not limited to, stock, bond, other investment, earning from investment, and contribution by employer and employee.

+ References + Details

Retirement Benefits (Net Periodic Benefit Costs Schedule) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 0	$ 0
Interest cost	2	2
Expected return on plan assets	(2)	(2)
Prior service cost amortization	0	0
Net periodic benefit cost	0	0
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	1
Interest cost	4	4
Expected return on plan assets	(11)	(11)
Prior service cost amortization	19	19
Net periodic benefit cost	$ 13	$ 13

Retirement Benefits (Benefit Assumptions) (Details)	12 Months Ended
Retirement Benefits (Benefit Assumptions) (Details)	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate	7.48%	7.14%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.18%	4.95%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.00%	2.79%
Discount rate	2.70%	2.57%
Tax exempt accounts	7.00%	4.76%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.46%	2.24%
Discount rate	2.58%	2.18%
Tax exempt accounts	7.00%	7.00%
Taxable accounts	4.75%	4.75%

Retirement Benefits (Fair Value of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Accumulated benefit obligation	$ 148	$ 195	$ 208
Fair value of plan assets	259	311	291
Pension Benefits
Fair Value of Plan Assets [Line Items]
Accumulated benefit obligation		50	55
Fair value of plan assets	20	44
Cash and Cash Equivalents [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	19	22
Cash and Cash Equivalents [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	2	1
Mutual Fund [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	146	175
Mutual Fund [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	18	24
Fixed Income Securities [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	94	114
Fixed Income Securities [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets		19
Level 1 [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	165	197
Level 1 [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	20	25
Level 1 [Member] \| Cash and Cash Equivalents [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	19	22
Level 1 [Member] \| Cash and Cash Equivalents [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	2	1
Level 1 [Member] \| Mutual Fund [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	146	175
Level 1 [Member] \| Mutual Fund [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	18	24
Level 1 [Member] \| Fixed Income Securities [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 1 [Member] \| Fixed Income Securities [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets		0
Level 2 [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	94	114
Level 2 [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	19
Level 2 [Member] \| Cash and Cash Equivalents [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] \| Cash and Cash Equivalents [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] \| Mutual Fund [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] \| Mutual Fund [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 2 [Member] \| Fixed Income Securities [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	94	114
Level 2 [Member] \| Fixed Income Securities [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets		19
Level 3 [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] \| Cash and Cash Equivalents [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] \| Cash and Cash Equivalents [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] \| Mutual Fund [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] \| Mutual Fund [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] \| Fixed Income Securities [Member] \| Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	0
Level 3 [Member] \| Fixed Income Securities [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets		0
Funded Plans [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Projected benefit obligation	22	50
Accumulated benefit obligation	22	50
Fair value of plan assets	20	44	45
Unfunded Plans [Member] \| Pension Benefits
Fair Value of Plan Assets [Line Items]
Projected benefit obligation	19	26
Accumulated benefit obligation	19	26	31
Fair value of plan assets	$ 0	$ 0	$ 0

Retirement Benefits (Benefit Payments) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2023	$ 16
2024	15
2025	15
2026	14
2027	13
2028 – 2032	55
Defined Benefit Plan, Funded Plan \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2023	1
2024	1
2025	1
2026	1
2027	1
2028 – 2032	7
Defined Benefit Plan, Unfunded Plan \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2023	4
2024	3
2025	3
2026	2
2027	2
2028 – 2032	$ 6

Reportable Segments Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenue from External Customer [Line Items]
Revenues	$ (89,876)	$ (67,417)	$ (38,954)
Intersegment Eliminations [Member]
Revenue from External Customer [Line Items]
Revenues	(18,941)	(13,423)	(5,884)
Investment in USAC
Revenue from External Customer [Line Items]
Revenues	(705)	(633)	(667)
All Other
Revenue from External Customer [Line Items]
Revenues	(3,574)	(3,476)	(1,838)
Crude Oil Transportation and Services
Revenue from External Customer [Line Items]
Revenues	(25,982)	(17,446)	(11,679)
NGL and Refined Products Transportation and Services
Revenue from External Customer [Line Items]
Revenues	(25,657)	(19,961)	(10,513)
Midstream
Revenue from External Customer [Line Items]
Revenues	(17,101)	(11,316)	(5,026)
Interstate Transportation and Storage
Revenue from External Customer [Line Items]
Revenues	(2,251)	(1,841)	(1,861)
Intrastate Transportation and Storage
Revenue from External Customer [Line Items]
Revenues	(7,818)	(8,571)	(2,544)
Investment in Sunoco LP
Revenue from External Customer [Line Items]
Revenues	(25,729)	(17,596)	(10,710)
Intersegment [Member] \| Investment in USAC
Revenue from External Customer [Line Items]
Revenues	(16)	(12)	(12)
Intersegment [Member] \| All Other
Revenue from External Customer [Line Items]
Revenues	(711)	(411)	(464)
Intersegment [Member] \| Crude Oil Transportation and Services
Revenue from External Customer [Line Items]
Revenues	(2)	(4)	(5)
Intersegment [Member] \| NGL and Refined Products Transportation and Services
Revenue from External Customer [Line Items]
Revenues	(4,243)	(2,972)	(2,012)
Intersegment [Member] \| Midstream
Revenue from External Customer [Line Items]
Revenues	(12,987)	(8,696)	(3,082)
Intersegment [Member] \| Interstate Transportation and Storage
Revenue from External Customer [Line Items]
Revenues	(66)	(39)	(20)
Intersegment [Member] \| Intrastate Transportation and Storage
Revenue from External Customer [Line Items]
Revenues	(864)	(1,264)	(232)
Intersegment [Member] \| Investment in Sunoco LP
Revenue from External Customer [Line Items]
Revenues	(52)	(25)	(57)
External Customers [Member] \| Investment in USAC
Revenue from External Customer [Line Items]
Revenues	(689)	(621)	(655)
External Customers [Member] \| All Other
Revenue from External Customer [Line Items]
Revenues	(2,863)	(3,065)	(1,374)
External Customers [Member] \| Crude Oil Transportation and Services
Revenue from External Customer [Line Items]
Revenues	(25,980)	(17,442)	(11,674)
External Customers [Member] \| NGL and Refined Products Transportation and Services
Revenue from External Customer [Line Items]
Revenues	(21,414)	(16,989)	(8,501)
External Customers [Member] \| Midstream
Revenue from External Customer [Line Items]
Revenues	(4,114)	(2,620)	(1,944)
External Customers [Member] \| Interstate Transportation and Storage
Revenue from External Customer [Line Items]
Revenues	(2,185)	(1,802)	(1,841)
External Customers [Member] \| Intrastate Transportation and Storage
Revenue from External Customer [Line Items]
Revenues	(6,954)	(7,307)	(2,312)
External Customers [Member] \| Investment in Sunoco LP
Revenue from External Customer [Line Items]
Revenues	$ (25,677)	$ (17,571)	$ (10,653)

Reportable Segments (Operating Segments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cost of Goods and Services Sold	$ (72,232)	$ (50,395)	$ (25,487)
Depreciation, depletion and amortization	4,164	3,817	3,678
Equity in earnings of unconsolidated affiliates	257	246	119
Intersegment Eliminations [Member]
Cost of Goods and Services Sold	(18,837)	(13,360)	(5,829)
Intrastate Transportation and Storage
Cost of Goods and Services Sold	(6,000)	(4,769)	(1,478)
Depreciation, depletion and amortization	209	191	185
Equity in earnings of unconsolidated affiliates	17	20	18
Investment in Sunoco LP
Cost of Goods and Services Sold	(24,350)	(16,246)	(9,654)
Depreciation, depletion and amortization	193	177	189
Interstate Transportation and Storage
Cost of Goods and Services Sold	(25)	(11)	0
Depreciation, depletion and amortization	513	457	411
Equity in earnings of unconsolidated affiliates	175	140	17
Midstream
Cost of Goods and Services Sold	(12,682)	(8,569)	(2,598)
Depreciation, depletion and amortization	1,351	1,190	1,140
Equity in earnings of unconsolidated affiliates	19	24	24
NGL and Refined Products Transportation and Services
Cost of Goods and Services Sold	(21,656)	(16,248)	(7,139)
Depreciation, depletion and amortization	865	778	667
Equity in earnings of unconsolidated affiliates	42	51	60
Crude Oil Transportation and Services
Cost of Goods and Services Sold	(22,917)	(14,759)	(8,838)
Depreciation, depletion and amortization	663	588	640
Equity in earnings of unconsolidated affiliates	0	10	(2)
All Other
Cost of Goods and Services Sold	(3,328)	(3,068)	(1,527)
Depreciation, depletion and amortization	133	197	207
Equity in earnings of unconsolidated affiliates	4	1	2
Investment in USAC
Cost of Goods and Services Sold	(111)	(85)	(82)
Depreciation, depletion and amortization	$ 237	$ 239	$ 239

Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 13,093	$ 13,046	$ 10,531
Depreciation, depletion and amortization	4,164	3,817	3,678
Interest expense, net of interest capitalized	2,306	2,267	2,327
Impairment losses and other	386	21	2,880
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments	293	61	(203)
Non-cash compensation expense	115	111	121
Non-cash compensation expense	42	162	(71)
Losses on extinguishments of debt	0	38	75
Inventory valuation adjustments	(5)	(190)	82
Impairment of investment in unconsolidated affiliates	0	0	129
Impairment of investments in unconsolidated affiliates	565	523	628
Equity in earnings of unconsolidated affiliates	(257)	(246)	(119)
Other, net	82	57	79
Income tax expense (benefit) from continuing operations	(204)	(184)	(237)
NET INCOME	5,868	6,687	140
Intrastate Transportation and Storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	1,396	3,483	863
Depreciation, depletion and amortization	209	191	185
Equity in earnings of unconsolidated affiliates	(17)	(20)	(18)
Investment in Sunoco LP
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	919	754	739
Depreciation, depletion and amortization	193	177	189
Investment in USAC
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	426	398	414
Depreciation, depletion and amortization	237	239	239
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	177	177	105
Interstate Transportation and Storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	1,753	1,515	1,680
Depreciation, depletion and amortization	513	457	411
Impairment losses and other			58
Equity in earnings of unconsolidated affiliates	(175)	(140)	(17)
Midstream
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	3,210	1,868	1,670
Depreciation, depletion and amortization	1,351	1,190	1,140
Equity in earnings of unconsolidated affiliates	(19)	(24)	(24)
NGL and Refined Products Transportation and Services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	3,025	2,828	2,802
Depreciation, depletion and amortization	865	778	667
Equity in earnings of unconsolidated affiliates	(42)	(51)	(60)
Crude Oil Transportation and Services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	2,187	2,023	2,258
Depreciation, depletion and amortization	663	588	640
Equity in earnings of unconsolidated affiliates	$ 0	$ (10)	$ 2

Reportable Segments (Assets Segments) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Assets	$ 105,643	$ 105,963	$ 95,144
Intrastate Transportation and Storage
Assets	6,609	7,322	6,308
Interstate Transportation and Storage
Assets	17,979	17,774	17,582
Midstream
Assets	21,851	21,960	18,583
NGL and Refined Products Transportation and Services
Assets	27,903	28,160	21,423
Crude Oil Transportation and Services
Assets	19,200	19,649	17,960
Investment in Sunoco LP
Assets	6,830	5,815	5,267
Investment in USAC
Assets	2,666	2,768	2,949
Corporate and Other [Member]
Assets	$ 2,605	$ 2,515	$ 5,072

- Definition

Sum of the carrying amounts as of the balance sheet date of all assets that are recognized. Assets are probable future economic benefits obtained or controlled by an entity as a result of past transactions or events.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 210
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-03(11))
-URI https://asc.fasb.org/extlink&oid=126897435&loc=d3e534808-122878

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 852
-SubTopic 10
-Section 55
-Paragraph 10
-URI https://asc.fasb.org/extlink&oid=84165509&loc=d3e56426-112766

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(A))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8736-108599

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iv))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 210
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-03(a)(12))
-URI https://asc.fasb.org/extlink&oid=126734703&loc=d3e572229-122910

Reference 7: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 852
-SubTopic 10
-Section 50
-Paragraph 7
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=124433192&loc=SL2890621-112765

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(i))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 9: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(ii))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(5))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iii)(A))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(i))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(ii))
-URI https://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 14: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iii))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442526-122756

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-Subparagraph (f)
-URI https://asc.fasb.org/extlink&oid=123596393&loc=d3e14064-108612

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(B))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (bb)
-URI https://asc.fasb.org/extlink&oid=123419778&loc=d3e5710-111685

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(5))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8933-108599

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 45
-Paragraph 25
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=116870748&loc=SL6758485-165988

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iv))
-URI https://asc.fasb.org/extlink&oid=126975872&loc=SL124442552-122756

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(18))
-URI https://asc.fasb.org/extlink&oid=120391452&loc=d3e13212-122682

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=114001798&loc=d3e33918-111571

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=126901519&loc=d3e8906-108599

+ Details

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, 2022

Dec. 31, 2021

Dec. 31, 2020

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

$ 3,026

$ 2,158

$ 3,759

Investment in Sunoco LP

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

186

174

124

Intrastate Transportation and Storage

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

179

Interstate Transportation and Storage

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

644

159

150

Midstream

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

1,004

484

487

NGL and Refined Products Transportation and Services

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

507

751

2,403

Crude Oil Transportation and Services

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

246

343

291

Investment in USAC

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

169

119

All Other

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

$ 91

$ 135

$ 136

[1]	Amounts are presented on the accrual basis, net of contributions in aid of constructions costs. Amounts exclude acquisitions and include only the Partnership’s proportionate share of capital expenditures related to joint ventures.

Reportable Segments (Advances to and investments in affiliates) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	$ 2,893	$ 2,947	$ 3,060
Intrastate Transportation and Storage
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	139	110	89
Interstate Transportation and Storage
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	2,201	2,209	2,278
Midstream
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	54	101	110
NGL and Refined Products Transportation and Services
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	446	476	509
Crude Oil Transportation and Services
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	0	0	22
All Other
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	$ 53	$ 51	$ 52