Energy Transfer (ET) 10-K 14 Feb 25 2024 FY Annual report Financial data

Cover Page Cover Page

Cover Page Cover Page - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Feb. 07, 2025	Jun. 30, 2024
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
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			$ 49,100
Entity Common Stock, Shares Outstanding		3,431,214,964
Documents Incorporated by Reference	None
Entity Central Index Key	0001276187
Document Fiscal Year Focus	2024
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, 2024
Current Fiscal Year End Date	--12-31
Auditor Firm ID	248
Auditor Location	Dallas, Texas
Auditor Name	GRANT THORNTON LLP
Document Financial Statement Error Correction [Flag]	false
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
ETprI
Cover [Abstract]
Title of 12(b) Security	9.250% Series I Fixed Rate Perpetual Preferred Units
Trading Symbol	ETprI
Security Exchange Name	NYSE
Document Information [Line Items]
Title of 12(b) Security	9.250% Series I Fixed Rate Perpetual Preferred Units
Trading Symbol	ETprI
Security Exchange Name	NYSE

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2024	Dec. 31, 2023
ASSETS
Cash and cash equivalents		$ 312	$ 161
Inventories		3,070	2,478
Income taxes receivable		56	67
Derivative assets		9	66
Other current assets		477	513
Total current assets		14,202	12,433
Property, plant and equipment		129,242	114,932	[1]
Accumulated depreciation and depletion		(34,030)	(29,581)	[1]
Property, Plant and Equipment, Net		95,212	85,351	[1]
Investments in unconsolidated affiliates	[2]	3,266	3,097
Lease right-of-use assets, net		809	826
Other non-current assets, net		2,017	1,733
Intangible assets, net		5,971	6,239
Goodwill		3,903	4,019
Total assets		125,380	113,698
LIABILITIES AND EQUITY
Derivative liabilities		15	8
Operating lease current liabilities		67	56
Accrued and other current liabilities		4,241	3,521
Current maturities of long-term debt		8	1,008
Total current liabilities		12,656	11,277
Long-term debt, less current maturities		59,752	51,380
Non-current derivative liabilities		0	4
Non-current operating lease liabilities		730	778
Deferred income taxes		4,190	3,931
Other non-current liabilities		1,618	1,611
Commitments and contingencies
Redeemable noncontrolling interests		417	778
Limited Partners:
Preferred Unitholders (44,898,959 and 113,648,967 units authorized, issued and outstanding as of December 31, 2024 and 2023, respectively)		3,852	6,459
Common Unitholders (3,431,088,022 and 3,367,525,806 units authorized, issued and outstanding as of December 31, 2024 and 2023, respectively)		31,195	30,197
General Partner		(2)	(2)
Accumulated other comprehensive income		73	28
Total partners’ capital		35,118	36,682
Noncontrolling interests		10,899	7,257
Total equity		46,017	43,939
Total liabilities and equity		125,380	113,698
Related Party
ASSETS
Accounts receivable from related companies		87	101
LIABILITIES AND EQUITY
Accounts payable		19	21
Nonrelated Party
ASSETS
Accounts receivable, net		10,191	9,047
LIABILITIES AND EQUITY
Accounts payable		$ 8,306	$ 6,663
[1] Certain components of property, plant and equipment were reclassified in the current year. The balances as of December 31, 2023 reflected above have been adjusted to conform to the current year presentation. These changes did not impact total property, plant and equipment. Amounts reflected above exclude Sunoco LP’s investments in the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Consolidated Balance Sheets Bal

Consolidated Balance Sheets Balance Sheet (Paranthetical) - shares	Dec. 31, 2024	Dec. 31, 2023
Class of Stock [Line Items]
Authorized	3,431,088,022	3,367,525,806
Issued	3,431,088,022	3,367,525,806
Outstanding	3,431,088,022	3,367,525,806
Preferred Units, Authorized	44,898,959	113,648,967
Preferred Units, Issued	44,898,959	113,648,967
Preferred Units, Outstanding	44,898,959	113,648,967

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
REVENUES:
Total revenues		$ 82,671	$ 78,586	$ 89,876
COSTS AND EXPENSES:
Cost of products sold		61,975	60,541	72,232
Operating expenses		5,164	4,368	4,338
Depreciation, depletion and amortization		5,165	4,385	4,164
Selling, general and administrative		1,177	985	1,018
Impairment losses and other		52	12	386
Total costs and expenses		73,533	70,291	82,138
OPERATING INCOME		9,138	8,295	7,738
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(3,125)	(2,578)	(2,306)
Equity in earnings of unconsolidated affiliates	[1]	379	383	257
Gains (losses) on extinguishments of debt		(12)	2	0
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments		6	36	293
Gain (Loss) from Litigation Settlement		0	(627)	0
Gain (Loss) on Disposition of Assets		586	0	0
Other, net		134	86	90
Income (Loss), Including Portion Attributable to Noncontrolling Interest, before Tax, Total		7,106	5,597	6,072
Income tax expense		541	303	204
NET INCOME		6,565	5,294	5,868
Less: Net income attributable to noncontrolling interests		1,692	1,299	1,061
Less: Net income attributable to redeemable noncontrolling interests		59	60	51
NET INCOME ATTRIBUTABLE TO PARTNERS		4,814	3,935	4,756
General Partner’s interest in net income		4	3	4
Preferred Unitholders’ interest in net income		362	463	422
Preferred Stock Redemption Premium		54	0	0
Limited Partners’ interest in net income		$ 4,394	$ 3,469	$ 4,330
NET INCOME PER COMMON UNIT:
Basic		$ 1.29	$ 1.10	$ 1.40
Diluted		$ 1.28	$ 1.09	$ 1.40
Refined product sales
REVENUES:
Total revenues		$ 22,051	$ 23,389	$ 26,020
Crude sales
REVENUES:
Total revenues		25,368	23,492	23,473
Natural gas sales
REVENUES:
Total revenues		2,737	3,259	8,535
Gathering, transportation and other fees
REVENUES:
Total revenues		12,027	11,428	10,907
NGL sales
REVENUES:
Total revenues		19,105	15,957	20,114
Other
REVENUES:
Total revenues		$ 1,383	$ 1,061	$ 827
[1] Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 6,565	$ 5,294	$ 5,868
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	7	4	(10)
Actuarial gain (loss) relating to pension and other postretirement benefits	39	13	(12)
Foreign currency translation adjustment	(1)	(6)	(6)
Change in other comprehensive income from unconsolidated affiliates	0	1	24
Other comprehensive income (loss), net of tax, total	45	12	(4)
Comprehensive income	6,610	5,306	5,864
Less: Comprehensive income attributable to noncontrolling interests	1,692	1,299	1,055
Less: Comprehensive income attributable to redeemable noncontrolling interests	59	60	51
Comprehensive income attributable to partners	$ 4,859	$ 3,947	$ 4,758

Consolidated Statement Of Equit

Consolidated Statement Of Equity - USD ($) $ in Millions	Total	Nustar	General Partner	General Partner Nustar	Accumulated Other Comprehensive Income	Accumulated Other Comprehensive Income Nustar	Common Unitholders	Common Unitholders Nustar	Non- controlling Interests	Non- controlling Interests Nustar	Preferred Unitholders	Preferred Unitholders Nustar	Lotus Midstream Acquisition	Lotus Midstream Acquisition General Partner	Lotus Midstream Acquisition Accumulated Other Comprehensive Income	Lotus Midstream Acquisition Common Unitholders	Lotus Midstream Acquisition Non- controlling Interests	Lotus Midstream Acquisition Preferred Unitholders	Crestwood Acquisition	Crestwood Acquisition General Partner	Crestwood Acquisition Accumulated Other Comprehensive Income	Crestwood Acquisition Common Unitholders	Crestwood Acquisition Non- controlling Interests	Crestwood Acquisition Preferred Unitholders	WTG Midstream	WTG Midstream General Partner	WTG Midstream Accumulated Other Comprehensive Income	WTG Midstream Common Unitholders	WTG Midstream Non- controlling Interests	WTG Midstream Preferred Unitholders	Nustar Acquisition	Nustar Acquisition General Partner	Nustar Acquisition Accumulated Other Comprehensive Income	Nustar Acquisition Common Unitholders	Nustar Acquisition Non- controlling Interests	Nustar Acquisition Preferred Unitholders
Balance at Dec. 31, 2021	$ 39,345		$ (4)		$ 23		$ 25,230		$ 8,045		$ 6,051
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(3,047)		(2)		0		(2,623)		0		(422)
Distributions to noncontrolling interests	(1,547)		0		0		0		(1,547)		0
Capital contributions from noncontrolling interests	405		0		0		0		405		0
Noncontrolling Interest, Decrease from Deconsolidation	(346)		0		(9)		0		(337)		0
Other, net	36		0		0		23		13		0
Other comprehensive income, net of tax	(4)		0		2		0		(6)		0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	5,817		4		0		4,330		1,061		422
Balance at Dec. 31, 2022	40,659		(2)		16		26,960		7,634		6,051
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(4,248)		(3)		0		(3,777)		0		(468)
Distributions to noncontrolling interests	(1,691)		0		0		0		(1,691)		0
Capital contributions from noncontrolling interests	3		0		0		0		3		0
Other, net	30		0		0		18		12		0
Partners' Capital Account, Acquisitions													$ 574	$ 0	$ 0	$ 574	$ 0	$ 0	$ 3,366	$ 0	$ 0	$ 2,953	$ 0	$ 413
Other comprehensive income, net of tax	12		0		12		0		0		0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	5,234		3		0		3,469		1,299		463
Balance at Dec. 31, 2023	43,939		(2)		28		30,197		7,257		6,459
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(4,623)		(4)		0		(4,241)		0		(378)
Distributions to noncontrolling interests	(1,780)		0		0		0		(1,780)		0
Capital contributions from noncontrolling interests	638		0		0		0		638		0
Other, net	(64)		0		0		(42)		(76)		54
Partners' Capital Account, Acquisitions																									$ 833	$ 0	$ 0	$ 833	$ 0	$ 0	$ 3,651	$ 0	$ 0	$ 0	$ 3,651	$ 0
Common units repurchased	(2,645)	$ (784)	0	$ 0	0	$ 0	0	$ 0	0	$ (784)	(2,645)	$ 0
Partners' Capital Account, Exchanges and Conversions	301		0		0		0		301		0
Other comprehensive income, net of tax	45		0		45		0		0		0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	6,506		4		0		4,448		1,692		362
Balance at Dec. 31, 2024	$ 46,017		$ (2)		$ 73		$ 31,195		$ 10,899		$ 3,852

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME		$ 6,565	$ 5,294	$ 5,868
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization		5,165	4,385	4,164
Deferred Income Tax Expense (Benefit)		276	203	187
Inventory valuation adjustments		86	114	(5)
Non-cash compensation expense		151	130	115
Impairment losses and other		52	12	386
(Gains) losses on extinguishments of debt		12	(2)	0
Distributions on unvested awards		59	68	73
Proceeds from Equity Method Investment, Distribution		356	353	232
Income (Loss) from Equity Method Investments	[1]	(379)	(383)	(257)
Gain (Loss) on Disposition of Assets		(586)	0	0
Other Noncash Income (Expense)		(63)	32	64
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures		(196)	(451)	(1,502)
Net cash provided by operating activities		11,506	9,555	9,051
Cash Acquired from Acquisition		27	0	0
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received		(250)	(111)	(1,141)
Capital expenditures, excluding allowance for equity funds used during construction		(4,164)	(3,134)	(3,381)
Contributions in aid of construction costs		73	40	56
Contributions to unconsolidated affiliates		(206)	(6)	0
Distributions from unconsolidated affiliates in excess of cumulative earnings		75	63	62
Proceeds from Sale of Equity Method Investments		0	0	302
Other, net		12	3	2
Net cash used in investing activities		(5,904)	(4,325)	(4,022)
FINANCING ACTIVITIES:
Proceeds from borrowings		34,150	32,130	28,838
Repayments of debt		(29,409)	(31,416)	(29,681)
Repayments of Senior Debt		(749)	0	0
Payments for Repurchase of Preferred Stock and Preference Stock			0	0
Distributions to partners		(4,623)	(4,248)	(3,047)
Distributions to noncontrolling interests		(1,780)	(1,691)	(1,547)
Distributions to redeemable noncontrolling interests		67	59	49
Debt issuance costs		(147)	(45)	(27)
Capital contributions from noncontrolling interests		2	0	0
Net cash used in financing activities		(5,451)	(5,326)	(5,108)
Increase (decrease) in cash and cash equivalents		151	(96)	(79)
Cash and cash equivalents, beginning of period		161	257	336
Cash and cash equivalents, end of period		312	161	257
Proceeds from Contributions from Affiliates		638	3	405
Nustar
FINANCING ACTIVITIES:
Payments for Repurchase of Preferred Stock and Preference Stock		(784)	0	0
Other Assets
INVESTING ACTIVITIES:
Proceeds from sales of other assets		24	38	78
Sunoco LP West Texas Assets
INVESTING ACTIVITIES:
Proceeds from sales of other assets		987	0	0
Crestwood Niobrara LLC
FINANCING ACTIVITIES:
Payments for Repurchase of Preferred Stock and Preference Stock		(37)	0	0
Series A, Series C, Series D and Series E preferred units
FINANCING ACTIVITIES:
Payments for Repurchase of Preferred Stock and Preference Stock		(2,645)
Crestwood Acquisition
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received		0	(288)	0
Lotus Midstream Acquisition
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received		0	(930)	0
WTG Midstream
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received		(2,174)	0	0
Sunoco LP acquisitions of terminals
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received		(224)	0	0
Edwards Lime Gathering, LLC
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received		$ (84)	$ 0	$ 0
[1] Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Operations And Organization

Operations And Organization	12 Months Ended
	Dec. 31, 2024
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”). Our consolidated 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 also 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 also engaged in midstream services, focusing on providing gathering, processing, compression, treating and transportation of natural gas in some of the most prolific natural gas producing regions in the United States, including the Permian, Anadarko, Arkoma, Hugoton, Powder River and Williston basins, as well as the Eagle Ford, Haynesville, Barnett, Marcellus and Utica shales. The Partnership’s operations also include crude oil, NGL and refined products transportation, terminalling services, and acquisition and marketing activities, as well as NGL storage and fractionation and LNG regasification. The Partnership owns a controlling interest in Sunoco LP which is engaged in energy infrastructure and distribution of motor fuels in over 40 U.S. states, Puerto Rico, Europe and Mexico. Sunoco LP’s midstream operations include an extensive network of over 14,000 miles of pipeline and over 100 terminals. Sunoco LP’s fuel distribution operations serve approximately 7,400 Sunoco and partner branded locations and additional independent dealers and commercial customers. As of December 31, 2024, 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, 2024, 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 have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all subsidiaries in which we have a controlling financial interest and limited partnerships in which we control 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. The operations of certain pipelines and terminals in which we own an undivided interest are proportionately consolidated in the accompanying consolidated financial statements.

Estimates, Significant Accounti

Estimates, Significant Accounting Policies and Balance Sheet Detail	12 Months Ended
	Dec. 31, 2024
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 oil and 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 much of our business 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 and divestitures, included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2024 2023 2022 Accounts receivable $ (775) $ (171) $ (863) Accounts receivable from related companies 15 (5) 23 Inventories (735) 35 (361) Other current assets 82 221 (326) Other non-current assets, net (166) (125) 146 Accounts payable 1,315 (501) 25 Accounts payable to related companies (35) (38) 6 Accrued and other current liabilities 166 209 131 Other non-current liabilities (123) (33) 66 Derivative assets and liabilities, net 60 (43) (349) Net change in operating assets and liabilities, net of effects of acquisitions and divestitures $ (196) $ (451) $ (1,502) Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2024 2023 2022 NON-CASH INVESTING AND FINANCING ACTIVITIES: Accrued capital expenditures $ 688 $ 442 $ 575 Lease assets obtained in exchange for new lease liabilities 7 23 42 Units issued in connection with the WTG Midstream acquisition (1) 833 — — Units issued in connection with the Crestwood acquisition (1) — 3,366 — Units issued in connection with the Lotus Midstream acquisition (1) — 574 — USAC exercise and conversion of preferred units into common units 301 — — USAC government securities transferred in connection with the legal defeasance of USAC senior notes due 2026 749 — — Legal defeasance of USAC senior notes due 2026 725 — — Sunoco LP common units (noncontrolling interest) issued in connection with the NuStar acquisition (1) 2,850 — — SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 2,884 $ 2,298 $ 2,167 Cash paid for income taxes, net of refunds (excluding $47 million of federal tax credits purchased from non-governmental third parties by Sunoco LP in 2024) 206 103 54 (1) See Note 3 for additional information. Accounts Receivable, net 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, 2024 and 2023, Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $316 million and $230 million, respectively. For the years ended December 31, 2024, 2023 and 2022, 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, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory adjustments of $86 million and $114 million, respectively, which decreased net income. For the year ended December 31, 2022 the Partnership’s cost of products sold included favorable inventory adjustments of $5 million, which increased net income. The Partnership’s inventories consisted of the following: December 31, 2024 2023 Natural gas, NGLs and refined products $ 1,989 $ 1,658 Crude oil 400 258 Spare parts and other 681 562 Total inventories $ 3,070 $ 2,478 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, 2024 2023 Deposits paid to vendors $ 150 $ 205 Prepaid expenses and other 327 308 Total other current assets $ 477 $ 513 Property, Plant and Equipment, net 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. For the years ended December 31 2024, 2023 and 2022, USAC recognized fixed asset impairments of $1 million, $12 million and $1 million, respectively, primarily related to its compression equipment as a result of its evaluation of the future deployment of 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 then current weighted average interest rate of our outstanding debt 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, 2024 2023 (1) Land and improvements $ 1,675 $ 1,529 Buildings and improvements (1 to 45 years) 4,688 4,392 Pipelines and equipment (5 to 83 years) 97,078 86,905 Product storage and related facilities (2 to 83 years) 7,869 8,381 Right of way (20 to 83 years) 9,239 7,379 Other (1 to 48 years) 4,060 4,031 Construction work-in-process 4,633 2,315 129,242 114,932 Less – Accumulated depreciation and depletion (34,030) (29,581) Property, plant and equipment, net $ 95,212 $ 85,351 (1) Certain components of property, plant and equipment were reclassified in the current year. The balances as of December 31, 2023 reflected above have been adjusted to conform to the current year presentation. These changes did not impact total property, plant and equipment. We recognized the following amounts for the periods presented: Years Ended December 31, 2024 2023 2022 Depreciation, depletion and amortization expense $ 4,701 $ 3,986 $ 3,774 Capitalized interest 120 77 112 Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2024 2023 Crude pipeline linefill and tank bottoms $ 743 $ 598 Regulatory assets 39 48 Pension assets 188 145 Deferred charges 151 148 Restricted funds 216 225 Other 680 569 Total other non-current assets, net $ 2,017 $ 1,733 Restricted funds primarily consist of investments held in our wholly owned captive insurance companies, including an immaterial amount of restricted cash. Intangible Assets, net 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, 2024 December 31, 2023 Gross Accumulated Gross Accumulated Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 9,304 $ (3,654) $ 9,098 $ (3,196) Patents (10 years) 48 (48) 48 (48) Trade names (20 years) 66 (48) 66 (44) Other (5 to 20 years) 12 (11) 12 (11) Total amortizable intangible assets 9,430 (3,761) 9,224 (3,299) Non-amortizable intangible assets: Trademarks 302 — 302 — Other — — 12 — Total non-amortizable intangible assets 302 — 314 — Total intangible assets $ 9,732 $ (3,761) $ 9,538 $ (3,299) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2024 2023 2022 Reported in depreciation, depletion and amortization expense $ 464 $ 399 $ 390 Estimated aggregate amortization of intangible assets for the next five years is as follows: Years Ending December 31: 2025 $ 440 2026 437 2027 419 2028 416 2029 408 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 Interstate Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services Investment in Sunoco LP Investment in USAC All Other Total Balance, December 31, 2022 $ — $ — $ — $ 693 $ 190 $ 1,601 $ — $ 82 $ 2,566 Acquired — — 601 191 663 — — — 1,455 Other — — — — — (2) — — (2) Balance, December 31, 2023 — — 601 884 853 1,599 — 82 4,019 Acquired — — — — — 16 — — 16 Disposed — — — — — (138) — — (138) Other — — 16 2 (12) — — — 6 Balance, December 31, 2024 $ — $ — $ 617 $ 886 $ 841 $ 1,477 $ — $ 82 $ 3,903 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 2024, $16 million of goodwill was recorded in connection with Sunoco LP’s acquisition of NuStar and $138 million of goodwill was removed in connection with Sunoco LP’s sale of 204 convenience stores to 7-Eleven Inc. During the fourth quarter of 2023, $1.46 billion of goodwill was recorded in connection with the acquisition of Crestwood, which is not expected to be deductible for tax purposes. 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. 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, 2024 and 2023, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $418 million and $410 million, respectively. For the years ended December 31, 2024, 2023 and 2022 aggregate accretion expense related to AROs was $11 million, $10 million and $4 million, respectively. Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2024 and 2023, 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 both December 31, 2024 and 2023, other non-current assets on the Partnership’s consolidated balance sheets included $31 million 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, 2024 2023 Interest payable $ 685 $ 637 Customer advances and deposits 360 240 Accrued capital expenditures 688 442 Accrued wages and benefits 422 406 Taxes payable other than income taxes 737 646 Exchanges payable 90 163 Deferred revenue 322 312 Other 937 675 Total accrued and other current liabilities $ 4,241 $ 3,521 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 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 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, 2024, 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, 2024 and 2023 based on inputs used to derive their fair values: Fair Value Total Fair Value Measurements at December 31, 2024 Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps FERC/NYMEX $ 6 $ 6 $ — Swing Swaps IFERC 4 4 — Fixed Swaps/Futures 10 10 — Power: Forwards 39 39 — Futures 10 10 — NGLs – Forwards/Swaps 166 166 — Refined Products – Futures 3 3 — Crude – Forwards/Swaps 25 25 — Total commodity derivatives 263 263 — Other non-current assets 212 212 — Total assets $ 475 $ 475 $ — Liabilities: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ (11) $ (11) $ — Swing Swaps IFERC (11) (11) — Fixed Swaps/Futures (9) (9) — Power: Forwards (38) (38) — Futures (10) (10) — NGLs – Forwards/Swaps (170) (170) — Refined Products – Futures (9) (9) — Crude – Forwards/Swaps (35) (35) — Total commodity derivatives (293) (293) — Total liabilities $ (293) $ (293) $ — Fair Value Total Fair Value Measurements at December 31, 2023 Level 1 Level 2 Assets: Interest rate derivatives $ 6 $ — $ 6 Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 24 24 — Swing Swaps IFERC 20 20 — Fixed Swaps/Futures 77 77 — Forward Physical Contracts 8 — 8 Power: Forwards 57 57 — Futures 8 8 — NGLs – Forwards/Swaps 336 336 — Refined Products – Futures 35 35 — Crude - Forwards/Swaps 45 45 — Total commodity derivatives 610 602 8 Other non-current assets 217 217 — Total assets $ 833 $ 819 $ 14 Liabilities: Interest rate derivatives $ (4) $ — $ (4) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (3) (3) Swing Swaps IFERC (2) (2) — Fixed Swaps/Futures (16) (16) — Options – Puts (2) (2) — Power: Forwards (56) (56) — Futures (8) (8) — NGL/Refined Products Option - Puts (1) (1) — NGL/Refined Products Option - Calls (1) (1) — NGLs – Forwards/Swaps (316) (316) — Refined Products – Futures (18) (18) — Crude - Forwards/Swaps (37) (37) — Total commodity derivatives (460) (460) — Total liabilities $ (464) $ (460) $ (4) 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, 2024 was $59.01 billion and $59.76 billion, respectively. As of December 31, 2023, the aggregate fair value and carrying amount of our debt obligations was $51.93 billion and $52.39 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. For our regulated businesses, contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received. For our non-regulated businesses, contributions in aid of construction costs are included in the transaction price of the underlying contract. 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, 2024, 2023 and 2022, excise taxes collected by Sunoco LP were $164 million, $274 million and $285 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, 2024, 2023 and 2022, the Partnership’s consolidated income statements reflect revenues from related parties of $603 million, $626 million and $391 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 acce

Acquisitions and Related Transa

Acquisitions and Related Transactions	12 Months Ended
	Dec. 31, 2024
Acquisitions and Dispositions [Abstract]
Acquisitions and Related Transactions	ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS : WTG Midstream Acquisition On July 15, 2024, Energy Transfer completed the acquisition of 100% of the membership interest in WTG Midstream. Consideration for the transaction was comprised of $2.28 billion in cash and approximately 50.8 million newly issued Energy Transfer common units, which had a fair value of approximately $833 million. The acquired assets include approximately 6,000 miles of complementary gas gathering pipelines that extended Energy Transfer’s network in the Midland Basin. Also, as part of the transaction, the Partnership added eight gas processing plants with a total capacity of approximately 1.3 Bcf/d, and two additional processing plants that were under construction at closing. Since closing the transaction, one of these 200 MMcf/d processing plants was placed into service. The WTG Midstream 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 a third-party 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 assumed allocation of the purchase price among the assets acquired and liabilities assumed: At July 15, 2024 Total current assets $ 334 Property, plant and equipment, net 3,109 Lease right-of-use assets, net 8 Intangible assets, net 20 Total assets 3,471 Total current liabilities 394 Non-current operating lease liabilities 5 Other non-current liabilities 20 Total liabilities 419 Total consideration 3,052 Cash received 45 Total consideration, net of cash received $ 3,007 Crestwood Acquisition On November 3, 2023, Energy Transfer acquired Crestwood, which owns gathering and processing assets located in the Williston, Delaware and Powder River basins. Under the terms of the merger agreement, holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood common unit held by them (the “Common Unit Merger Consideration”). Additionally, each outstanding Crestwood preferred unit was, at the election of the holder of such Crestwood preferred unit, either, (i) converted into a Series I Preferred Unit, which is a new preferred unit of Energy Transfer that has substantially similar terms, including with respect to economics and structural protections, as the Crestwood preferred units; (ii) redeemed in exchange for $9.857484 in cash plus accrued and unpaid distributions to the date of such redemption; or (iii) converted into a Crestwood common unit at the then-applicable conversion ratio of one Crestwood common unit for ten Crestwood preferred units, and such Crestwood common units then received the Common Unit Merger Consideration. In total, consideration issued in the transaction included approximately 216 million Energy Transfer common units, 41 million Series I Preferred Units and $300 million in cash. Concurrent with the closing of the Crestwood acquisition, the Partnership assumed $2.85 billion aggregate principal amount of Crestwood senior notes and terminated its revolving credit facility, which included the repayment of $613 million in outstanding borrowings. The Crestwood 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 assumed allocation of the purchase price among the assets acquired and liabilities assumed: At November 3, 2023 Total current assets $ 657 Property, plant and equipment, net 4,772 Investments in unconsolidated affiliates 95 Lease right-of-use assets, net 27 Other non-current assets 12 Intangible assets, net 1,139 Goodwill 1,455 Total assets 8,157 Total current liabilities 445 Long-term debt, less current maturities 3,461 Other non-current liabilities 322 Total liabilities 4,228 Noncontrolling interests 272 Total consideration 3,657 Cash received 12 Total consideration, net of cash received $ 3,645 Lotus Midstream Acquisition On May 2, 2023, Energy Transfer acquired Lotus Midstream for total consideration of $1.50 billion, including working capital. Consideration included $930 million in cash and approximately 44.5 million newly issued Energy Transfer common units, which had an aggregate acquisition-date fair value of $574 million. Lotus Midstream owns and operates Centurion Pipeline Company LLC, an integrated crude midstream platform located in the Permian Basin. The following table summarizes the allocation of the purchase price among the assets acquired and liabilities assumed: At May 2, 2023 Total current assets $ 61 Property, plant and equipment, net 1,263 Investments in unconsolidated affiliates 138 Lease right-of-use assets, net 10 Other non-current assets 4 Intangible assets, net 75 Total assets 1,551 Total current liabilities 27 Other non-current liabilities 16 Total liabilities 43 Total consideration 1,508 Cash received 4 Total consideration, net of cash received $ 1,504 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 Midcontinent 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 NuStar Acquisition On May 3, 2024, Sunoco LP completed the acquisition of all of the common units of NuStar. Under the terms of the merger agreement, NuStar common unitholders received 0.400 Sunoco LP common units for each NuStar common unit. In connection with the acquisition, Sunoco LP issued approximately 51.5 million common units, which had a fair value of approximately $2.85 billion, assumed debt totaling approximately $3.5 billion, including approximately $56 million of lease related financing obligations, and assumed preferred units with a fair value of approximately $800 million. NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids. The NuStar 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 a third-party 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 assumed allocation of the purchase price among the assets acquired and liabilities assumed: At May 3, 2024 Total current assets $ 186 Property, plant and equipment, net 6,958 Lease right-of-use assets, net 136 Goodwill (1) 16 Intangible assets, net (2) 195 Other non-current assets 127 Total assets 7,618 Total current liabilities 245 Long-term debt, less current maturities (3) 3,500 Non-current operating lease liabilities 136 Deferred income taxes 4 Other non-current liabilities 82 Total liabilities 3,967 Preferred units (3) 801 Total consideration 2,850 Cash received 27 Total consideration, net of cash received $ 2,823 (1) Goodwill primarily represents expected commercial and operational synergies. None of the goodwill recorded as a result of this transaction is deductible for tax purposes. (2) Intangible assets, net comprised of $151 million of favorable contracts, with a remaining weighted average life of approximately 7 years, and $44 million of customer relationships, with a remaining weighted average life of approximately 15 years. (3) Subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed all outstanding NuStar preferred units totaling $784 million, redeemed NuStar’s subordinated notes totaling $403 million and repaid the outstanding balance on the NuStar credit facility totaling $455 million. Subsequent to the NuStar acquisition, Sunoco LP purchased a property previously leased by NuStar and cancelled the lease, resulting in an impairment of $50 million based on the value of comparable real property. Zenith European Terminals Acquisition On March 13, 2024, Sunoco LP completed the acquisition of liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith Energy for approximately €170 million ($185 million), including working capital. The acquisition is expected to supply optimization for Sunoco LP’s existing East Coast business and continues its focus on growing its portfolio of stable midstream income. The purchase price was allocated $6 million to other current assets, $204 million to property, plant and equipment, $36 million to other non-current assets and $6 million to deferred tax assets. In connection with this transaction, Sunoco LP also assumed $14 million in current liabilities, $4 million in deferred tax liabilities and $43 million in other non-current liabilities. Sunoco LP also recognized a $6 million bargain purchase gain related to the acquisition. Other 2024 Acquisition On August 30, 2024, Sunoco LP acquired a terminal in Portland, Maine for approximately $24 million, including working capital. The purchase price was primarily allocated to property, plant and equipment. Other 2023 Acquisition On May 1, 2023, Sunoco LP completed the acquisition of 16 refined product terminals located across the East Coast and Midwest from Zenith Energy for $111 million, including working capital. The purchase price was primarily allocated to property and equipment. Other 2022 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 primarily within Puerto Rico, for $67 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. West Texas Sale On April 16, 2024, Sunoco LP completed the sale of 204 convenience stores located in West Texas, New Mexico and Oklahoma to 7-Eleven, Inc. for approximately $1.00 billion, including customary adjustments for fuel and merchandise inventory. As part of the sale, Sunoco LP also amended its existing take-or-pay fuel supply agreement with 7-Eleven, Inc. to incorporate additional fuel gross profit. As a result of the sale, Sunoco LP recorded a $586 million gain ($438 million, net of current tax expense of $175 million and deferred tax benefit of $27 million). Joint Venture Transaction ET-S Permian Effective July 1, 2024, Energy Transfer and Sunoco LP formed ET-S Permian, a joint venture combining their respective crude oil and produced water gathering assets in the Permian Basin. Pursuant to the contribution agreement by and among Sunoco LP, SUN Pipeline Holdings LLC, NuStar Permian Transportation and Storage LLC, NuStar Permian Crude Logistics LLC, NuStar Permian Holdings LLC, NuStar Logistics, L.P., ET-S Permian Holdings Company LP, ET-S Permian Pipeline Company LLC, ET-S Permian Marketing Company LLC, Energy Transfer and Energy Transfer Crude Marketing, LLC dated July 14, 2024, in a cashless transaction, Energy Transfer contributed its Permian crude oil and produced water gathering assets and operations to ET-S Permian. Sunoco LP contributed all of its Permian crude oil gathering assets and operations to ET-S Permian. Energy Transfer’s long-haul crude pipeline network that provides transportation of crude oil out of the Permian Basin to Nederland, Houston and Cushing is excluded from ET-S Permian. ET-S Permian operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels.

Advances to and Investments in

Advances to and Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2024
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 54.3% 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. White Cliffs is accounted for as an unconsolidated affiliate, despite the Partnership’s ownership of greater than 50%, due to substantive participating rights held by the minority interest owner. 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. SESH Energy Transfer owns a 50% interest in SESH, which consists of a 290-mile pipeline which provides transportation services in Louisiana, Mississippi and Alabama. Our investment in SESH is reflected in our interstate transportation and storage segment. Summary of Balances Related to Unconsolidated Affiliates The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2024 and 2023 were as follows: December 31, 2024 2023 Citrus $ 1,818 $ 1,811 MEP 309 332 White Cliffs 196 203 Explorer 66 67 SESH 223 37 Other 654 647 Total $ 3,266 $ 3,097 The following table presents equity in earnings (losses) of unconsolidated affiliates: Years Ended December 31, 2024 2023 2022 Citrus $ 136 $ 146 $ 141 MEP 63 87 10 White Cliffs 19 10 (8) Explorer 34 37 25 SESH 45 31 22 Other 82 72 67 Total equity in earnings of unconsolidated affiliates $ 379 $ 383 $ 257 Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, MEP, White Cliffs, Explorer and SESH (on a 100% basis) for all periods presented: December 31, 2024 2023 Current assets $ 446 $ 437 Property, plant and equipment, net 8,478 8,571 Other assets 105 88 Total assets $ 9,029 $ 9,096 Current liabilities $ 1,160 $ 683 Non-current liabilities 3,541 4,379 Equity 4,328 4,034 Total liabilities and equity $ 9,029 $ 9,096 Years Ended December 31, 2024 2023 2022 Revenue $ 1,898 $ 1,914 $ 1,618 Operating income 1,009 1,079 754 Net income 750 786 496 In addition to the equity method investments described above, we have other equity method investments which are not significant to our consolidated financial statements.

Net Income Per Limited Partner

Net Income Per Limited Partner Unit	12 Months Ended
	Dec. 31, 2024
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 and USAC that would have resulted assuming the incremental units related to Sunoco LP’s and USAC’s respective long-term 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, 2024 2023 2022 Net income $ 6,565 $ 5,294 $ 5,868 Less: Net income attributable to redeemable noncontrolling interests 59 60 51 Less: Net income attributable to noncontrolling interests 1,692 1,299 1,061 Net income, net of noncontrolling interests 4,814 3,935 4,756 Less: General Partner’s interest in income 4 3 4 Less: Preferred Unitholders’ interest in income 362 463 422 Less: Loss on redemption of preferred units 54 — — Common Unitholders’ interest in net income $ 4,394 $ 3,469 $ 4,330 Basic Income per Common Unit: Weighted average common units 3,395.1 3,161.7 3,086.8 Basic income per common unit $ 1.29 $ 1.10 $ 1.40 Diluted Income per Common Unit: Common Unitholders’ interest in net income $ 4,394 $ 3,469 $ 4,330 Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units (1) (1) (2) Diluted income available to Common Unitholders $ 4,393 $ 3,468 $ 4,328 Weighted average common units 3,395.1 3,161.7 3,086.8 Dilutive effect of unvested unit awards 25.4 15.5 10.2 Weighted average common units, assuming dilutive effect of unvested unit awards 3,420.5 3,177.2 3,097.0 Diluted income per common unit $ 1.28 $ 1.09 $ 1.40

Debt Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2024
Debt Obligations [Abstract]
Debt Disclosure [Text Block]	DEBT OBLIGATIONS : Our debt obligations consist of the following: December 31, 2024 2023 Energy Transfer Indebtedness 5.875% Senior Notes due January 15, 2024 (1) $ — $ 23 5.875% Senior Notes due January 15, 2024 (1) — 1,127 7.60% Senior Notes due February 1, 2024 (1) — 82 4.90% Senior Notes due February 1, 2024 (1) — 350 4.25% Senior Notes due April 1, 2024 (1) — 500 4.50% Senior Notes due April 15, 2024 (1) — 750 3.90% Senior Notes due May 15, 2024 (1) — 600 9.00% Debentures due November 1, 2024 (1) — 65 4.05% Senior Notes due March 15, 2025 (2) 1,000 1,000 5.75% Senior Notes due April 1, 2025 (1) — 500 2.90% Senior Notes due May 15, 2025 (2) 1,000 1,000 5.95% Senior Notes due December 1, 2025 (2) 400 400 4.75% Senior Notes due January 15, 2026 1,000 1,000 3.90% Senior Notes due July 15, 2026 550 550 6.05% Senior Notes due December 1, 2026 1,000 1,000 4.40% Senior Notes due March 15, 2027 700 700 4.20% Senior Notes due April 15, 2027 600 600 6.05% Senior Notes due May 1, 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 1,000 4.95% Senior Notes due May 15, 2028 800 800 4.95% Senior Notes due June 15, 2028 1,000 1,000 6.10% Senior Notes due December 1, 2028 500 500 6.00% Senior Notes due February 1, 2029 700 700 8.00% Senior Notes due April 1, 2029 (1) — 450 5.25% Senior Notes due April 15, 2029 1,500 1,500 5.25% Senior Notes due July 1, 2029 1,000 — 7.00% Senior Notes due July 15, 2029 66 66 4.15% Senior Notes due September 15, 2029 547 547 8.25% Senior Notes due November 15, 2029 33 33 8.25% Senior Notes due November 15, 2029 267 267 3.75% Senior Note due May 15, 2030 1,500 1,500 6.40% Senior Notes due December 1, 2030 1,000 1,000 7.38% Senior Notes due April 1, 2031 600 600 5.75% Senior Notes due February 15, 2033 1,500 1,500 4.05% Tax-Exempt Bonds due June 1, 2033 225 225 6.55% Senior Notes due December 1,2033 1,500 1,500 5.55% Senior Notes due May 15, 2034 1,250 — 5.60% Senior Notes due September 1, 2034 1,250 — 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 5.95% Senior Notes due May 15, 2054 1,750 — 6.05% Senior Notes due September 1, 2054 1,250 — 8.00% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due May 15, 2054 800 — 7.125% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due October 1, 2054 400 — Floating Rate Junior Subordinated Notes due November 1, 2066 600 600 Five-Year Credit Facility due April 11, 2029 2,759 1,412 Unamortized premiums, discounts and fair value adjustments, net 62 128 Deferred debt issuance costs (250) (197) 48,840 44,359 Subsidiary Indebtedness Transwestern Debt 5.66% Senior Notes due December 9, 2024 (1) — 175 6.16% Senior Notes due May 24, 2037 75 75 75 250 Bakken Project Debt 3.90% Senior Notes due April 1, 2024 (1) — 1,000 4.625% Senior Notes due April 1, 2029 850 850 Unamortized premiums, discounts and fair value adjustments, net — (1) Deferred debt issuance costs (3) (4) 847 1,845 Sunoco LP Debt 5.750% Senior Notes due October 1, 2025 (2)(3) 600 — 6.000% Senior Notes due June 1, 2026 (3) 500 — 6.000% Senior Notes due April 15, 2027 600 600 5.625% Senior Notes due April 28, 2027 (3) 550 — 5.875% Senior Notes due March 15, 2028 400 400 7.000% Senior Notes due September 25, 2028 500 500 7.000% Senior Notes due May 1, 2029 750 — 4.500% Senior Notes due May 15, 2029 800 800 4.500% Senior Notes due April 30, 2030 800 800 6.375% Senior Notes due October 1, 2030 (3) 600 — 7.250% Senior Notes due May 1, 2032 750 — GoZone Bonds (2)(3) 322 — Sunoco LP Credit Facility due May 3, 2029 203 411 Lease-related obligations 132 94 Unamortized premiums, discounts and fair value adjustments, net 15 — Deferred debt issuance costs (37) (25) 7,485 3,580 USAC Debt 6.875% Senior Notes due April 1, 2026 (1) — 725 6.875% Senior Notes due September 1, 2027 750 750 7.125% Senior Notes due March 15, 2029 1,000 — USAC Credit Facility due December 8, 2026 772 872 Deferred debt issuance costs (20) (11) 2,502 2,336 Other long-term debt 11 18 Total debt 59,760 52,388 Less: Current maturities of long-term debt 8 1,008 Long-term debt, less current maturities $ 59,752 $ 51,380 (1) These notes were redeemed in 2024. (2) As of December 31, 2024, these obligations (including $75 million of Sunoco LP’s GoZone bonds) were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. (3) Sunoco LP assumed $2.57 billion aggregate principal amount of NuStar senior notes and bonds in connection with the closing of the NuStar acquisition in May 2024. The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $233 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: 2025 $ 3,082 2026 3,826 2027 5,554 2028 4,203 2029 10,476 Thereafter 32,852 Total $ 59,993 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. 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. Energy Transfer 2024 Senior Notes Redemptions During the first quarter of 2024, the Partnership redeemed its $1.15 billion aggregate principal amount of 5.875% senior notes due January 2024, $350 million aggregate principal amount of 4.90% senior notes due February 2024 and $82 million aggregate principal amount of 7.60% senior notes due February 2024 using proceeds from its January 2024 notes issuance described below. During the second quarter of 2024, the Partnership redeemed its $500 million aggregate principal amount of 4.25% senior notes due April 2024, $750 million aggregate principal amount of 4.50% senior notes due April 2024, $450 million aggregate principal amount of 8.00% senior notes due April 2029 and $600 million aggregate principal amount of 3.90% senior notes due May 2024 using cash on hand and proceeds from its Five-Year Credit Facility (defined below). During the fourth quarter of 2024, the Partnership redeemed its $65 million aggregate principal amount of 9.00% debentures due November 2024, its Transwestern $175 million aggregate principal amount of 5.66% senior notes due December 2024 and its $500 million aggregate principal amount of 5.75% senior notes due April 2025 using cash on hand and proceeds from its Five-Year Credit Facility. Bakken Project Debt Redemption In April 2024, the Bakken Pipeline entities redeemed $1.00 billion aggregate principal amount of 3.90% senior notes due April 2024 using proceeds from member contributions, which included $637 million reflected as capital contributions from noncontrolling interests recorded in the Partnership’s consolidated financial statements. Energy Transfer 2024 Notes Issuance In January 2024, the Partnership issued $1.25 billion aggregate principal amount of 5.55% senior notes due 2034, $1.75 billion aggregate principal amount of 5.95% senior notes due 2054 and $800 million aggregate principal amount of 8.00% fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used the net proceeds to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility (defined below), to redeem its outstanding Series C Preferred Units and Series D Preferred Units and for general partnership purposes. The Partnership also used the proceeds to redeem its Series E Preferred Units in May 2024. In June 2024, the Partnership issued $1.00 billion aggregate principal amount of 5.25% senior notes due 2029, $1.25 billion aggregate principal amount of 5.60% senior notes due 2034, $1.25 billion aggregate principal amount of 6.05% senior notes due 2054 and $400 million aggregate principal amount of 7.125% fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used part of the net proceeds to redeem its outstanding Series A Preferred Units. It also used the net proceeds to fund a portion of its acquisition of WTG Midstream, refinance existing indebtedness, including borrowings under its Five-Year Credit Facility, and for general partnership purposes. Sunoco LP April 2024 Notes Issuance On April 30, 2024, the Sunoco LP issued $750 million aggregate principal amount of 7.000% senior notes due 2029 and $750 million aggregate principal amount of 7.250% senior notes due 2032 in a private offering. Sunoco LP used the net proceeds from the offering to (i) repay certain outstanding indebtedness of NuStar, in connection with the merger between the Sunoco LP and NuStar, (ii) fund the redemption of NuStar's preferred units in connection with the merger and (iii) pay offering fees and expenses. NuStar Subordinated Note Redemption and Credit Facility Termination During the second quarter of 2024, subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed NuStar's subordinated notes totaling $403 million and repaid and terminated NuStar's credit facility totaling $455 million. Upon the closing of the NuStar acquisition, the commitments under NuStar’s receivables financing agreement were reduced to zero during a suspension period, for which the period end has not been determined. As of December 31, 2024, this facility had zero outstanding borrowings. USAC March 2024 Notes Issuance In March 2024, USAC issued $1.00 billion aggregate principal amount of 7.125% senior notes due 2029. The net proceeds from this issuance were used to repay a portion of existing borrowings under USAC’s revolving credit facility, to redeem its $725 million aggregate principal amount of 6.875% senior notes due 2026, which constituted a legal defeasance under GAAP, and for general partnership purposes. The Defeasance required a cash outlay in the net amount of $749 million, which was used to purchase U.S. government securities. These securities generated sufficient cash upon maturity to fund interest payments on the senior notes due 2026 occurring between the effective date of the Defeasance through April 4, 2024, when the senior notes due 2026 were redeemed at par, as well as fund the redemption of the senior notes due 2026 in full. As a result of the Defeasance, USAC recognized a loss on early extinguishment of debt of $5 million for the three months ended March 31, 2024. GoZone Bonds Sunoco LP’s obligations also include revenue bonds issued by the Parish of St. James, Louisiana pursuant to the Gulf Opportunity Zone Act of 2005 (the “GoZone Bonds”). As reflected in the table below, the holders of the Series 2008, Series 2010B and Series 2011 GoZone Bonds are required to tender their bonds at the applicable mandatory purchase date in exchange for 100% of the principal plus accrued and unpaid interest, after which these bonds are expected to be remarketed with a new interest rate established. Each of the Series 2010 and Series 2010A GoZone Bonds is subject to redemption on or after June 1, 2030 by the Parish of St. James, at our option, in whole or in part, at a redemption price of 100% of the principal amount to be redeemed plus accrued and unpaid interest. Interest on the GoZone Bonds is payable semi-annually on June 1 and December 1 of each year. The following table summarizes the GoZone Bonds outstanding as of December 31, 2024: Series Date Issued Amount Outstanding Interest Rate Mandatory Purchase Date Original Redemption Date Maturity Date Series 2008 June 26, 2008 56 6.10 % June 1, 2030 n/a June 1, 2038 Series 2010 July 15, 2010 100 6.35 % n/a June 1, 2030 July 1, 2040 Series 2010A October 7, 2010 43 6.35 % n/a June 1, 2030 October 1, 2040 Series 2010B December 29, 2010 48 6.10 % June 1, 2030 n/a December 1, 2040 Series 2011 August 9, 2011 75 5.85 % June 1, 2025 n/a August 1, 2041 Sunoco LP’s agreements with the Parish of St. James related to the GoZone Bonds contain: (i) customary restrictive covenants that limit the ability of Sunoco LP and its subsidiaries to, among other things, create liens, enter into certain sale leaseback transactions, and engage in certain consolidations, mergers or asset sales; and (ii) a repurchase provision which provides that if we undergo a change of control that is followed by a ratings decline that occurs within 60 days of the change of control, then each holder may require the trustee, with funds provided by Sunoco LP, to repurchase all or a portion of that holder’s GoZone Bonds at a price equal to 101% of the aggregate principal amount repurchased, plus any accrued and unpaid interest. 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 until April 11, 2027, and, following the Partnership’s exercise of its option to extend the maturity date on December 18, 2024, up to $4.84 billion until April 11, 2029. 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, 2024, the Five-Year Credit Facility had $2.76 billion of outstanding borrowings, all of which consisted of commercial paper. The amount available for future borrowings was $2.21 billion, after accounting for outstanding letters of credit in the amount of $30 million. The weighted average interest rate on the total amount outstanding as of December 31, 2024 was 4.65%. Sunoco LP Credit Facility Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”). As of December 31, 2024, the Sunoco LP Credit Facility had $203 million of outstanding borrowings and $43 million in standby letters of credit and matures in May 2029. The amount available for future borrowings was $1.25 billion at December 31, 2024. The weighted average interest rate on the total amount outstanding as of December 31, 2024 was 6.57%. USAC Credit Facility USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”) which matures on December 8, 2026. As of December 31, 2024, USAC had $772 million of outstanding borrowings and $1 million in outstanding letters of credit under the credit agreement. As of December 31, 2024, USAC had $827 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $783 million was available to be drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2024 was 6.98%. 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 3.12 to 1.00 at December 31, 2024, 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 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. 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, 2024.

Redeemable Noncontrolling Inter

Redeemable Noncontrolling Interest	12 Months Ended
	Dec. 31, 2024
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. As of December 31, 2024 and 2023, redeemable noncontrolling interests included $169 million and $476 million, respectively, related to the USAC Preferred Units, described below, $23 million and $22 million, respectively, 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 $225 million and $280 million, respectively, related to the Niobrara Preferred Units described below. USAC Series A Preferred Units On January 12, 2024, the holders of the USAC Preferred Units elected to convert 40,000 USAC Preferred Units into 1,998,850 USAC common units. These preferred units were converted into common units and, for USAC’s fourth-quarter 2023 distribution, the holders received the common unit distribution of $0.525 on the 1,998,850 common units in lieu of the preferred unit distribution of $24.375 on the converted 40,000 preferred units. On April 1, 2024, the holders of USAC preferred units elected to convert 280,000 preferred units into 13,991,954 common units. These preferred units were converted into common units and, for USAC’s first-quarter 2024 distribution, the holders received the common unit distribution of $0.525 on the 13,991,954 common units in lieu of the preferred unit distribution of $24.375 on the converted 280,000 preferred units. Niobrara Preferred Units Crestwood Niobrara LLC (“Crestwood Niobrara”), a subsidiary acquired in the Crestwood acquisition in November 2023, has outstanding two series of preferred units (collectively, the “Niobrara Preferred Units”) held by a third-party. The Niobrara Preferred Units are redeemable by the Partnership or the preferred interest holder and are also convertible by the preferred interest holder into Crestwood Niobrara common units. The preferred interest holder also has the option to contribute additional capital to Crestwood Niobrara to increase their common ownership percentage in Crestwood Niobrara to 50% upon the conversion. On February 23, 2024, the Partnership paid approximately $37 million in cash to redeem a portion of the outstanding Crestwood Niobrara LLC preferred units.

Equity

Equity	12 Months Ended
	Dec. 31, 2023
Partners' Capital Notes [Abstract]
Equity	EQUITY : Limited Partners 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, 2024, 2023 and 2022 was as follows: Years Ended December 31, 2024 2023 2022 Number of Common Units, beginning of period 3,367.5 3,094.4 3,082.5 Common Units issued in mergers and acquisitions (1) 50.8 260.2 — Issuance of Common Units (2) 12.7 12.9 11.9 Number of Common Units, end of period 3,431.0 3,367.5 3,094.4 (1) Includes common units issued related to our acquisitions of WTG Midstream in 2024 and of Crestwood and Lotus Midstream in 2023. (2) Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings. Energy Transfer Class A Units As of December 31, 2024, the Partnership had outstanding 847,443,096 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 2024 or 2023. As of December 31, 2024, $880 million remained available to repurchase under the current program. Energy Transfer Distribution Reinvestment Program During the year ended December 31, 2024, distributions of $89 million were reinvested under the distribution reinvestment program. As of December 31, 2024, a total of 38.9 million Energy Transfer common units remained available to be issued under currently effective registration statements in connection with the distribution reinvestment program. Energy Transfer Preferred Units As of December 31, 2024, Energy Transfer’s outstanding preferred units included 550,000 Series B Preferred Units, 500,000 Series F Preferred Units, 1,484,780 Series G Preferred Units, 900,000 Series H Preferred Units and 41,464,179 Series I Preferred Units. As of December 31, 2023, Energy Transfer’s outstanding preferred units also included the Series A Preferred Units, Series C Preferred Units, Series D Preferred Units and Series E Preferred Units, all of which were redeemed in 2024. 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 Series I Total 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 Distributions to partners (96) (36) (40) (36) (61) (34) (106) (59) — (468) Units issued in Crestwood acquisition — — — — — — — — 413 413 Net income 86 36 38 37 61 34 106 59 6 463 Balance, December 31, 2023 948 556 438 435 786 496 1,488 893 419 6,459 Distributions to partners (56) (36) (11) (11) (30) (34) (106) (59) (35) (378) Redemption of Preferred Units (950) — (450) (445) (800) — — — — (2,645) Other, net 13 — 11 10 20 — — — — 54 Net Income 45 36 12 11 24 34 106 59 35 362 Balance, December 31, 2024. $ — $ 556 $ — $ — $ — $ 496 $ 1,488 $ 893 $ 419 $ 3,852 Series A Preferred Units Prior to February 15, 2023, distributions on the Series A Preferred Units accrued at a fixed rate of 6.250% per annum of the liquidation preference of $1,000. Beginning February 15, 2023 to, but excluding, August 15, 2023, the Series A Preferred Units accrued a floating distribution rate set each quarterly distribution period at a percentage of the $1,000 liquidation preference equal to the then-current three-month LIBOR plus a spread of 4.028% per annum. On and after August 15, 2023, the floating distribution rate on the Series A Preferred Units is based on the three-month SOFR, plus a tenor spread adjustment of 0.26161%, plus 4.028% per annum. Distributions on the Series A Preferred Units were previously payable semiannually in arrears until February 15, 2023, and, after February 15, 2023, quarterly in arrears, when, as, and if declared by our General Partner out of legally available funds for such purpose. The Partnership redeemed the Series A Preferred Units in 2024. Series B Preferred Units Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate based on the three-month SOFR, plus a tenor spread adjustment of 0.26161%, plus a spread of 4.155% per annum. The 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 Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Series C Preferred Units Prior to May 15, 2023, distributions on the Series C Preferred Units accrued at a fixed rate of 7.375% per annum of the liquidation preference of $25. Beginning May 15, 2023 to, but excluding, August 15, 2023, the Series C Preferred Units accrued a floating distribution rate set each quarterly distribution period at a percentage of the $25 liquidation preference equal to the then-current three-month LIBOR plus a spread of 4.530% per annum. On and after August 15, 2023, the floating distribution rate on the Series C Preferred Units was based on the three-month SOFR, plus a tenor spread adjustment of 0.26161%, plus 4.530% per annum. The Partnership redeemed the Series C Preferred Units in 2024. Series D Preferred Units Prior to August 15, 2023, distributions on the Series D Preferred Units accrued at a fixed rate of 7.625% per annum of the liquidation preference of $25. On and after August 15, 2023, the Series D Preferred Units accrued a floating distribution rate set each quarterly distribution period at a percentage of the $25 liquidation preference equal to the three-month SOFR, plus a tenor spread adjustment of 0.26161%, plus 4.738% per annum. The Partnership redeemed the Series D Preferred Units in 2024. Series E Preferred Units Distributions on the Series E Preferred Units accrued at a rate of 7.600% per annum of the stated liquidation preference of $25. The Partnership redeemed the Series E Preferred Units in 2024. 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 Series F Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.134% per annum. The Series F Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2025 at a redemption price of $1,000 per Series F Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Series G Preferred Units Distributions on the Series G Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2030, at a rate equal to 7.125% per annum of the $1,000 liquidation preference. On and after May 15, 2030, the distribution rate on the Series G Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.306% per annum. The Series G Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2030 at a redemption price of $1,000 per Series G Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Series H Preferred Units 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. Series I Preferred Units On November 3, 2023, Energy Transfer, in connection with its acquisition of Crestwood, issued 41,464,179 of its Series I Preferred Units in exchange for a commensurate number of Crestwood preferred units. Subject to certain conditions, the holders of the Series I Preferred Units will have the right to convert preferred units into (i) common units on a 10-for-2.07 basis, or (ii) a number of common units determined pursuant to a conversion ratio set forth in the Partnership Agreement upon the occurrence of certain events, such as a change in control. The Series I Preferred Units, on an as converted basis, have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, except that the preferred units are entitled to vote as a separate class on any matter on which all unitholders are entitled to vote that adversely affects the rights, powers, privileges or preferences of the preferred units in relation to Energy Transfer’s other securities outstanding The holders of the Series I Preferred Units are entitled to receive fixed quarterly distributions of $0.2111 per unit. Distributions on the preferred units are paid in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units; and (ii) our available cash (as defined in our Partnership Agreement) is insufficient to make a cash distribution to Series I Preferred Unitholders. 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, 2024, 2023 and 2022, USAC issued 65,352, 87,808 and 124,255 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. In October 2023, the remainder of USAC’s outstanding warrants were exercised in full and net settled for 2,360,488 USAC common units. No warrants remained outstanding subsequent to the exercise on October 27, 2023. 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, 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 March 31, 2023 May 8, 2023 May 22, 2023 0.3075 June 30, 2023 August 14, 2023 August 21, 2023 0.3100 September 30, 2023 October 30, 2023 November 20, 2023 0.3125 December 31, 2023 February 7, 2024 February 20, 2024 0.3150 March 31, 2024 May 13, 2024 May 20, 2024 0.3175 June 30, 2024 August 9, 2024 August 19, 2024 0.3200 September 30, 2024 November 8, 2024 November 19, 2024 0.3225 December 31, 2024 February 7, 2025 February 19, 2025 0.3250 Energy Transfer Preferred Unit Distributions Distributions on Energy Transfer’s preferred units declared and/or paid by Energy Transfer were as follows: Period Ended Record Date Payment Date Series A Series B (1) Series C Series D Series E Series F (1) Series G (1) Series H (1) Series I December 31, 2021 February 1, 2022 February 15, 2022 $ 31.25 $ 33.125 $ 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 33.125 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 33.125 0.4609 0.4766 0.4750 — — — — March 31, 2023 May 1, 2023 May 15, 2023 21.98 — 0.4609 0.4766 0.4750 33.7500 35.63 32.50 — June 30, 2023 August 1, 2023 August 15, 2023 23.89 33.125 0.6294 0.4766 0.4750 — — — — September 30, 2023 November 1, 2023 November 15, 2023 24.67 — 0.6489 0.6622 0.4750 33.7500 35.63 32.50 — December 31, 2023 February 1, 2024 February 15, 2024 24.71 33.125 0.6075 0.6199 0.4750 — — — 0.2111 March 31, 2024 May 1, 2024 May 15, 2024 23.99 — — — 0.4750 33.7500 35.63 32.50 0.2111 June 30, 2024 August 1, 2024 August 15, 2024 9.88 33.125 — — — — — — 0.2111 (2) September 30, 2024 November 1, 2024 November 15, 2024 — — — — — 33.7500 35.63 32.50 0.2111 (2) December 31, 2024 February 1, 2025 February 15, 2024 — 33.125 — — — — — — 0.2111 (2) (1) Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Distributions on the Series B Preferred Units will begin to be paid quarterly on February 15, 2028. (2) For the period ended December 31, 2024, the cash distribution for the Series I Preferred Units was paid on February 14, 2025 to unitholders of record as of the close of business on February 4, 2025. For the period ended September 30, 2024, the cash distribution for the Series I Preferred Units was paid on November 14, 2024 to unitholders of record as of the close of business on November 4, 2024. For the period ended June 30, 2024, the cash distribution for the Series I Preferred Units was paid on August 14, 2024 to unitholders of record as of the close of business on August 2, 2024. Sunoco LP Cash Distributions Energy Transfer owns approximately 28.5 million Sunoco LP common units and all of Sunoco LP’s IDRs. As of December 31, 2024, Sunoco LP had approximately 136.2 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 Payment Date Rate December 31, 2021 February 18, 2022 $ 0.8255 March 31, 2022 May 19, 2022 0.8255 June 30, 2022 August 19, 2022 0.8255 September 30, 2022 November 18, 2022 0.8255 December 31, 2022 February 21, 2023 0.8255 March 31, 2023 May 22, 2023 0.8420 June 30, 2023 August 21, 2023 0.8420 September 30, 2023 November 20, 2023 0.8420 December 31, 2023 February 20, 2024 0.8420 March 31, 2024 May 20, 2024 0.8756 June 30, 2024 August 19, 2024 0.8756 September 30, 2024 November 19, 2024 0.8756 December 31, 2024 February 19, 2025 0.8865 USAC Cash Distributions Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2024, USAC had approximately 117 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 Payment Date Rate December 31, 2021 February 4, 2022 $ 0.5250 March 31, 2022 May 6, 2022 0.5250 June 30, 2022 August 5, 2022 0.5250 September 30, 2022 November 4, 2022 0.5250 December 31, 2022 February 3, 2023 0.5250 March 31, 2023 May 5, 2023 0.5250 June 30, 2023 August 4, 2023 0.5250 September 30, 2023 November 3, 2023 0.5250 December 31, 2023 February 2, 2024 0.5250 March 31, 2024 May 3, 2024 0.5250 June 30, 2024 August 2, 2024 0.5250 September 30, 2024 November 1, 2024 0.5250 December 31, 2024 February 7, 2025 0.5250 Accumulated Other Comprehensive Income The following table presents the components of AOCI, net of tax: December 31, 2024 2023 Available-for-sale securities $ 20 $ 13 Foreign currency translation adjustment (6) (5) Actuarial gain related to pensions and other postretirement benefits 45 6 Investments in unconsolidated affiliates, net 14 14 Total AOCI, net of tax $ 73 $ 28 The following table sets forth the tax amounts included in the respective components of other comprehensive income: December 31, 2024 2023 Available-for-sale securities $ (3) $ (3) Foreign currency translation adjustment 2 6 Total $ (1) $ 3

Equity Incentive Plans

Equity Incentive Plans	12 Months Ended
	Dec. 31, 2024
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, 2024, an aggregate total of 38.6 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, 2023 39.1 $ 10.84 Awards granted 8.6 18.95 Awards vested (10.5) 9.55 Awards forfeited (1.1) 11.13 Unvested awards as of December 31, 2024 36.1 $ 13.18 During the years ended December 31, 2024, 2023, and 2022, the weighted average grant-date fair value per unit award granted was $18.95, $13.78 and $11.56, respectively, and the total fair value of awards vested was $194 million, $106 million and $103 million, respectively, based on the market price of the respective Common Units as of the vesting date. As of December 31, 2024, a total of 36.1 million unit awards remain unvested, for which Energy Transfer expects to recognize a total of $313 million in compensation expense over a weighted average period of 3.0 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, 2024, 2023 and 2022, the Partnership granted a total of 2.8 million, 3.2 million and 3.8 million cash restricted units, respectively. As of December 31, 2024, a total of 6.0 million cash restricted units were unvested. As of December 31, 2024, the Partnership’s consolidated balance sheet reflected aggregate liabilities of $5.1 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 Weighted Average Number of Weighted Average Unvested awards as of December 31, 2023 1.6 $ 41.08 1.9 $ 17.08 Awards granted 0.6 55.24 0.3 22.37 Awards vested (0.4) 34.76 (0.5) 15.40 Awards forfeited (0.1) 42.06 (0.1) 18.09 Unvested awards as of December 31, 2024 1.7 $ 47.55 1.6 $ 19.31 The following table summarizes the weighted average grant-date fair value per unit award granted: Years Ended December 31, 2024 2023 2022 Sunoco LP $ 55.24 $ 53.37 $ 43.54 USAC 22.37 23.13 18.31 The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2024, 2023 and 2022 was $29 million, $37 million and $26 million, respectively, based on the market price of Sunoco LP and USAC common units as of the vesting date. As of December 31, 2024, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $51 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.7 years. As of December 31, 2024, Sunoco LP and USAC also had outstanding grants of cash restricted units totaling 134,225 and 107,820, respectively, for which an aggregate liability of $0.1 million is included on the Partnership’s consolidated balance sheet.

Income Taxes Income Taxes (Note

Income Taxes Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2024
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 Partnership’s income (loss) before income tax expense by geographic area is shown in the table below: Years Ended December 31, 2024 2023 2022 United States $ 7,101 $ 5,602 $ 6,073 Foreign 5 (5) (1) Total $ 7,106 $ 5,597 $ 6,072 The components of the federal and state income tax expense (benefit) of our taxable subsidiaries are summarized as follows: Years Ended December 31, 2024 2023 2022 Current expense: Federal $ 198 $ 56 $ — State 66 44 17 Foreign 1 — — Total 265 100 17 Deferred expense (benefit): Federal 175 227 239 State 101 (24) (58) Foreign — — 6 Total 276 203 187 Total income tax expense $ 541 $ 303 $ 204 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, 2024, 2023 and 2022 is as follows: Years Ended December 31, 2024 2023 2022 Income tax expense at United States statutory rate $ 1,492 $ 1,175 $ 1,275 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax (1,084) (884) (1,086) Noncontrolling interests — — 26 State tax, net of federal tax benefit 113 47 19 Statutory rate change — (10) (42) Valuation allowance — (3) (4) Uncertain tax positions 21 (14) (3) Non-deductible goodwill 9 — — Dividend received deduction (3) (3) (3) Foreign taxes — — 6 Other (7) (5) 16 Income tax expense $ 541 $ 303 $ 204 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, 2024 2023 Deferred income tax assets: Net operating losses and other carryforwards $ 197 $ 371 Other 42 46 Total deferred income tax assets 239 417 Deferred income tax liabilities: Property, plant and equipment (224) (232) Investments in affiliates (4,098) (4,003) Trademarks (82) (91) Other (18) (22) Total deferred income tax liabilities (4,422) (4,348) Net deferred income taxes $ (4,183) $ (3,931) As of December 31, 2024, ETP Holdco had a federal net operating loss carryforward of $537 million, that 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, 2024, Sunoco Retail LLC, a corporate subsidiary of Sunoco LP, had a state net operating loss carryforward of $20 million, which we expect to fully utilize. Sunoco Retail LLC has no federal net operating loss carryforward. A foreign subsidiary of Sunoco Retail LLC had a net operating loss carryforward of $56 million, which we expect to fully utilize. Our corporate subsidiaries have state net operating loss carryforward benefits of $64 million, net of federal tax, some of which expire between 2025 and 2043, while others are carried forward indefinitely. Our corporate subsidiaries have cumulative excess business interest expense of $118 million available for carryforward indefinitely, of which $4 million is limited under IRC §382. The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2024 2023 2022 Balance at beginning of year $ 40 $ 52 $ 56 Additions attributable to tax positions taken in prior years 34 — — Reduction attributable to tax positions taken in prior years — (9) (4) Settlements — (3) — Balance at end of year $ 74 $ 40 $ 52 As of December 31, 2024, we had $74 million ($65 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 2024, we recognized an interest and penalty benefit of $6 million. At December 31, 2024, we have interest and penalties accrued of $5 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. 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 held pending the Nextel matter. 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 reserved $34 million ($27 million after federal income tax benefits) against the receivable. 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 believed the Pennsylvania Supreme Court’s ruling in GM would more likely than not be upheld if challenged by the Commonwealth, and we reversed the reserve thereby recognizing the entire tax benefit of $34 million ($27 million after federal income tax effects). On November 20, 2024, the Pennsylvania Supreme Court reversed its earlier holding in GM and determined taxpayers are not entitled to refunds for excess taxes paid in earlier years. A motion for rehearing of this decision was filed with the court on December 4, 2024. Following the reversal of the GM decision, we reinstated the reserve. IRS Audits The Partnership’s 2020 U.S. Federal income tax return is currently under examination by the IRS. In general, Energy Transfer and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2019 and prior tax years. 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. USAC is currently under examination by the IRS for years 2019 and 2020. The IRS has issued preliminary partnership examination changes, along with imputed underpayment computations. Based on discussions with the IRS, USAC has estimated a potential range of loss up to $28 million, including interest. Once a final partnership imputed underpayment, if any, is determined, USAC’s general partner may either elect to pay the imputed underpayment (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each USAC unitholder, and former USAC unitholder, as applicable, with respect to an audited and adjusted return.

Regulatory Matters, Commitments

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities	12 Months Ended
	Dec. 31, 2024
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
Commitments Contingencies and Guarantees	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES : 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; as explained below, this FERC proceeding has been stayed. 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 (the “Federal District Court”) 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 Federal 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. On April 14, 2023, the United States Supreme Court held against the government in both cases, finding that the federal district courts had jurisdiction to hear those suits and to resolve the parties’ constitutional challenges. The cases were remanded to the federal district courts for further proceedings. On September 13, 2023, the Federal District Court ordered that the Federal District Court case would be stayed pending the resolution of another case pending before the United States Supreme Court and that the FERC enforcement case would remain stayed. On November 13, 2023, the FERC appealed the Federal District Court order to the United States Court of Appeals for the Fifth Circuit. On December 11, 2023, FERC filed a motion to withdraw that appeal, which the Fifth Circuit granted on December 12, 2023. The FERC and the Federal District Court proceedings were stayed pending resolution of the case pending before the United States Supreme Court. The Supreme Court issued a decision in that case on June 27, 2024. The FERC and District Court proceedings remain stayed at this time. 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. FERC has taken no further action on the case since that time. 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 on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023. On November 17, 2023, Panhandle provided refunds to shippers and on November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which was protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the January 5, 2024 order. On May 28, 2024, the FERC issued an order rejecting Panhandle’s refund report. On June 27, 2024, Panhandle filed a revised refund report in compliance with the FERC’s May 28, 2024 order rejecting Panhandle’s refund report and a request for rehearing of the FERC’s May 28, 2024 order rejecting Panhandle’s refund report, and provided revised refunds to shippers, or in the case of shippers whose revised refunds are less than the original amounts refunded, notices of upcoming debits. One party protested Panhandle’s revised refund report, and Panhandle submitted a response to the protest on July 24, 2024. By notice issued July 29, 2024, Panhandle’s rehearing request was deemed denied. In an ordered issued September 9, 2024, FERC addressed arguments raised on rehearing, modified the discussion in the May 28, 2024 order and continued to reach the same result. On September 18, 2024, Panhandle petitioned the Court of Appeals for review of the September 9, 2024, July 29, 2024, and May 28, 2024 orders. On December 5, 2024, the FERC issued an order rejecting Panhandle’s June 27, 2024, refund report, ordering a corrected refund report and directing the issuance of additional refunds. On January 3, 2025, Panhandle submitted an adjusted refund report as well as a request for rehearing of the FERC’s December 5, 2024 order. The FERC approved the adjusted refund report by letter order dated January 23, 2025. On February 3, 2025, the FERC issued a Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration. The request for rehearing will be addressed in a future order. On December 1, 2022, Sea Robin filed a general rate proceeding under Section 4 of the NGA reflecting a general rate increase for gathering and transportation services. The parties reached a settlement in the case, and the settlement was filed with the FERC on December 29, 2023 and approved by order dated February 21, 2024. 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, 2024 2023 2022 ROW expense $ 72 $ 68 $ 64 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, 2024 and 2023, accruals of approximately $281 million and $285 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 $75 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 following sections 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 in the following sections, 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 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. On September 8, 2023, the USACE published the Draft EIS. Comments on the Draft EIS were due on December 13, 2023. The USACE anticipates that a Final EIS will be issued in December 2025 and a Record of Decision will be issued in early 2026. The pipeline continues to operate pending completion of the EIS. Energy Transfer cannot determine when or how future lawsuits will be resolved or the impact they may have on the Bakken Pipeline; however, Energy Transfer expects that 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. Standing Rock Sioux Tribe in Federal Court in District of Columbia Dakota Access is the subject of litigation in the U.S. District Court for the District of Columbia. The Standing Rock Sioux Tribe (“SRST”) sued the USACE arguing that the USACE’s alleged failure to stop Dakota Access from operating violates numerous laws, including the Mineral Leasing Act, the Government Acquisition and Streamlining Act, NEPA, the Clean Water Act, the National Historic Preservation Act, the Administrative Procedure Act as well as the 1868 Fort Laramie Treaty. The SRST requests a permanent injunction or writ of mandamus that would compel the USACE to shut Dakota Access down pending the completion of the USACE’s Environmental Impact Statement (“EIS”) and decision on whether to grant Dakota Access an easement under the Mineral Leasing Act. On October 15, 2024, the SRST filed the above referenced complaint. A summons to the USACE was issued on October 17, 2024. Dakota Access, the state of North Dakota and numerous other states have intervened in the lawsuit in support of the USACE. Dakota Access intends to vigorously defend against these new claims. On January 17, 2025, the USACE, Dakota Access and state intervenors (including North Dakota and thirteen other states) each filed a motion to dismiss all of the claims in the new SRST litigation. Also, on January 17, 2025, the SRST filed a motion for partial summary judgment on certain of their claims. Briefing on the motions to dismiss and the motion for partial summary judgment is ongoing. Louisiana Dispute with New Generation Gas Gathering LLC On August 31, 2023, Energy Transfer and ETC Texas Pipeline, LTD amended the next day to be ETC Texas Pipeline, Ltd, Gulf Run Transmission, LLC, Enable Midstream Partners, LP and ETC Tiger Pipeline, LLC (collectively “Energy Transfer”), filed a petition for declaratory judgment against New Generation Gas Gathering LLC (“NG3”) in the 42nd Judicial District Court of DeSoto Parish, Louisiana. In relation to seven specific servitudes in DeSoto Parish, Louisiana underlying Energy Transfer natural gas pipelines, Energy Transfer requested declarations from the Court that, pursuant to Louisiana Civil Code Article 720, NG3 must obtain Energy Transfer’s permission to install NG3’s proposed pipelines across the Energy Transfer servitudes so that Energy Transfer may determine if NG3’s proposed installation of its proposed pipelines would interfere with Energy Transfer’s use of its existing servitudes. On November 13, 2023, NG3 filed its answer and reconventional demand (a Louisiana term for counterclaim) asserting six claims against the entities asserting the claim, as well as against Energy Transfer. In Count I, NG3 seeks declaratory judgment that Energy Transfer lacks the right to object to its proposed crossings of Energy Transfer’s natural gas pipelines that adversely affect Energy Transfer. In Counts II–VI, NG3 asserts five causes of action alleging that Energy Transfer’s objection and lawsuit seeking court determination that it has the right to object to NG3’s request to cross Energy Transfer’s pipelines more than one hundred times constitutes tortious conduct, an abuse of Energy Transfer’s rights, an unfair trade practice, and a violation of Louisiana Monopolies Act sections prohibiting conspiracies, monopolies and attempted monopolies. On December 7, 2023, the trial court set the deadline for Energy Transfer to respond to NG3’s reconventional demand as February 9, 2024, set a hearing on any exceptions for March 25, 2024, and set a trial date for September 9, 2024. The parties have begun written discovery. On February 7, 2024, the Attorney General for the State of Louisiana, Public Protection Division (the “AG”) gave notice of a complaint filed by NG3. NG3 asserts that Energy Transfer violated Louisiana Revised Statutes 51:1401, et seq., the Unfair Trade Practices and Consumer Protection Law. The AG has not investigated this matter and it makes no determination as to the merits of matter. On March 25, 2024, the trial court denied Energy Transfer’s motion to strike NG3’s Counts II-VI, Energy Transfer’s exceptions, and NG3’s exceptions. Energy Transfer filed an appeal of the trial court’s orders denying its exceptions and motion to strike. The appeal was heard on an expedited basis and denied. On June 4, 2024, a Joint Motion to Dismiss with Prejudice was filed ending the litigation. Williams Antitrust Litigation On June 28, 2024, Louisiana Energy Gateway LLC, The Williams Companies, Inc., and Williams Fields Services Group, LLC (“Williams”) filed a Petition for Damages against Energy Transfer and Gulf Run Transmission, LLC (“Gulf Run”) in the 42nd Judicial District Court, Parish of DeSoto, State of Louisiana, alleging that Energy Transfer and/or Gulf Run have monopolized, conspired to monopolize, and/or attempted to monopolize the relevant product and geographic market for the movement of natural gas from the Haynesville Shale in northwestern Louisiana south to natural gas facilities in the Louisiana Gulf Coast (the “Relevant Market”), engaged in acquisitions that have directly enabled and incentivized to substantially lessen competition, and engaged in unfair methods of competition and unfair trade practices. On September 16, 2024, Energy Transfer and Gulf Run removed the case to the U.S. District Court for the Western District of Louisiana. On October 4, 2024, Williams filed a Motion to Remand, seeking to remand the case back to the 42nd Judicial District Court. On October 21, 2024, Energy Transfer and Gulf Run filed a consent to remand based on a subsequent change in circumstances. After the case was remanded, on November 18, 2024, Energy Transfer and Gulf Run filed a Peremptory Exception of No Cause, asserting that Williams failed to state a cause of action. The Peremptory Exception was set for hearing on February 10, 2025 and denied. 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, 2024, Sunoco Defendants are defendants in two cases: one case initiated by the State of Maryland and one by the Commonwealth of Pennsylvania. The actions brought also named as defendants ETO, ETP Holdco and Sunoco Partners Marketing & Terminals L.P., now known as Energy Transfer Marketing & Terminals L.P. ETP Holdco and Energy Transfer Marketing & Terminals L.P. are wholly owned subsidiaries of Energy Transfer. 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. Rover - State of Ohio On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants (collectively, the “Defendants”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. The Defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court. On April 22, 2020, the Ohio Supreme Court granted the 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. By order issued on October 20, 2023, the trial judge dismissed the Ohio EPA’s Fourth Amended Complaint. On November 17, 2023, the State of Ohio appealed the trial judge’s decision to Ohio’s Fifth District Court of Appeals. The State filed its initial brief on January 8, 2024. Energy Transfer and Rover filed a responsive brief on February 20, 2024. The State filed a reply brief on February 26, 2024. Oral argument on the appeal was held on August 27, 2024. On October 1, 2024, Ohio’s Fifth District Court of Appeals affirmed the trial judge’s decision. The State of Ohio sought permission to appeal this decision from the Ohio State Supreme Court. Energy Transfer and Rover have opposed such permission. On January 28, 2025, the Ohio State Supreme Court declined to hear the State’s appeal. The State of Ohio could seek reconsideration of this Order with the Ohio Supreme Court or attempt to seek review from the U.S. Supreme Court. Energy Transfer and Rover intend to vigorously defend this claim. Unitholder Litigation Regarding Pipeline Construction Various purported unitholders of Energy Transfer have filed derivative actions against various past and current officers and 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.); Barry King v. LE GP, Case No. 3:20-cv-00719-X (N.D. Tex.); Inter-Marketing Group USA, Inc. v. LE GP, et al., 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 Charles King v. LE GP, LLC et al, Cause No. DC-22-14159 (Dallas County, Texas). The Barry 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 S. McCrea and Matthew S. Ramsey, as

Revenue (Notes)

Revenue (Notes)	12 Months Ended
	Dec. 31, 2024
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; ◦ pipeline systems; and ◦ terminals • investment in USAC; ◦ contract operations; and ◦ 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 offtake 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 Northeast 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 revenue Revenues from Sunoco LP’s fuel distribution segment are derived from the sale of fuel, non-fuel and lease income. Fuel sales consist 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 it distributes motor fuel at a price based on a formula which includes 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 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. To determine when control transfers to the customer, the shipping terms of the contract are assessed as a primary indicator of the transfer of control. For free on board ("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. Non-fuel revenue includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores and other revenue such as credit card processing, car washes, lottery and other services. Lease revenue is derived from the leasing or subleasing of real estate used in the retail distribution of motor fuels. Sunoco LP’s pipeline systems revenue Revenues from Sunoco LP’s pipeline systems segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia and the applicable pipeline tariff on a per barrel basis for crude oil or refined products and on a per ton basis for ammonia. Sunoco LP’s terminals revenue Revenues from Sunoco LP’s terminals segment include fees for tank storage agreements, under which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues) and throughput agreements, under which a customer pays a fee per barrel for volumes moving through Sunoco LP’s terminals (throughput terminal revenues). Sunoco LP’s terminals also provide blending, additive injections, handling and filtering services for which Sunoco LP charges additional fees. Additionally, Sunoco LP leases certain of its storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment. USAC’s contract operations revenue USAC’s revenue from contracted compression, natural 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, 2022 $ 615 Additions 1,254 Revenue recognized (1,120) Balance, December 31, 2023 749 Additions 1,256 Revenue recognized (1,246) Balance, December 31, 2024 $ 759 The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2024 and 2023 were as follows: December 31, 2024 2023 Contract Balances Contract assets $ 288 $ 256 Accounts receivable from contracts with customers 1,084 809 Contract liabilities 39 — 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, 2024, 2023 and 2022 was $35 million, $29 million and $22 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, 2024, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $37.70 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below: Years Ending December 31, 2025 2026 2027 Thereafter Total Revenue expected to be recognized on contracts with customers existing as of December 31, 2024 $ 7,808 $ 6,830 $ 5,591 $ 17,474 $ 37,703 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

Lease Accounting (Notes)

Lease Accounting (Notes)	12 Months Ended
	Dec. 31, 2024
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 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 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 sheets as of December 31, 2024 and 2023 were as follows: December 31, 2024 2023 Operating leases: Lease right-of-use assets, net $ 753 $ 797 Operating lease current liabilities 67 56 Accrued and other current liabilities 5 Non-current operating lease liabilities 730 778 Finance leases: Property, plant and equipment, net $ 1 $ 1 Lease right-of-use assets, net 56 29 Current maturities of long-term debt 8 8 Long-term debt, less current maturities 50 19 Other non-current liabilities 1 — The components of lease expense for the years ended December 31, 2024 and 2023 were as follows: Year Ended December 31, Income Statement Location 2024 2023 Operating lease costs: Operating lease cost Cost of goods sold $ 1 $ 1 Operating lease cost Operating expenses 71 69 Operating lease cost Selling, general and administrative 19 18 Total operating lease costs 91 88 Finance lease costs: Amortization of lease assets Depreciation, depletion and amortization 2 — Interest on lease liabilities Interest expense, net of capitalized interest 2 — Total finance lease costs 4 — Short-term lease cost Operating expenses 69 38 Variable lease cost Operating expenses 19 16 Lease costs, gross 183 142 Less: Sublease income Other revenue 45 42 Lease costs, net $ 138 $ 100 The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2024 and 2023 were as follows: December 31, 2024 2023 Weighted-average remaining lease term (years): Operating leases 18 21 Finance leases 15 12 Weighted-average discount rate (%): Operating leases 6 % 6 % Finance leases 6 % 5 % Cash flows and non-cash activity related to leases for the years ended December 31, 2024 and 2023 were as follows: Year Ended December 31, 2024 2023 Operating cash flows from operating leases $ (94) $ (139) Operating cash flows from finance leases (2) — Financing cash flows from finance leases (6) — Lease assets obtained in exchange for new finance lease liabilities 1 18 Lease assets obtained in exchange for new operating lease liabilities 6 5 Maturities of lease liabilities as of December 31, 2024 are as follows: Operating leases Finance leases Total 2025 $ 99 $ 10 $ 109 2026 92 6 98 2027 83 6 89 2028 81 5 86 2029 75 4 79 Thereafter 812 56 868 Total lease payments 1,242 87 1,329 Less: present value discount 445 28 473 Present value of lease liabilities $ 797 $ 59 $ 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. Additionally, Sunoco LP leases certain of its storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment. Sunoco LP’s future minimum operating lease payments receivable as of December 31, 2024 are as follows: Lease Payments 2025 $ 139 2026 121 2027 93 2028 73 2029 61 Thereafter 356 Total undiscounted cash flows $ 843

Derivative Assets And Liabiliti

Derivative Assets And Liabilities	12 Months Ended
	Dec. 31, 2024
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, 2024 December 31, 2023 Notional Maturity Notional Maturity Mark-to-Market Derivatives Natural Gas (BBtu): Fixed Swaps/Futures 6,630 2025-2026 5,247 2024-2026 Basis Swaps IFERC/NYMEX 3,490 2025-2027 (46,975) 2024-2025 Swing Swaps (156,820) 2025-2027 (97,728) 2024-2025 Options – Puts — — 1,900 2024 Options - Calls — — 250 2024 Forward Physical Contracts (1) — — (1,751) 2024-2026 Power (Megawatt): Forwards 6,040 2025-2029 155,600 2024-2029 Futures (140,137) 2025-2026 (464,897) 2024 Options – Puts (17,600) 2025 136,000 2024 Crude (MBbls): Forwards/Swaps (22,512) 2025-2026 (2,674) 2024-2025 Option - Puts — — (15) 2024 Option - Calls — — (20) 2024 NGL/Refined Products (MBbls): Forwards/Swaps (15,063) 2025-2027 (13,870) 2024-2027 Option - Puts (9) 2025-2026 121 2024-2026 Option - Calls (14) 2025-2026 (43) 2024-2026 Futures (1,763) 2025-2026 (4,548) 2024-2025 Fair Value Hedging Derivatives Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (47,170) 2025 (39,013) 2024 Fixed Swaps/Futures (47,170) 2025 (39,013) 2024 Hedged Item – Inventory 44,170 2025 39,013 2024 (1) Natural gas forward physical contracts are no longer reflected as mark-to-market derivatives in 2024. 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 USAC’s interest rate swap which is no longer outstanding as of December 31, 2024, and which was not designated as a hedge for accounting purposes. Term Type Notional Amount Outstanding December 31, 2024 December 31, 2023 December 2025 (1) Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR $ — $ 700 (1) In August 2024, USAC elected to terminate the outstanding interest rate swap. 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, 2024 December 31, 2023 December 31, 2024 December 31, 2023 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 3 $ 51 $ (7) $ (6) 3 51 (7) (6) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 209 427 (229) (374) Commodity derivatives 51 132 (57) (80) Interest rate derivatives — 6 — (4) 260 565 (286) (458) Total derivatives $ 263 $ 616 $ (293) $ (464) 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, 2024 December 31, 2023 December 31, 2024 December 31, 2023 Derivatives without offsetting agreements Derivative assets (liabilities) $ — $ 6 $ — $ (4) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 51 132 (57) (80) Broker cleared derivative contracts Other current assets (liabilities) 212 478 (236) (380) 263 616 (293) (464) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (42) (72) 42 72 Counterparty netting Other current assets (liabilities) (204) (368) 204 368 Total net derivatives $ 17 $ 176 $ (47) $ (24) 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, 2024 2023 2022 Derivatives not designated as hedging instruments: Commodity derivatives Cost of products sold $ 57 $ 47 $ 124 Interest rate derivatives Gains on interest rate derivatives 6 36 293 Total $ 63 $ 83 $ 417

Retirement Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2024
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 $103 million, $86 million and $79 million to these 401(k) savings plans for the years ended December 31, 2024, 2023 and 2022, respectively. 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, 2024 December 31, 2023 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 $ 23 $ 17 $ 138 $ 22 $ 19 $ 148 Service cost 1 — — — — — Interest cost 6 1 7 1 1 6 Amendments — — (11) — — — Benefits paid, net (37) (3) (13) (1) (3) (13) Actuarial gain and other 13 1 (6) 1 — (3) NuStar acquisition 152 — 12 — — — Benefit obligation at end of period 158 16 127 23 17 138 Change in plan assets: Fair value of plan assets at beginning of period 22 — 277 20 — 259 Return on plan assets and other 13 — 29 2 — 29 Employer contributions 5 — 2 1 — 2 Benefits paid, net (36) — (13) (1) — (13) NuStar acquisition 178 — — — — — Fair value of plan assets at end of period 182 — 295 22 — 277 Amount underfunded (overfunded) at end of period $ (24) $ 16 $ (168) $ 1 $ 17 $ (139) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ 24 $ — $ 185 $ — $ — $ 155 Current liabilities — (3) (3) — (3) (2) Non-current liabilities — (13) (14) (1) (14) (14) $ 24 $ (16) $ 168 $ (1) $ (17) $ 139 Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of: Net actuarial gain (loss) $ (9) $ (1) $ (59) $ — $ (2) $ (12) Prior service credit — — 25 — — (3) $ (9) $ (1) $ (34) $ — $ (2) $ (15) The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2024 December 31, 2023 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 22 $ 16 N/A $ 23 $ 15 N/A Accumulated benefit obligation 158 16 $ 127 23 17 $ 138 Fair value of plan assets 182 — 295 22 — 277 Components of Net Periodic Benefit Cost December 31, 2024 December 31, 2023 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Service cost $ 1 $ — $ — $ — Interest cost 6 7 1 6 Expected return on plan assets (8) (13) (1) (12) Prior service cost amortization (2) 2 — 2 Actuarial gain amortization — (1) — (1) Settlements 2 — — — Net periodic benefit cost $ (1) $ (5) $ — $ (5) Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the following table: December 31, 2024 December 31, 2023 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 4.80 % 4.40 % 2.70 % 4.62 % The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the following table: December 31, 2024 December 31, 2023 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 5.40 % 4.40 % 2.70 % 4.93 % Expected return on assets: Tax exempt accounts 7.00 % 7.00 % 7.00 % 7.00 % Taxable accounts 4.26 % 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, 2024 2023 Health care cost trend rate 7.44 % 7.42 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.09 % 5.17 % Year that the rate reaches the ultimate trend rate 2032 2031 Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits. Plan 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, 2024 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Cash and cash equivalents $ 81 $ 81 $ — $ — Mutual funds (1) 65 21 44 — Fixed income securities 36 36 — — Total $ 182 $ 138 $ 44 $ — (1) Comprised of approximately 100% equities as of December 31, 2024. Fair Value Measurements at December 31, 2023 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Cash and cash equivalents $ 1 $ 1 $ — $ — Mutual funds (1) 21 21 — — Total $ 22 $ 22 $ — $ — (1) Comprised of approximately 100% equities as of December 31, 2023. The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2024 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 8 $ 8 $ — $ — Mutual funds (1) 189 189 — — Fixed income securities 98 — 98 — Total $ 295 $ 197 $ 98 $ — (1) Primarily composed of market index funds as of December 31, 2024. Fair Value Measurements at December 31, 2023 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 13 $ 13 $ — $ — Mutual funds (1) 166 166 — — Fixed income securities 98 — 98 — Total $ 277 $ 179 $ 98 $ — (1) Primarily composed of market index funds as of December 31, 2023. 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 $3 million to pension plans and $1 million to other postretirement plans in 2025. 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: Pension Benefits - Funded Plans Pension Benefits - Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2025 $ 72 $ 3 $ 14 2026 4 2 13 2027 4 2 12 2028 4 2 12 2029 5 1 11 2030 – 2034 26 5 46 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.

Reportable Segments

Reportable Segments	12 Months Ended
	Dec. 31, 2024
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 (defined below) as the measure of segment performance reviewed by our chief operating decision maker (“CODM”). The role of the CODM is held by the Partnership’s co-chief executive officers (“co-CEOs”). Both of the co-CEOs fulfill specific functions that impact the allocation of resources and assessment of performance among our reportable segments, including the approval of budgets and the evaluation of growth projects and acquisitions. The Partnership’s co-CEOs receive and review the same information with respect to the Partnership’s segment operating results. The co-CEOs use Segment Adjusted EBITDA to allocate resources (including employees, property, and financial or capital resources) for each segment predominantly in the annual budget and forecasting process. The co-CEOs also use Segment Adjusted EBITDA to assess the performance for each segment by comparing the results and return on assets of each segment with one another and in the compensation of certain employees. The co-CEOs consider forecast-to-actual variances on a monthly basis when making decisions about allocating capital and personnel to the segments. 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, as well as certain non-recurring gains and losses. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period. Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly. The following tables present financial information by segment: Years Ended December 31, 2024 2023 2022 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,750 $ 3,222 $ 6,954 Intersegment revenues 303 740 864 3,053 3,962 7,818 Interstate transportation and storage: Revenues from external customers 2,270 2,328 2,185 Intersegment revenues 26 47 66 2,296 2,375 2,251 Midstream: Revenues from external customers 3,283 2,911 4,114 Intersegment revenues 7,916 7,495 12,987 11,199 10,406 17,101 NGL and refined products transportation and services: Revenues from external customers 20,981 18,413 21,414 Intersegment revenues 3,549 3,490 4,243 24,530 21,903 25,657 Crude oil transportation and services: Revenues from external customers 28,528 26,534 25,980 Intersegment revenues 11 2 2 28,539 26,536 25,982 Investment in Sunoco LP: Revenues from external customers 22,666 23,026 25,677 Intersegment revenues 27 42 52 22,693 23,068 25,729 Investment in USAC: Revenues from external customers 909 824 689 Intersegment revenues 41 22 16 950 846 705 All other: Revenues from external customers 1,284 1,328 2,863 Intersegment revenues 463 470 711 1,747 1,798 3,574 Eliminations (12,336) (12,308) (18,941) Total revenues $ 82,671 $ 78,586 $ 89,876 Years Ended December 31, 2024 2023 2022 Cost of products sold: Intrastate transportation and storage $ 1,390 $ 2,616 $ 6,000 Interstate transportation and storage 9 6 25 Midstream 6,637 6,503 12,682 NGL and refined products transportation and services 19,406 17,049 21,656 Crude oil transportation and services 24,407 23,071 22,917 Investment in Sunoco LP 20,595 21,703 24,350 Investment in USAC 146 137 111 All other 1,709 1,740 3,328 Eliminations (12,324) (12,284) (18,837) Total cost of products sold $ 61,975 $ 60,541 $ 72,232 Years Ended December 31, 2024 2023 2022 Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses: Intrastate transportation and storage $ 246 $ 279 $ 334 Interstate transportation and storage 807 746 791 Midstream 1,550 1,204 1,087 NGL and refined products transportation and services 957 892 962 Crude oil transportation and services 852 699 645 Investment in Sunoco LP 611 420 396 Investment in USAC 166 147 123 All other 20 40 80 Eliminations (112) (112) (170) Total operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses $ 5,097 $ 4,315 $ 4,248 Years Ended December 31, 2024 2023 2022 Depreciation, depletion and amortization: Intrastate transportation and storage $ 216 $ 214 $ 209 Interstate transportation and storage 575 563 513 Midstream 1,719 1,451 1,351 NGL and refined products transportation and services 1,026 915 865 Crude oil transportation and services 965 740 663 Investment in Sunoco LP 368 187 193 Investment in USAC 265 246 237 All other 31 69 133 Total depreciation, depletion and amortization $ 5,165 $ 4,385 $ 4,164 Years Ended December 31, 2024 2023 2022 Selling, general and administrative expenses, excluding non-cash compensation and accretion expenses: Intrastate transportation and storage $ 50 $ 51 $ 53 Interstate transportation and storage 129 115 131 Midstream 199 199 186 NGL and refined products transportation and services 160 157 127 Crude oil transportation and services 149 120 224 Investment in Sunoco LP 266 113 111 Investment in USAC 54 51 45 All other 62 85 60 Total selling, general and administrative expenses, excluding non-cash compensation and accretion expenses $ 1,069 $ 891 $ 937 Years Ended December 31, 2024 2023 2022 Equity in earnings (losses) of unconsolidated affiliates (1) : Intrastate transportation and storage $ 16 $ 17 $ 17 Interstate transportation and storage 241 260 175 Midstream 13 15 19 NGL and refined products transportation and services 83 76 44 Crude oil transportation and services 21 11 (2) All other 5 4 4 Total equity in earnings of unconsolidated affiliates $ 379 $ 383 $ 257 (1) Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation. Years Ended December 31, 2024 2023 2022 Other income (expense) (1) : Intrastate transportation and storage $ (9) $ 95 $ (35) Interstate transportation and storage 477 501 449 Midstream 97 25 64 NGL and refined products transportation and services 172 89 113 Crude oil transportation and services 46 35 (9) Investment in Sunoco LP 236 132 47 Investment in USAC — 1 — All other 35 (8) 14 Eliminations (101) (11) (9) Total other income (expense) $ 953 $ 859 $ 634 (1) Other income and expense include, if applicable to a segment, Adjusted EBITDA related to unconsolidated affiliates, unrealized gains and losses on commodity risk management activities and other items. For the investment in Sunoco LP segment, this also includes inventory valuation adjustments. December 31, 2024 2023 2022 Segment assets: Intrastate transportation and storage $ 6,289 $ 6,112 $ 6,609 Interstate transportation and storage 17,656 17,708 17,979 Midstream 30,473 25,592 21,851 NGL and refined products transportation and services 27,445 27,214 27,903 Crude oil transportation and services 25,231 25,464 19,200 Investment in Sunoco LP 14,375 6,826 6,830 Investment in USAC 2,746 2,737 2,666 All other and eliminations 1,165 2,045 2,605 Total segment assets $ 125,380 $ 113,698 $ 105,643 Years Ended December 31, 2024 2023 2022 Additions to property, plant and equipment (1) : Intrastate transportation and storage $ 118 $ 93 $ 179 Interstate transportation and storage 332 383 644 Midstream 1,323 832 1,004 NGL and refined products transportation and services 1,424 679 507 Crude oil transportation and services 423 266 246 Investment in Sunoco LP 344 215 186 Investment in USAC 276 300 169 All other 342 100 91 Total additions to property, plant and equipment $ 4,582 $ 2,868 $ 3,026 (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, 2024 2023 2022 Investments in unconsolidated affiliates (1) : Intrastate transportation and storage $ 150 $ 144 $ 139 Interstate transportation and storage 2,350 2,179 2,201 Midstream 132 141 54 NGL and refined products transportation and services 383 390 398 Crude oil transportation and services 193 187 48 All other 58 56 53 Total investments in unconsolidated affiliates $ 3,266 $ 3,097 $ 2,893 (1) Amounts reflected above exclude Sunoco LP’s investments in the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation. Years Ended December 31, 2024 2023 2022 Segment Adjusted EBITDA: Intrastate transportation and storage $ 1,358 $ 1,111 $ 1,396 Interstate transportation and storage 1,828 2,009 1,753 Midstream 2,910 2,525 3,210 NGL and refined products transportation and services 4,179 3,894 3,025 Crude oil transportation and services 3,177 2,681 2,187 Investment in Sunoco LP 1,457 964 919 Investment in USAC 584 512 426 All Other (10) 2 177 Adjusted EBITDA (consolidated) $ 15,483 $ 13,698 $ 13,093 Years Ended December 31, 2024 2023 2022 Reconciliation of net income to Adjusted EBITDA: Net income $ 6,565 $ 5,294 $ 5,868 Depreciation, depletion and amortization 5,165 4,385 4,164 Interest expense, net of interest capitalized 3,125 2,578 2,306 Income tax expense 541 303 204 Impairment losses and other 52 12 386 Gains on interest rate derivatives (6) (36) (293) Non-cash compensation expense 151 130 115 Unrealized (gains) losses on commodity risk management activities 56 (3) (42) Inventory valuation adjustments (Sunoco LP) 86 114 (5) (Gains) losses on extinguishments of debt 12 (2) — Adjusted EBITDA related to unconsolidated affiliates 692 691 565 Equity in earnings of unconsolidated affiliates (379) (383) (257) Non-operating litigation-related loss — 627 — Gain on sale of West Texas assets (Sunoco LP) (586) — — Other, net 9 (12) 82 Adjusted EBITDA (consolidated) $ 15,483 $ 13,698 $ 13,093

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pay vs Performance Disclosure
NET INCOME ATTRIBUTABLE TO PARTNERS	$ 4,814	$ 3,935	$ 4,756

Insider Trading Arrangements

Insider Trading Arrangements	12 Months Ended
	Dec. 31, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Insider Trading Policies and Pr

Insider Trading Policies and Procedures	12 Months Ended
	Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Operations And Organization Ope

Operations And Organization Operations and Organization (Policies)	12 Months Ended
	Dec. 31, 2024
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 have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all subsidiaries in which we have a controlling financial interest and limited partnerships in which we control the general partner. All significant intercompany transactions and accounts are eliminated in consolidation.

Estimates, Significant Accoun_2

Estimates, Significant Accounting Policies and Balance Sheet Detail (Policy)	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The oil and 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 much of our business 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.
Regulatory Accounting - Regulatory Assets and Liabilities	Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities, 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, 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.
Accounts Receivable	Accounts Receivable, net 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
Inventories	Inventories Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method. Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2024 and 2023, Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $316 million and $230 million, respectively. For the years ended December 31, 2024, 2023 and 2022, 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, 2024 and 2023, the Partnership’s cost of products sold included unfavorable inventory adjustments of $86 million and $114 million, respectively, which decreased net income. For the year ended December 31, 2022 the Partnership’s cost of products sold included favorable inventory adjustments of $5 million, which increased net income. The Partnership’s inventories consisted of the following: December 31, 2024 2023 Natural gas, NGLs and refined products $ 1,989 $ 1,658 Crude oil 400 258 Spare parts and other 681 562 Total inventories $ 3,070 $ 2,478
Property, Plant and Equipment	Property, Plant and Equipment, net 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. For the years ended December 31 2024, 2023 and 2022, USAC recognized fixed asset impairments of $1 million, $12 million and $1 million, respectively, primarily related to its compression equipment as a result of its evaluation of the future deployment of 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 then current weighted average interest rate of our outstanding debt 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.
Other Non-Current Assets, net	Other non-current assets, net are stated at cost less accumulated amortization.
Intangible Assets	Intangible Assets, net 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, 2024 December 31, 2023 Gross Accumulated Gross Accumulated Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 9,304 $ (3,654) $ 9,098 $ (3,196) Patents (10 years) 48 (48) 48 (48) Trade names (20 years) 66 (48) 66 (44) Other (5 to 20 years) 12 (11) 12 (11) Total amortizable intangible assets 9,430 (3,761) 9,224 (3,299) Non-amortizable intangible assets: Trademarks 302 — 302 — Other — — 12 — Total non-amortizable intangible assets 302 — 314 — Total intangible assets $ 9,732 $ (3,761) $ 9,538 $ (3,299) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2024 2023 2022 Reported in depreciation, depletion and amortization expense $ 464 $ 399 $ 390 Estimated aggregate amortization of intangible assets for the next five years is as follows: Years Ending December 31: 2025 $ 440 2026 437 2027 419 2028 416 2029 408
Goodwill	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 Interstate Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services Investment in Sunoco LP Investment in USAC All Other Total Balance, December 31, 2022 $ — $ — $ — $ 693 $ 190 $ 1,601 $ — $ 82 $ 2,566 Acquired — — 601 191 663 — — — 1,455 Other — — — — — (2) — — (2) Balance, December 31, 2023 — — 601 884 853 1,599 — 82 4,019 Acquired — — — — — 16 — — 16 Disposed — — — — — (138) — — (138) Other — — 16 2 (12) — — — 6 Balance, December 31, 2024 $ — $ — $ 617 $ 886 $ 841 $ 1,477 $ — $ 82 $ 3,903 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 2024, $16 million of goodwill was recorded in connection with Sunoco LP’s acquisition of NuStar and $138 million of goodwill was removed in connection with Sunoco LP’s sale of 204 convenience stores to 7-Eleven Inc. During the fourth quarter of 2023, $1.46 billion of goodwill was recorded in connection with the acquisition of Crestwood, which is not expected to be deductible for tax purposes. 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.
Asset Retirement Obligation	Asset Retirement Obligations We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an ARO in the periods in which management can reasonably estimate the settlement dates. As of December 31, 2024 and 2023, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $418 million and $410 million, respectively. For the years ended December 31, 2024, 2023 and 2022 aggregate accretion expense related to AROs was $11 million, $10 million and $4 million, respectively. Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2024 and 2023, 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 both December 31, 2024 and 2023, other non-current assets on the Partnership’s consolidated balance sheets included $31 million of funds that were legally restricted for the purpose of settling AROs.
Redeemable Noncontrolling Interest [Text Block]	Redeemable Noncontrolling Interests
Environmental Costs, Policy [Policy Text Block]	Environmental Remediation
Fair Value of Financial Instruments	Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. 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, 2024, no transfers were made between any levels within the fair value hierarchy.
Contributions In Aid Of Construction Costs Policy Text Block	Contributions in Aid of Construction Costs On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. For our regulated businesses, contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received. For our non-regulated businesses, contributions in aid of construction costs are included in the transaction price of the underlying contract.
Costs and Expenses	Costs and Expenses Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership and administrative personnel. We record the collection of taxes to be remitted to government authorities on a net basis, except for consumer excise taxes collected by Sunoco LP on sales of refined products and merchandise which are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income. For the years ended December 31, 2024, 2023 and 2022, excise taxes collected by Sunoco LP were $164 million, $274 million and $285 million, respectively.
Issuances of Subsidiary Units	Issuances of Subsidiary Units
Income Taxes	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, 2024, 2023 and 2022, 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.
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques. At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period. If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations. Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
Share-based Payment Arrangement [Policy Text Block]	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.
Pension and Other Postretirement Plans, Policy [Policy Text Block]	Pensions and Other Postretirement Benefit Plans The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Changes in the funded
Allocation of Income (Loss)	Allocation of Income For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.
Equity Method Investments Issuances, Policy	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.
New Accounting Pronouncements, Policy	Recent Accounting Pronouncements In November 2024, Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2024-03, Income Statement–Reporting Comprehensive Income–Expense Disaggregation Disclosures (Subtopic 220-40) . ASU 2024-03 requires disclosure of specified information about certain costs and expenses in the notes to the consolidated financial statements. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and interim periods within annual periods beginning after December 15, 2027, with early adoption permitted. ASU 2024-03 is to be applied on a prospective basis, with retrospective application permitted. We are currently evaluating the impact, if any, of ASU 2024-03 on our consolidated financial statements and related disclosures. In December 2023, FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures . ASU 2023-09 improves and enhances income tax disclosure requirements, including new disclosures related to tax rate reconciliation and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, and interim periods within annual periods beginning after December 15, 2025, with early adoption permitted. ASU 2023-09 is to be applied on a prospective basis, with retrospective application permitted. We are currently evaluating the impact, if any, of ASU 2023-09 on our consolidated financial statements and related disclosures.

Revenue (Policies)

Revenue (Policies)	12 Months Ended
	Dec. 31, 2024
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; ◦ pipeline systems; and ◦ terminals • investment in USAC; ◦ contract operations; and ◦ 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 offtake 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 Northeast 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 revenue Revenues from Sunoco LP’s fuel distribution segment are derived from the sale of fuel, non-fuel and lease income. Fuel sales consist 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 it distributes motor fuel at a price based on a formula which includes 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 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. To determine when control transfers to the customer, the shipping terms of the contract are assessed as a primary indicator of the transfer of control. For free on board ("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. Non-fuel revenue includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores and other revenue such as credit card processing, car washes, lottery and other services. Lease revenue is derived from the leasing or subleasing of real estate used in the retail distribution of motor fuels. Sunoco LP’s pipeline systems revenue Revenues from Sunoco LP’s pipeline systems segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia and the applicable pipeline tariff on a per barrel basis for crude oil or refined products and on a per ton basis for ammonia. Sunoco LP’s terminals revenue Revenues from Sunoco LP’s terminals segment include fees for tank storage agreements, under which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues) and throughput agreements, under which a customer pays a fee per barrel for volumes moving through Sunoco LP’s terminals (throughput terminal revenues). Sunoco LP’s terminals also provide blending, additive injections, handling and filtering services for which Sunoco LP charges additional fees. Additionally, Sunoco LP leases certain of its storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment. USAC’s contract operations revenue USAC’s revenue from contracted compression, natural 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

Lease Accounting (Policies)

Lease Accounting (Policies)	12 Months Ended
	Dec. 31, 2024
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 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 determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives. Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance. For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.
Lessor, Leases [Policy Text Block]	Lessor Accounting Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement. Additionally, Sunoco LP leases certain of its storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment.

Estimates, Significant Accoun_3

Estimates, Significant Accounting Policies and Balance Sheet Detail (Tables)	12 Months Ended
	Dec. 31, 2024
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 and divestitures, included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2024 2023 2022 Accounts receivable $ (775) $ (171) $ (863) Accounts receivable from related companies 15 (5) 23 Inventories (735) 35 (361) Other current assets 82 221 (326) Other non-current assets, net (166) (125) 146 Accounts payable 1,315 (501) 25 Accounts payable to related companies (35) (38) 6 Accrued and other current liabilities 166 209 131 Other non-current liabilities (123) (33) 66 Derivative assets and liabilities, net 60 (43) (349) Net change in operating assets and liabilities, net of effects of acquisitions and divestitures $ (196) $ (451) $ (1,502)
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, 2024 2023 2022 NON-CASH INVESTING AND FINANCING ACTIVITIES: Accrued capital expenditures $ 688 $ 442 $ 575 Lease assets obtained in exchange for new lease liabilities 7 23 42 Units issued in connection with the WTG Midstream acquisition (1) 833 — — Units issued in connection with the Crestwood acquisition (1) — 3,366 — Units issued in connection with the Lotus Midstream acquisition (1) — 574 — USAC exercise and conversion of preferred units into common units 301 — — USAC government securities transferred in connection with the legal defeasance of USAC senior notes due 2026 749 — — Legal defeasance of USAC senior notes due 2026 725 — — Sunoco LP common units (noncontrolling interest) issued in connection with the NuStar acquisition (1) 2,850 — — SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 2,884 $ 2,298 $ 2,167 Cash paid for income taxes, net of refunds (excluding $47 million of federal tax credits purchased from non-governmental third parties by Sunoco LP in 2024) 206 103 54 (1) See Note 3 for additional information.
Schedule of Inventory	The Partnership’s inventories consisted of the following: December 31, 2024 2023 Natural gas, NGLs and refined products $ 1,989 $ 1,658 Crude oil 400 258 Spare parts and other 681 562 Total inventories $ 3,070 $ 2,478
Other Current Assets	Other current assets consisted of the following: December 31, 2024 2023 Deposits paid to vendors $ 150 $ 205 Prepaid expenses and other 327 308 Total other current assets $ 477 $ 513
Property, Plant and Equipment	Components and useful lives of property, plant and equipment were as follows: December 31, 2024 2023 (1) Land and improvements $ 1,675 $ 1,529 Buildings and improvements (1 to 45 years) 4,688 4,392 Pipelines and equipment (5 to 83 years) 97,078 86,905 Product storage and related facilities (2 to 83 years) 7,869 8,381 Right of way (20 to 83 years) 9,239 7,379 Other (1 to 48 years) 4,060 4,031 Construction work-in-process 4,633 2,315 129,242 114,932 Less – Accumulated depreciation and depletion (34,030) (29,581) Property, plant and equipment, net $ 95,212 $ 85,351 (1) Certain components of property, plant and equipment were reclassified in the current year. The balances as of December 31, 2023 reflected above have been adjusted to conform to the current year presentation. These changes did not impact total property, plant and equipment.
Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense	We recognized the following amounts for the periods presented: Years Ended December 31, 2024 2023 2022 Depreciation, depletion and amortization expense $ 4,701 $ 3,986 $ 3,774 Capitalized interest 120 77 112
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, 2024 2023 Crude pipeline linefill and tank bottoms $ 743 $ 598 Regulatory assets 39 48 Pension assets 188 145 Deferred charges 151 148 Restricted funds 216 225 Other 680 569 Total other non-current assets, net $ 2,017 $ 1,733 Restricted funds primarily consist of investments held in our wholly owned captive insurance companies, including an immaterial amount of restricted cash.
Components And Useful Lives Of Intangibles And Other Assets	Components and useful lives of intangible assets were as follows: December 31, 2024 December 31, 2023 Gross Accumulated Gross Accumulated Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 9,304 $ (3,654) $ 9,098 $ (3,196) Patents (10 years) 48 (48) 48 (48) Trade names (20 years) 66 (48) 66 (44) Other (5 to 20 years) 12 (11) 12 (11) Total amortizable intangible assets 9,430 (3,761) 9,224 (3,299) Non-amortizable intangible assets: Trademarks 302 — 302 — Other — — 12 — Total non-amortizable intangible assets 302 — 314 — Total intangible assets $ 9,732 $ (3,761) $ 9,538 $ (3,299)
Aggregate Amortization Expense Of Intangibles And Other Assets	Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2024 2023 2022 Reported in depreciation, depletion and amortization expense $ 464 $ 399 $ 390
Estimated Aggregate Amortization Expense	Estimated aggregate amortization of intangible assets for the next five years is as follows: Years Ending December 31: 2025 $ 440 2026 437 2027 419 2028 416 2029 408
Schedule of Goodwill	Changes in the carrying amount of goodwill were as follows: Intrastate Interstate Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services Investment in Sunoco LP Investment in USAC All Other Total Balance, December 31, 2022 $ — $ — $ — $ 693 $ 190 $ 1,601 $ — $ 82 $ 2,566 Acquired — — 601 191 663 — — — 1,455 Other — — — — — (2) — — (2) Balance, December 31, 2023 — — 601 884 853 1,599 — 82 4,019 Acquired — — — — — 16 — — 16 Disposed — — — — — (138) — — (138) Other — — 16 2 (12) — — — 6 Balance, December 31, 2024 $ — $ — $ 617 $ 886 $ 841 $ 1,477 $ — $ 82 $ 3,903
Accrued and Other Current Liabilities	Accrued and other current liabilities consisted of the following: December 31, 2024 2023 Interest payable $ 685 $ 637 Customer advances and deposits 360 240 Accrued capital expenditures 688 442 Accrued wages and benefits 422 406 Taxes payable other than income taxes 737 646 Exchanges payable 90 163 Deferred revenue 322 312 Other 937 675 Total accrued and other current liabilities $ 4,241 $ 3,521
Schedule of Derivative Assets at Fair Value	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, 2024 and 2023 based on inputs used to derive their fair values: Fair Value Total Fair Value Measurements at December 31, 2024 Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps FERC/NYMEX $ 6 $ 6 $ — Swing Swaps IFERC 4 4 — Fixed Swaps/Futures 10 10 — Power: Forwards 39 39 — Futures 10 10 — NGLs – Forwards/Swaps 166 166 — Refined Products – Futures 3 3 — Crude – Forwards/Swaps 25 25 — Total commodity derivatives 263 263 — Other non-current assets 212 212 — Total assets $ 475 $ 475 $ — Liabilities: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ (11) $ (11) $ — Swing Swaps IFERC (11) (11) — Fixed Swaps/Futures (9) (9) — Power: Forwards (38) (38) — Futures (10) (10) — NGLs – Forwards/Swaps (170) (170) — Refined Products – Futures (9) (9) — Crude – Forwards/Swaps (35) (35) — Total commodity derivatives (293) (293) — Total liabilities $ (293) $ (293) $ — Fair Value Total Fair Value Measurements at December 31, 2023 Level 1 Level 2 Assets: Interest rate derivatives $ 6 $ — $ 6 Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX 24 24 — Swing Swaps IFERC 20 20 — Fixed Swaps/Futures 77 77 — Forward Physical Contracts 8 — 8 Power: Forwards 57 57 — Futures 8 8 — NGLs – Forwards/Swaps 336 336 — Refined Products – Futures 35 35 — Crude - Forwards/Swaps 45 45 — Total commodity derivatives 610 602 8 Other non-current assets 217 217 — Total assets $ 833 $ 819 $ 14 Liabilities: Interest rate derivatives $ (4) $ — $ (4) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (3) (3) Swing Swaps IFERC (2) (2) — Fixed Swaps/Futures (16) (16) — Options – Puts (2) (2) — Power: Forwards (56) (56) — Futures (8) (8) — NGL/Refined Products Option - Puts (1) (1) — NGL/Refined Products Option - Calls (1) (1) — NGLs – Forwards/Swaps (316) (316) — Refined Products – Futures (18) (18) — Crude - Forwards/Swaps (37) (37) — Total commodity derivatives (460) (460) — Total liabilities $ (464) $ (460) $ (4)

Acquisitions and Related Tran_2

Acquisitions and Related Transactions (Tables)	12 Months Ended
	Dec. 31, 2024
Nustar Acquisition
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed: At May 3, 2024 Total current assets $ 186 Property, plant and equipment, net 6,958 Lease right-of-use assets, net 136 Goodwill (1) 16 Intangible assets, net (2) 195 Other non-current assets 127 Total assets 7,618 Total current liabilities 245 Long-term debt, less current maturities (3) 3,500 Non-current operating lease liabilities 136 Deferred income taxes 4 Other non-current liabilities 82 Total liabilities 3,967 Preferred units (3) 801 Total consideration 2,850 Cash received 27 Total consideration, net of cash received $ 2,823 (1) Goodwill primarily represents expected commercial and operational synergies. None of the goodwill recorded as a result of this transaction is deductible for tax purposes. (2) Intangible assets, net comprised of $151 million of favorable contracts, with a remaining weighted average life of approximately 7 years, and $44 million of customer relationships, with a remaining weighted average life of approximately 15 years. (3) Subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed all outstanding NuStar preferred units totaling $784 million, redeemed NuStar’s subordinated notes totaling $403 million and repaid the outstanding balance on the NuStar credit facility totaling $455 million.
Lotus Midstream Acquisition
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 May 2, 2023 Total current assets $ 61 Property, plant and equipment, net 1,263 Investments in unconsolidated affiliates 138 Lease right-of-use assets, net 10 Other non-current assets 4 Intangible assets, net 75 Total assets 1,551 Total current liabilities 27 Other non-current liabilities 16 Total liabilities 43 Total consideration 1,508 Cash received 4 Total consideration, net of cash received $ 1,504
Crestwood Acquisition
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed: At November 3, 2023 Total current assets $ 657 Property, plant and equipment, net 4,772 Investments in unconsolidated affiliates 95 Lease right-of-use assets, net 27 Other non-current assets 12 Intangible assets, net 1,139 Goodwill 1,455 Total assets 8,157 Total current liabilities 445 Long-term debt, less current maturities 3,461 Other non-current liabilities 322 Total liabilities 4,228 Noncontrolling interests 272 Total consideration 3,657 Cash received 12 Total consideration, net of cash received $ 3,645
WTG Midstream
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed: At July 15, 2024 Total current assets $ 334 Property, plant and equipment, net 3,109 Lease right-of-use assets, net 8 Intangible assets, net 20 Total assets 3,471 Total current liabilities 394 Non-current operating lease liabilities 5 Other non-current liabilities 20 Total liabilities 419 Total consideration 3,052 Cash received 45 Total consideration, net of cash received $ 3,007

Advances to and Investments i_2

Advances to and Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 and 2023 were as follows: December 31, 2024 2023 Citrus $ 1,818 $ 1,811 MEP 309 332 White Cliffs 196 203 Explorer 66 67 SESH 223 37 Other 654 647 Total $ 3,266 $ 3,097 The following table presents equity in earnings (losses) of unconsolidated affiliates: Years Ended December 31, 2024 2023 2022 Citrus $ 136 $ 146 $ 141 MEP 63 87 10 White Cliffs 19 10 (8) Explorer 34 37 25 SESH 45 31 22 Other 82 72 67 Total equity in earnings of unconsolidated affiliates $ 379 $ 383 $ 257
Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block]	The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, MEP, White Cliffs, Explorer and SESH (on a 100% basis) for all periods presented: December 31, 2024 2023 Current assets $ 446 $ 437 Property, plant and equipment, net 8,478 8,571 Other assets 105 88 Total assets $ 9,029 $ 9,096 Current liabilities $ 1,160 $ 683 Non-current liabilities 3,541 4,379 Equity 4,328 4,034 Total liabilities and equity $ 9,029 $ 9,096 Years Ended December 31, 2024 2023 2022 Revenue $ 1,898 $ 1,914 $ 1,618 Operating income 1,009 1,079 754 Net income 750 786 496 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 Partne_2

Net Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 2022 Net income $ 6,565 $ 5,294 $ 5,868 Less: Net income attributable to redeemable noncontrolling interests 59 60 51 Less: Net income attributable to noncontrolling interests 1,692 1,299 1,061 Net income, net of noncontrolling interests 4,814 3,935 4,756 Less: General Partner’s interest in income 4 3 4 Less: Preferred Unitholders’ interest in income 362 463 422 Less: Loss on redemption of preferred units 54 — — Common Unitholders’ interest in net income $ 4,394 $ 3,469 $ 4,330 Basic Income per Common Unit: Weighted average common units 3,395.1 3,161.7 3,086.8 Basic income per common unit $ 1.29 $ 1.10 $ 1.40 Diluted Income per Common Unit: Common Unitholders’ interest in net income $ 4,394 $ 3,469 $ 4,330 Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units (1) (1) (2) Diluted income available to Common Unitholders $ 4,393 $ 3,468 $ 4,328 Weighted average common units 3,395.1 3,161.7 3,086.8 Dilutive effect of unvested unit awards 25.4 15.5 10.2 Weighted average common units, assuming dilutive effect of unvested unit awards 3,420.5 3,177.2 3,097.0 Diluted income per common unit $ 1.28 $ 1.09 $ 1.40

Debt Obligations Debt Obligatio

Debt Obligations Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2024
Debt Obligations [Abstract]
Schedule of debt obligations	Our debt obligations consist of the following: December 31, 2024 2023 Energy Transfer Indebtedness 5.875% Senior Notes due January 15, 2024 (1) $ — $ 23 5.875% Senior Notes due January 15, 2024 (1) — 1,127 7.60% Senior Notes due February 1, 2024 (1) — 82 4.90% Senior Notes due February 1, 2024 (1) — 350 4.25% Senior Notes due April 1, 2024 (1) — 500 4.50% Senior Notes due April 15, 2024 (1) — 750 3.90% Senior Notes due May 15, 2024 (1) — 600 9.00% Debentures due November 1, 2024 (1) — 65 4.05% Senior Notes due March 15, 2025 (2) 1,000 1,000 5.75% Senior Notes due April 1, 2025 (1) — 500 2.90% Senior Notes due May 15, 2025 (2) 1,000 1,000 5.95% Senior Notes due December 1, 2025 (2) 400 400 4.75% Senior Notes due January 15, 2026 1,000 1,000 3.90% Senior Notes due July 15, 2026 550 550 6.05% Senior Notes due December 1, 2026 1,000 1,000 4.40% Senior Notes due March 15, 2027 700 700 4.20% Senior Notes due April 15, 2027 600 600 6.05% Senior Notes due May 1, 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 1,000 4.95% Senior Notes due May 15, 2028 800 800 4.95% Senior Notes due June 15, 2028 1,000 1,000 6.10% Senior Notes due December 1, 2028 500 500 6.00% Senior Notes due February 1, 2029 700 700 8.00% Senior Notes due April 1, 2029 (1) — 450 5.25% Senior Notes due April 15, 2029 1,500 1,500 5.25% Senior Notes due July 1, 2029 1,000 — 7.00% Senior Notes due July 15, 2029 66 66 4.15% Senior Notes due September 15, 2029 547 547 8.25% Senior Notes due November 15, 2029 33 33 8.25% Senior Notes due November 15, 2029 267 267 3.75% Senior Note due May 15, 2030 1,500 1,500 6.40% Senior Notes due December 1, 2030 1,000 1,000 7.38% Senior Notes due April 1, 2031 600 600 5.75% Senior Notes due February 15, 2033 1,500 1,500 4.05% Tax-Exempt Bonds due June 1, 2033 225 225 6.55% Senior Notes due December 1,2033 1,500 1,500 5.55% Senior Notes due May 15, 2034 1,250 — 5.60% Senior Notes due September 1, 2034 1,250 — 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 5.95% Senior Notes due May 15, 2054 1,750 — 6.05% Senior Notes due September 1, 2054 1,250 — 8.00% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due May 15, 2054 800 — 7.125% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due October 1, 2054 400 — Floating Rate Junior Subordinated Notes due November 1, 2066 600 600 Five-Year Credit Facility due April 11, 2029 2,759 1,412 Unamortized premiums, discounts and fair value adjustments, net 62 128 Deferred debt issuance costs (250) (197) 48,840 44,359 Subsidiary Indebtedness Transwestern Debt 5.66% Senior Notes due December 9, 2024 (1) — 175 6.16% Senior Notes due May 24, 2037 75 75 75 250 Bakken Project Debt 3.90% Senior Notes due April 1, 2024 (1) — 1,000 4.625% Senior Notes due April 1, 2029 850 850 Unamortized premiums, discounts and fair value adjustments, net — (1) Deferred debt issuance costs (3) (4) 847 1,845 Sunoco LP Debt 5.750% Senior Notes due October 1, 2025 (2)(3) 600 — 6.000% Senior Notes due June 1, 2026 (3) 500 — 6.000% Senior Notes due April 15, 2027 600 600 5.625% Senior Notes due April 28, 2027 (3) 550 — 5.875% Senior Notes due March 15, 2028 400 400 7.000% Senior Notes due September 25, 2028 500 500 7.000% Senior Notes due May 1, 2029 750 — 4.500% Senior Notes due May 15, 2029 800 800 4.500% Senior Notes due April 30, 2030 800 800 6.375% Senior Notes due October 1, 2030 (3) 600 — 7.250% Senior Notes due May 1, 2032 750 — GoZone Bonds (2)(3) 322 — Sunoco LP Credit Facility due May 3, 2029 203 411 Lease-related obligations 132 94 Unamortized premiums, discounts and fair value adjustments, net 15 — Deferred debt issuance costs (37) (25) 7,485 3,580 USAC Debt 6.875% Senior Notes due April 1, 2026 (1) — 725 6.875% Senior Notes due September 1, 2027 750 750 7.125% Senior Notes due March 15, 2029 1,000 — USAC Credit Facility due December 8, 2026 772 872 Deferred debt issuance costs (20) (11) 2,502 2,336 Other long-term debt 11 18 Total debt 59,760 52,388 Less: Current maturities of long-term debt 8 1,008 Long-term debt, less current maturities $ 59,752 $ 51,380 (1) These notes were redeemed in 2024. (2) As of December 31, 2024, these obligations (including $75 million of Sunoco LP’s GoZone bonds) were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. (3) Sunoco LP assumed $2.57 billion aggregate principal amount of NuStar senior notes and bonds in connection with the closing of the NuStar acquisition in May 2024.
Future maturities of long-term debt	The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $233 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: 2025 $ 3,082 2026 3,826 2027 5,554 2028 4,203 2029 10,476 Thereafter 32,852 Total $ 59,993
Schedule of Debt Conversions	The following table summarizes the GoZone Bonds outstanding as of December 31, 2024: Series Date Issued Amount Outstanding Interest Rate Mandatory Purchase Date Original Redemption Date Maturity Date Series 2008 June 26, 2008 56 6.10 % June 1, 2030 n/a June 1, 2038 Series 2010 July 15, 2010 100 6.35 % n/a June 1, 2030 July 1, 2040 Series 2010A October 7, 2010 43 6.35 % n/a June 1, 2030 October 1, 2040 Series 2010B December 29, 2010 48 6.10 % June 1, 2030 n/a December 1, 2040 Series 2011 August 9, 2011 75 5.85 % June 1, 2025 n/a August 1, 2041

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2024
Change In ETE Common Units	The change in Energy Transfer Common Units during the years ended December 31, 2024, 2023 and 2022 was as follows: Years Ended December 31, 2024 2023 2022 Number of Common Units, beginning of period 3,367.5 3,094.4 3,082.5 Common Units issued in mergers and acquisitions (1) 50.8 260.2 — Issuance of Common Units (2) 12.7 12.9 11.9 Number of Common Units, end of period 3,431.0 3,367.5 3,094.4 (1) Includes common units issued related to our acquisitions of WTG Midstream in 2024 and of Crestwood and Lotus Midstream in 2023. (2) Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The following table presents the components of AOCI, net of tax: December 31, 2024 2023 Available-for-sale securities $ 20 $ 13 Foreign currency translation adjustment (6) (5) Actuarial gain related to pensions and other postretirement benefits 45 6 Investments in unconsolidated affiliates, net 14 14 Total AOCI, net of tax $ 73 $ 28 The following table sets forth the tax amounts included in the respective components of other comprehensive income: December 31, 2024 2023 Available-for-sale securities $ (3) $ (3) Foreign currency translation adjustment 2 6 Total $ (1) $ 3
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 Series I Total 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 Distributions to partners (96) (36) (40) (36) (61) (34) (106) (59) — (468) Units issued in Crestwood acquisition — — — — — — — — 413 413 Net income 86 36 38 37 61 34 106 59 6 463 Balance, December 31, 2023 948 556 438 435 786 496 1,488 893 419 6,459 Distributions to partners (56) (36) (11) (11) (30) (34) (106) (59) (35) (378) Redemption of Preferred Units (950) — (450) (445) (800) — — — — (2,645) Other, net 13 — 11 10 20 — — — — 54 Net Income 45 36 12 11 24 34 106 59 35 362 Balance, December 31, 2024. $ — $ 556 $ — $ — $ — $ 496 $ 1,488 $ 893 $ 419 $ 3,852
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 Payment Date Rate December 31, 2021 February 18, 2022 $ 0.8255 March 31, 2022 May 19, 2022 0.8255 June 30, 2022 August 19, 2022 0.8255 September 30, 2022 November 18, 2022 0.8255 December 31, 2022 February 21, 2023 0.8255 March 31, 2023 May 22, 2023 0.8420 June 30, 2023 August 21, 2023 0.8420 September 30, 2023 November 20, 2023 0.8420 December 31, 2023 February 20, 2024 0.8420 March 31, 2024 May 20, 2024 0.8756 June 30, 2024 August 19, 2024 0.8756 September 30, 2024 November 19, 2024 0.8756 December 31, 2024 February 19, 2025 0.8865
Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution [Table Text Block]	The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Marginal Percentage Interest in Distributions Total Quarterly Distribution Target Amount Common Unitholders Holder of IDRs Minimum Quarterly Distribution $0.4375 100% —% First Target Distribution $0.4375 to $0.503125 100% —% Second Target Distribution $0.503125 to $0.546875 85% 15% Third Target Distribution $0.546875 to $0.656250 75% 25% Thereafter Above $0.656250 50% 50%
USAC [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	USAC Cash Distributions Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2024, USAC had approximately 117 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 Payment Date Rate December 31, 2021 February 4, 2022 $ 0.5250 March 31, 2022 May 6, 2022 0.5250 June 30, 2022 August 5, 2022 0.5250 September 30, 2022 November 4, 2022 0.5250 December 31, 2022 February 3, 2023 0.5250 March 31, 2023 May 5, 2023 0.5250 June 30, 2023 August 4, 2023 0.5250 September 30, 2023 November 3, 2023 0.5250 December 31, 2023 February 2, 2024 0.5250 March 31, 2024 May 3, 2024 0.5250 June 30, 2024 August 2, 2024 0.5250 September 30, 2024 November 1, 2024 0.5250 December 31, 2024 February 7, 2025 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, 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 March 31, 2023 May 8, 2023 May 22, 2023 0.3075 June 30, 2023 August 14, 2023 August 21, 2023 0.3100 September 30, 2023 October 30, 2023 November 20, 2023 0.3125 December 31, 2023 February 7, 2024 February 20, 2024 0.3150 March 31, 2024 May 13, 2024 May 20, 2024 0.3175 June 30, 2024 August 9, 2024 August 19, 2024 0.3200 September 30, 2024 November 8, 2024 November 19, 2024 0.3225 December 31, 2024 February 7, 2025 February 19, 2025 0.3250
Preferred Units [Member]
Distributions Made to Limited Partner, by Distribution [Table Text Block]	Distributions on Energy Transfer’s preferred units declared and/or paid by Energy Transfer were as follows: Period Ended Record Date Payment Date Series A Series B (1) Series C Series D Series E Series F (1) Series G (1) Series H (1) Series I December 31, 2021 February 1, 2022 February 15, 2022 $ 31.25 $ 33.125 $ 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 33.125 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 33.125 0.4609 0.4766 0.4750 — — — — March 31, 2023 May 1, 2023 May 15, 2023 21.98 — 0.4609 0.4766 0.4750 33.7500 35.63 32.50 — June 30, 2023 August 1, 2023 August 15, 2023 23.89 33.125 0.6294 0.4766 0.4750 — — — — September 30, 2023 November 1, 2023 November 15, 2023 24.67 — 0.6489 0.6622 0.4750 33.7500 35.63 32.50 — December 31, 2023 February 1, 2024 February 15, 2024 24.71 33.125 0.6075 0.6199 0.4750 — — — 0.2111 March 31, 2024 May 1, 2024 May 15, 2024 23.99 — — — 0.4750 33.7500 35.63 32.50 0.2111 June 30, 2024 August 1, 2024 August 15, 2024 9.88 33.125 — — — — — — 0.2111 (2) September 30, 2024 November 1, 2024 November 15, 2024 — — — — — 33.7500 35.63 32.50 0.2111 (2) December 31, 2024 February 1, 2025 February 15, 2024 — 33.125 — — — — — — 0.2111 (2) (1) Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Distributions on the Series B Preferred Units will begin to be paid quarterly on February 15, 2028. (2) For the period ended December 31, 2024, the cash distribution for the Series I Preferred Units was paid on February 14, 2025 to unitholders of record as of the close of business on February 4, 2025. For the period ended September 30, 2024, the cash distribution for the Series I Preferred Units was paid on November 14, 2024 to unitholders of record as of the close of business on November 4, 2024. For the period ended June 30, 2024, the cash distribution for the Series I Preferred Units was paid on August 14, 2024 to unitholders of record as of the close of business on August 2, 2024.

Equity Incentive Plans (Tables)

Equity Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 2022 Sunoco LP $ 55.24 $ 53.37 $ 43.54 USAC 22.37 23.13 18.31
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, 2023 39.1 $ 10.84 Awards granted 8.6 18.95 Awards vested (10.5) 9.55 Awards forfeited (1.1) 11.13 Unvested awards as of December 31, 2024 36.1 $ 13.18
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 Weighted Average Number of Weighted Average Unvested awards as of December 31, 2023 1.6 $ 41.08 1.9 $ 17.08 Awards granted 0.6 55.24 0.3 22.37 Awards vested (0.4) 34.76 (0.5) 15.40 Awards forfeited (0.1) 42.06 (0.1) 18.09 Unvested awards as of December 31, 2024 1.7 $ 47.55 1.6 $ 19.31

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 2022 Current expense: Federal $ 198 $ 56 $ — State 66 44 17 Foreign 1 — — Total 265 100 17 Deferred expense (benefit): Federal 175 227 239 State 101 (24) (58) Foreign — — 6 Total 276 203 187 Total income tax expense $ 541 $ 303 $ 204
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2024, 2023 and 2022 is as follows: Years Ended December 31, 2024 2023 2022 Income tax expense at United States statutory rate $ 1,492 $ 1,175 $ 1,275 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax (1,084) (884) (1,086) Noncontrolling interests — — 26 State tax, net of federal tax benefit 113 47 19 Statutory rate change — (10) (42) Valuation allowance — (3) (4) Uncertain tax positions 21 (14) (3) Non-deductible goodwill 9 — — Dividend received deduction (3) (3) (3) Foreign taxes — — 6 Other (7) (5) 16 Income tax expense $ 541 $ 303 $ 204
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The following table summarizes the principal components of the deferred tax assets (liabilities) as follows: December 31, 2024 2023 Deferred income tax assets: Net operating losses and other carryforwards $ 197 $ 371 Other 42 46 Total deferred income tax assets 239 417 Deferred income tax liabilities: Property, plant and equipment (224) (232) Investments in affiliates (4,098) (4,003) Trademarks (82) (91) Other (18) (22) Total deferred income tax liabilities (4,422) (4,348) Net deferred income taxes $ (4,183) $ (3,931)
ScheduleOfUnrecognizedTaxBenefits [Table Text Block]	The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2024 2023 2022 Balance at beginning of year $ 40 $ 52 $ 56 Additions attributable to tax positions taken in prior years 34 — — Reduction attributable to tax positions taken in prior years — (9) (4) Settlements — (3) — Balance at end of year $ 74 $ 40 $ 52
Schedule of Income before Income Tax, Domestic and Foreign	The Partnership’s income (loss) before income tax expense by geographic area is shown in the table below: Years Ended December 31, 2024 2023 2022 United States $ 7,101 $ 5,602 $ 6,073 Foreign 5 (5) (1) Total $ 7,106 $ 5,597 $ 6,072

Regulatory Matters, Commitmen_2

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)	12 Months Ended
	Dec. 31, 2024
Environmental Exit Costs by Cost [Table Text Block]	The following table reflects the amounts of accrued liabilities December 31, 2024 2023 Current $ 51 $ 42 Non-current 227 235 Total environmental liabilities $ 278 $ 277
Right of way (20 to 83 years)
Other Commitments	The following table reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations: Years Ended December 31, 2024 2023 2022 ROW expense $ 72 $ 68 $ 64

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2022 $ 615 Additions 1,254 Revenue recognized (1,120) Balance, December 31, 2023 749 Additions 1,256 Revenue recognized (1,246) Balance, December 31, 2024 $ 759
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]	As of December 31, 2024, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $37.70 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below: Years Ending December 31, 2025 2026 2027 Thereafter Total Revenue expected to be recognized on contracts with customers existing as of December 31, 2024 $ 7,808 $ 6,830 $ 5,591 $ 17,474 $ 37,703
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, 2024 and 2023 were as follows: December 31, 2024 2023 Contract Balances Contract assets $ 288 $ 256 Accounts receivable from contracts with customers 1,084 809 Contract liabilities 39 —

Lease Accounting (Tables)

Lease Accounting (Tables)	12 Months Ended
	Dec. 31, 2024
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 sheets as of December 31, 2024 and 2023 were as follows: December 31, 2024 2023 Operating leases: Lease right-of-use assets, net $ 753 $ 797 Operating lease current liabilities 67 56 Accrued and other current liabilities 5 Non-current operating lease liabilities 730 778 Finance leases: Property, plant and equipment, net $ 1 $ 1 Lease right-of-use assets, net 56 29 Current maturities of long-term debt 8 8 Long-term debt, less current maturities 50 19 Other non-current liabilities 1 —
Lease, Cost [Table Text Block]	The components of lease expense for the years ended December 31, 2024 and 2023 were as follows: Year Ended December 31, Income Statement Location 2024 2023 Operating lease costs: Operating lease cost Cost of goods sold $ 1 $ 1 Operating lease cost Operating expenses 71 69 Operating lease cost Selling, general and administrative 19 18 Total operating lease costs 91 88 Finance lease costs: Amortization of lease assets Depreciation, depletion and amortization 2 — Interest on lease liabilities Interest expense, net of capitalized interest 2 — Total finance lease costs 4 — Short-term lease cost Operating expenses 69 38 Variable lease cost Operating expenses 19 16 Lease costs, gross 183 142 Less: Sublease income Other revenue 45 42 Lease costs, net $ 138 $ 100
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2024 and 2023 were as follows: December 31, 2024 2023 Weighted-average remaining lease term (years): Operating leases 18 21 Finance leases 15 12 Weighted-average discount rate (%): Operating leases 6 % 6 % Finance leases 6 % 5 % Maturities of lease liabilities as of December 31, 2024 are as follows: Operating leases Finance leases Total 2025 $ 99 $ 10 $ 109 2026 92 6 98 2027 83 6 89 2028 81 5 86 2029 75 4 79 Thereafter 812 56 868 Total lease payments 1,242 87 1,329 Less: present value discount 445 28 473 Present value of lease liabilities $ 797 $ 59 $ 856
Schedule of additional lease information [Table Text Block]	Cash flows and non-cash activity related to leases for the years ended December 31, 2024 and 2023 were as follows: Year Ended December 31, 2024 2023 Operating cash flows from operating leases $ (94) $ (139) Operating cash flows from finance leases (2) — Financing cash flows from finance leases (6) — Lease assets obtained in exchange for new finance lease liabilities 1 18 Lease assets obtained in exchange for new operating lease liabilities 6 5
Lessor, Operating Lease, Payments to be Received, Maturity [Table Text Block]	Sunoco LP’s future minimum operating lease payments receivable as of December 31, 2024 are as follows: Lease Payments 2025 $ 139 2026 121 2027 93 2028 73 2029 61 Thereafter 356 Total undiscounted cash flows $ 843

Derivative Assets And Liabili_2

Derivative Assets And Liabilities (Tables)	12 Months Ended
	Dec. 31, 2024
General Discussion of Derivative Instruments and Hedging Activities [Abstract]
Offsetting Assets [Table Text Block]	Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 2024 December 31, 2023 December 31, 2024 December 31, 2023 Derivatives without offsetting agreements Derivative assets (liabilities) $ — $ 6 $ — $ (4) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 51 132 (57) (80) Broker cleared derivative contracts Other current assets (liabilities) 212 478 (236) (380) 263 616 (293) (464) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (42) (72) 42 72 Counterparty netting Other current assets (liabilities) (204) (368) 204 368 Total net derivatives $ 17 $ 176 $ (47) $ (24)
Outstanding Commodity-Related Derivatives	The following table details our outstanding commodity-related derivatives: December 31, 2024 December 31, 2023 Notional Maturity Notional Maturity Mark-to-Market Derivatives Natural Gas (BBtu): Fixed Swaps/Futures 6,630 2025-2026 5,247 2024-2026 Basis Swaps IFERC/NYMEX 3,490 2025-2027 (46,975) 2024-2025 Swing Swaps (156,820) 2025-2027 (97,728) 2024-2025 Options – Puts — — 1,900 2024 Options - Calls — — 250 2024 Forward Physical Contracts (1) — — (1,751) 2024-2026 Power (Megawatt): Forwards 6,040 2025-2029 155,600 2024-2029 Futures (140,137) 2025-2026 (464,897) 2024 Options – Puts (17,600) 2025 136,000 2024 Crude (MBbls): Forwards/Swaps (22,512) 2025-2026 (2,674) 2024-2025 Option - Puts — — (15) 2024 Option - Calls — — (20) 2024 NGL/Refined Products (MBbls): Forwards/Swaps (15,063) 2025-2027 (13,870) 2024-2027 Option - Puts (9) 2025-2026 121 2024-2026 Option - Calls (14) 2025-2026 (43) 2024-2026 Futures (1,763) 2025-2026 (4,548) 2024-2025 Fair Value Hedging Derivatives Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (47,170) 2025 (39,013) 2024 Fixed Swaps/Futures (47,170) 2025 (39,013) 2024 Hedged Item – Inventory 44,170 2025 39,013 2024 (1)
Interest Rate Swaps Outstanding	The following table summarizes USAC’s interest rate swap which is no longer outstanding as of December 31, 2024, and which was not designated as a hedge for accounting purposes. Term Type Notional Amount Outstanding December 31, 2024 December 31, 2023 December 2025 (1) Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR $ — $ 700 (1) In August 2024, USAC elected to terminate the outstanding interest rate swap.
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, 2024 December 31, 2023 December 31, 2024 December 31, 2023 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 3 $ 51 $ (7) $ (6) 3 51 (7) (6) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 209 427 (229) (374) Commodity derivatives 51 132 (57) (80) Interest rate derivatives — 6 — (4) 260 565 (286) (458) Total derivatives $ 263 $ 616 $ (293) $ (464)
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, 2024 2023 2022 Derivatives not designated as hedging instruments: Commodity derivatives Cost of products sold $ 57 $ 47 $ 124 Interest rate derivatives Gains on interest rate derivatives 6 36 293 Total $ 63 $ 83 $ 417

Retirement Benefits Retirement

Retirement Benefits Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2024
Retirement Benefits [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	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, 2024 December 31, 2023 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 $ 23 $ 17 $ 138 $ 22 $ 19 $ 148 Service cost 1 — — — — — Interest cost 6 1 7 1 1 6 Amendments — — (11) — — — Benefits paid, net (37) (3) (13) (1) (3) (13) Actuarial gain and other 13 1 (6) 1 — (3) NuStar acquisition 152 — 12 — — — Benefit obligation at end of period 158 16 127 23 17 138 Change in plan assets: Fair value of plan assets at beginning of period 22 — 277 20 — 259 Return on plan assets and other 13 — 29 2 — 29 Employer contributions 5 — 2 1 — 2 Benefits paid, net (36) — (13) (1) — (13) NuStar acquisition 178 — — — — — Fair value of plan assets at end of period 182 — 295 22 — 277 Amount underfunded (overfunded) at end of period $ (24) $ 16 $ (168) $ 1 $ 17 $ (139) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ 24 $ — $ 185 $ — $ — $ 155 Current liabilities — (3) (3) — (3) (2) Non-current liabilities — (13) (14) (1) (14) (14) $ 24 $ (16) $ 168 $ (1) $ (17) $ 139 Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of: Net actuarial gain (loss) $ (9) $ (1) $ (59) $ — $ (2) $ (12) Prior service credit — — 25 — — (3) $ (9) $ (1) $ (34) $ — $ (2) $ (15)
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, 2024 December 31, 2023 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 22 $ 16 N/A $ 23 $ 15 N/A Accumulated benefit obligation 158 16 $ 127 23 17 $ 138 Fair value of plan assets 182 — 295 22 — 277
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, 2024 2023 Health care cost trend rate 7.44 % 7.42 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.09 % 5.17 % Year that the rate reaches the ultimate trend rate 2032 2031
Schedule of Expected Benefit Payments [Table Text Block]	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: Pension Benefits - Funded Plans Pension Benefits - Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2025 $ 72 $ 3 $ 14 2026 4 2 13 2027 4 2 12 2028 4 2 12 2029 5 1 11 2030 – 2034 26 5 46
Schedule of Net Benefit Costs [Table Text Block]	Components of Net Periodic Benefit Cost December 31, 2024 December 31, 2023 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Service cost $ 1 $ — $ — $ — Interest cost 6 7 1 6 Expected return on plan assets (8) (13) (1) (12) Prior service cost amortization (2) 2 — 2 Actuarial gain amortization — (1) — (1) Settlements 2 — — — Net periodic benefit cost $ (1) $ (5) $ — $ (5)
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, 2024 December 31, 2023 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 4.80 % 4.40 % 2.70 % 4.62 % The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the following table: December 31, 2024 December 31, 2023 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 5.40 % 4.40 % 2.70 % 4.93 % Expected return on assets: Tax exempt accounts 7.00 % 7.00 % 7.00 % 7.00 % Taxable accounts 4.26 % 4.75 % — 4.75 %
Schedule of Changes in Fair Value of Plan 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, 2024 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Cash and cash equivalents $ 81 $ 81 $ — $ — Mutual funds (1) 65 21 44 — Fixed income securities 36 36 — — Total $ 182 $ 138 $ 44 $ — (1) Comprised of approximately 100% equities as of December 31, 2024. Fair Value Measurements at December 31, 2023 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Cash and cash equivalents $ 1 $ 1 $ — $ — Mutual funds (1) 21 21 — — Total $ 22 $ 22 $ — $ — (1) Comprised of approximately 100% equities as of December 31, 2023. The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2024 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 8 $ 8 $ — $ — Mutual funds (1) 189 189 — — Fixed income securities 98 — 98 — Total $ 295 $ 197 $ 98 $ — (1) Primarily composed of market index funds as of December 31, 2024. Fair Value Measurements at December 31, 2023 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 13 $ 13 $ — $ — Mutual funds (1) 166 166 — — Fixed income securities 98 — 98 — Total $ 277 $ 179 $ 98 $ — (1) Primarily composed of market index funds as of December 31, 2023.

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2024
Financial Information By Segment	The following tables present financial information by segment: Years Ended December 31, 2024 2023 2022 Revenues: Intrastate transportation and storage: Revenues from external customers $ 2,750 $ 3,222 $ 6,954 Intersegment revenues 303 740 864 3,053 3,962 7,818 Interstate transportation and storage: Revenues from external customers 2,270 2,328 2,185 Intersegment revenues 26 47 66 2,296 2,375 2,251 Midstream: Revenues from external customers 3,283 2,911 4,114 Intersegment revenues 7,916 7,495 12,987 11,199 10,406 17,101 NGL and refined products transportation and services: Revenues from external customers 20,981 18,413 21,414 Intersegment revenues 3,549 3,490 4,243 24,530 21,903 25,657 Crude oil transportation and services: Revenues from external customers 28,528 26,534 25,980 Intersegment revenues 11 2 2 28,539 26,536 25,982 Investment in Sunoco LP: Revenues from external customers 22,666 23,026 25,677 Intersegment revenues 27 42 52 22,693 23,068 25,729 Investment in USAC: Revenues from external customers 909 824 689 Intersegment revenues 41 22 16 950 846 705 All other: Revenues from external customers 1,284 1,328 2,863 Intersegment revenues 463 470 711 1,747 1,798 3,574 Eliminations (12,336) (12,308) (18,941) Total revenues $ 82,671 $ 78,586 $ 89,876 Years Ended December 31, 2024 2023 2022 Cost of products sold: Intrastate transportation and storage $ 1,390 $ 2,616 $ 6,000 Interstate transportation and storage 9 6 25 Midstream 6,637 6,503 12,682 NGL and refined products transportation and services 19,406 17,049 21,656 Crude oil transportation and services 24,407 23,071 22,917 Investment in Sunoco LP 20,595 21,703 24,350 Investment in USAC 146 137 111 All other 1,709 1,740 3,328 Eliminations (12,324) (12,284) (18,837) Total cost of products sold $ 61,975 $ 60,541 $ 72,232 Years Ended December 31, 2024 2023 2022 Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses: Intrastate transportation and storage $ 246 $ 279 $ 334 Interstate transportation and storage 807 746 791 Midstream 1,550 1,204 1,087 NGL and refined products transportation and services 957 892 962 Crude oil transportation and services 852 699 645 Investment in Sunoco LP 611 420 396 Investment in USAC 166 147 123 All other 20 40 80 Eliminations (112) (112) (170) Total operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses $ 5,097 $ 4,315 $ 4,248 Years Ended December 31, 2024 2023 2022 Depreciation, depletion and amortization: Intrastate transportation and storage $ 216 $ 214 $ 209 Interstate transportation and storage 575 563 513 Midstream 1,719 1,451 1,351 NGL and refined products transportation and services 1,026 915 865 Crude oil transportation and services 965 740 663 Investment in Sunoco LP 368 187 193 Investment in USAC 265 246 237 All other 31 69 133 Total depreciation, depletion and amortization $ 5,165 $ 4,385 $ 4,164 Years Ended December 31, 2024 2023 2022 Selling, general and administrative expenses, excluding non-cash compensation and accretion expenses: Intrastate transportation and storage $ 50 $ 51 $ 53 Interstate transportation and storage 129 115 131 Midstream 199 199 186 NGL and refined products transportation and services 160 157 127 Crude oil transportation and services 149 120 224 Investment in Sunoco LP 266 113 111 Investment in USAC 54 51 45 All other 62 85 60 Total selling, general and administrative expenses, excluding non-cash compensation and accretion expenses $ 1,069 $ 891 $ 937 Years Ended December 31, 2024 2023 2022 Equity in earnings (losses) of unconsolidated affiliates (1) : Intrastate transportation and storage $ 16 $ 17 $ 17 Interstate transportation and storage 241 260 175 Midstream 13 15 19 NGL and refined products transportation and services 83 76 44 Crude oil transportation and services 21 11 (2) All other 5 4 4 Total equity in earnings of unconsolidated affiliates $ 379 $ 383 $ 257 (1) Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation. Years Ended December 31, 2024 2023 2022 Other income (expense) (1) : Intrastate transportation and storage $ (9) $ 95 $ (35) Interstate transportation and storage 477 501 449 Midstream 97 25 64 NGL and refined products transportation and services 172 89 113 Crude oil transportation and services 46 35 (9) Investment in Sunoco LP 236 132 47 Investment in USAC — 1 — All other 35 (8) 14 Eliminations (101) (11) (9) Total other income (expense) $ 953 $ 859 $ 634 (1) Other income and expense include, if applicable to a segment, Adjusted EBITDA related to unconsolidated affiliates, unrealized gains and losses on commodity risk management activities and other items. For the investment in Sunoco LP segment, this also includes inventory valuation adjustments. December 31, 2024 2023 2022 Segment assets: Intrastate transportation and storage $ 6,289 $ 6,112 $ 6,609 Interstate transportation and storage 17,656 17,708 17,979 Midstream 30,473 25,592 21,851 NGL and refined products transportation and services 27,445 27,214 27,903 Crude oil transportation and services 25,231 25,464 19,200 Investment in Sunoco LP 14,375 6,826 6,830 Investment in USAC 2,746 2,737 2,666 All other and eliminations 1,165 2,045 2,605 Total segment assets $ 125,380 $ 113,698 $ 105,643 Years Ended December 31, 2024 2023 2022 Additions to property, plant and equipment (1) : Intrastate transportation and storage $ 118 $ 93 $ 179 Interstate transportation and storage 332 383 644 Midstream 1,323 832 1,004 NGL and refined products transportation and services 1,424 679 507 Crude oil transportation and services 423 266 246 Investment in Sunoco LP 344 215 186 Investment in USAC 276 300 169 All other 342 100 91 Total additions to property, plant and equipment $ 4,582 $ 2,868 $ 3,026 (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, 2024 2023 2022 Investments in unconsolidated affiliates (1) : Intrastate transportation and storage $ 150 $ 144 $ 139 Interstate transportation and storage 2,350 2,179 2,201 Midstream 132 141 54 NGL and refined products transportation and services 383 390 398 Crude oil transportation and services 193 187 48 All other 58 56 53 Total investments in unconsolidated affiliates $ 3,266 $ 3,097 $ 2,893 (1) Amounts reflected above exclude Sunoco LP’s investments in the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation. Years Ended December 31, 2024 2023 2022 Segment Adjusted EBITDA: Intrastate transportation and storage $ 1,358 $ 1,111 $ 1,396 Interstate transportation and storage 1,828 2,009 1,753 Midstream 2,910 2,525 3,210 NGL and refined products transportation and services 4,179 3,894 3,025 Crude oil transportation and services 3,177 2,681 2,187 Investment in Sunoco LP 1,457 964 919 Investment in USAC 584 512 426 All Other (10) 2 177 Adjusted EBITDA (consolidated) $ 15,483 $ 13,698 $ 13,093 Years Ended December 31, 2024 2023 2022 Reconciliation of net income to Adjusted EBITDA: Net income $ 6,565 $ 5,294 $ 5,868 Depreciation, depletion and amortization 5,165 4,385 4,164 Interest expense, net of interest capitalized 3,125 2,578 2,306 Income tax expense 541 303 204 Impairment losses and other 52 12 386 Gains on interest rate derivatives (6) (36) (293) Non-cash compensation expense 151 130 115 Unrealized (gains) losses on commodity risk management activities 56 (3) (42) Inventory valuation adjustments (Sunoco LP) 86 114 (5) (Gains) losses on extinguishments of debt 12 (2) — Adjusted EBITDA related to unconsolidated affiliates 692 691 565 Equity in earnings of unconsolidated affiliates (379) (383) (257) Non-operating litigation-related loss — 627 — Gain on sale of West Texas assets (Sunoco LP) (586) — — Other, net 9 (12) 82 Adjusted EBITDA (consolidated) $ 15,483 $ 13,698 $ 13,093

Operations And Organization (Na

Operations And Organization (Narrative) (Details)	12 Months Ended
	Dec. 31, 2024 shares	Dec. 31, 2023 shares
Incentive Distribution Rights	0%
Issued	3,431,088,022	3,367,525,806
Number of States in which Entity Operates	40
Number of convenience stores	7,400
Terminals
Number of Real Estate Properties	100
Miles of pipeline [Member]
Number of Real Estate Properties	14,000
Sunoco LP [Member]
Incentive Distribution Rights	10,000%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	28,500,000
USAC [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	46,100,000
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	100%

Estimates, Significant Accoun_4

Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) - USD ($) $ in Millions					3 Months Ended	12 Months Ended
	May 03, 2024	[1]	Nov. 03, 2023	Apr. 01, 2022	Dec. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Impairment losses and other						$ 52	$ 12	$ 386
Asset Retirement Obligation					$ 418	418	410
Oil and Gas, Cost Incurred, Asset Retirement Obligation						11	10	4
Long-term Debt, Fair Value					59,010	59,010	51,930
Goodwill, Acquired During Period						16	1,455
Goodwill					3,903	3,903	4,019	2,566
Long-term Debt					59,760	59,760	52,388
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net						0
Inventory Write-down						86	114	5
Revenues						82,671	78,586	89,876
Goodwill, Written off Related to Sale of Business Unit						138
Other (5 to 20 years)
Asset Retirement Obligation					$ 31	31	31
Related Party
Revenues						$ 603	626	391
Minimum [Member] | Product storage and related facilities
Property, plant and equipment, useful life, minimum (years)					2 years	2 years
Maximum [Member] | Product storage and related facilities
Property, plant and equipment, useful life, minimum (years)					83 years	83 years
Midstream
Goodwill, Acquired During Period						$ 0	601
Goodwill					$ 617	617	601	0
Goodwill, Written off Related to Sale of Business Unit						0
All Other
Goodwill, Acquired During Period						0	0
Goodwill					82	82	82	82
Goodwill, Written off Related to Sale of Business Unit						0
Investment in Sunoco LP
Goodwill, Acquired During Period						16	0
Goodwill					1,477	1,477	1,599	1,601
Goodwill, Written off Related to Sale of Business Unit						138
Retail Marketing [Member]
Excise Taxes Collected						164	274	285
Interstate Transportation and Storage
Goodwill, Acquired During Period						0	0
Goodwill					0	0	0	0
Goodwill, Written off Related to Sale of Business Unit						0
Investment in USAC
Goodwill, Acquired During Period						0	0
Goodwill					0	0	0	0
Goodwill, Written off Related to Sale of Business Unit						0
Crude Oil Transportation and Services
Goodwill, Acquired During Period						0	663
Goodwill					841	841	853	190
Goodwill, Written off Related to Sale of Business Unit						0
Intrastate Transportation and Storage
Goodwill, Acquired During Period						0	0
Goodwill					0	0	0	0
Goodwill, Written off Related to Sale of Business Unit						0
NGL and Refined Products Transportation and Services
Goodwill, Acquired During Period						0	191
Goodwill					886	886	884	693
Goodwill, Written off Related to Sale of Business Unit						0
Sunoco LP [Member]
Goodwill, Acquired During Period				$ 20
Long-term Debt					7,485	7,485	3,580
Inventory, LIFO Reserve					316	316	230
USAC [Member]
Impairment losses and other						1	$ 12	$ 1
Crestwood Acquisition
Goodwill, Acquired During Period			$ 1,455		$ 1,460
Nustar Acquisition
Goodwill, Acquired During Period	$ 16					$ 16
[1] Goodwill primarily represents expected commercial and operational synergies. None of the goodwill recorded as a result of this transaction is deductible for tax purposes.

Estimates (Schedule Of Net Chan

Estimates (Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Supplemental Cash Flow Information [Abstract]
Accounts receivable	$ (775)	$ (171)	$ (863)
Accounts receivable from related companies	15	(5)	23
Inventories	(735)	35	(361)
Other current assets	(82)	(221)	326
Other non-current assets, net	(166)	(125)	146
Accounts payable	1,315	(501)	25
Accounts payable to related companies	(35)	(38)	6
Accrued and other current liabilities	166	209	131
Other non-current liabilities	(123)	(33)	66
Derivative assets and liabilities, net	60	(43)	(349)
Net change in operating assets and liabilities, net of effects of acquisitions and divestitures	$ (196)	$ (451)	$ (1,502)

Estimates (Schedule Of Non-Cash

Estimates (Schedule Of Non-Cash Investing And Financing Activities) (Details) - USD ($) $ in Millions			12 Months Ended
		May 03, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
NON-CASH INVESTING ACTIVITIES: [Abstract]
Cash paid for interest, net of interest capitalized			$ 2,884	$ 2,298	$ 2,167
Cash paid for income taxes, net of refunds (excluding $47 million of federal tax credits purchased from non-governmental third parties by Sunoco LP in 2024)			206	103	54
Accrued capital expenditures			688	442	575
Lease assets obtained in exchange for new lease liabilities			7	23	42
Gain from subsidiary issuances of common units			301	0	0
Repayments of Senior Debt			749	0	0
Repayments of Senior Debt			749	0	0
Sunoco LP [Member]
NON-CASH INVESTING ACTIVITIES: [Abstract]
Income Tax Paid, Federal, after Refund Received			47
Income Tax Paid, Federal, after Refund Received			47
USAC [Member]
Convertible Preferred Stock Converted to Other Securities			749	0	0
Convertible Preferred Stock Converted to Other Securities			749	0	0
USAC [Member] | legal defeasance of senior notes due 2026
Repayments of Senior Debt			725	0	0
Repayments of Senior Debt			725	0	0
Crestwood Acquisition
NON-CASH INVESTING ACTIVITIES: [Abstract]
Stock Issued During Period, Value, Acquisitions	[1]		0	3,366	0
Stock Issued During Period, Value, Acquisitions	[1]		0	3,366	0
Lotus Midstream Acquisition
NON-CASH INVESTING ACTIVITIES: [Abstract]
Stock Issued During Period, Value, Acquisitions	[1]		0	574	0
Stock Issued During Period, Value, Acquisitions	[1]		0	574	0
Nustar Acquisition
Subsidiary unit transactions	[1]		2,850	0	0
Repayments of Senior Debt		$ 403
Repayments of Senior Debt		$ 403
Subsidiary unit transactions	[1]		2,850	0	0
WTG Midstream
NON-CASH INVESTING ACTIVITIES: [Abstract]
Stock Issued During Period, Value, Acquisitions	[1]		833	0	0
Stock Issued During Period, Value, Acquisitions	[1]		$ 833	$ 0	$ 0
[1] See Note 3 for additional information.

Estimates (Schedule of Inventor

Estimates (Schedule of Inventory) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Inventory, Net [Abstract]
Natural gas, NGLs and refined products	$ 1,989	$ 1,658
Crude oil	400	258
Spare parts and other	681	562
Total inventories	$ 3,070	$ 2,478

Estimates (Other Current Assets

Estimates (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Other Information [Abstract]
Deposits paid to vendors	$ 150	$ 205
Prepaid expenses and other	327	308
Total other current assets	$ 477	$ 513

Estimates (Property, Plant and

Estimates (Property, Plant and Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	[1]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 129,242	$ 114,932
Less - Accumulated depreciation	(34,030)	(29,581)
Property, plant and equipment, net	$ 95,212	85,351
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	3 years
Minimum [Member] | Other (5 to 20 years)
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	5 years
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	46 years
Maximum [Member] | Patents (10 years)
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	20 years
Maximum [Member] | Trade names (20 years)
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	10 years
Maximum [Member] | Other (5 to 20 years)
Property, Plant and Equipment, Net [Abstract]
Finite-Lived Intangible Asset, Useful Life	20 years
Land and improvements
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 1,675	1,529
Buildings and improvements (1 to 45 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	4,688	4,392
Pipelines and equipment (5 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	97,078	86,905
Right of way (20 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 9,239	7,379
Right of way (20 to 83 years) | Minimum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	20 years
Right of way (20 to 83 years) | Maximum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	83 years
Other (1 to 48 years) | Minimum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	1 year
Other (1 to 48 years) | Maximum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	48 years
Construction work-in-process
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 4,633	2,315
Product storage and related facilities
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 7,869	8,381
Product storage and related facilities | Minimum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	2 years
Product storage and related facilities | Maximum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	83 years
Other
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 4,060	$ 4,031
Buildings and improvements [Member] | Minimum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	1 year
Buildings and improvements [Member] | Maximum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	45 years
Pipelines And Equipment [Member] | Minimum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	5 years
Pipelines And Equipment [Member] | Maximum [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, useful life, minimum (years)	83 years
[1] Certain components of property, plant and equipment were reclassified in the current year. The balances as of December 31, 2023 reflected above have been adjusted to conform to the current year presentation. These changes did not impact total property, plant and equipment.

Estimates (Schedule Of Property

Estimates (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Depreciation, depletion and amortization expense	$ 4,701	$ 3,986	$ 3,774
Capitalized interest	$ 120	$ 77	$ 112
Property, Plant and Equipment [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
2025	$ 440
2026	437
2027	419
2028	416
2029	$ 408
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Property, Plant and Equipment [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2025
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Property, Plant and Equipment [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2026
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Property, Plant and Equipment [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2027
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Property, Plant and Equipment [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2028
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Property, Plant and Equipment [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2029

Estimates (Schedule of Other No

Estimates (Schedule of Other Non-Current Assets, net) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Accounting Policies [Abstract]
Crude pipeline linefill and tank bottoms	$ 743	$ 598
Regulatory assets	39	48
Pension assets	188	145
Deferred charges	151	148
Restricted funds	216	225
Other	680	569
Total other non-current assets, net	$ 2,017	$ 1,733

Estimates (Components Of Intang

Estimates (Components Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Gross Carrying Amount	$ 9,732	$ 9,538
Accumulated Amortization	(3,761)	(3,299)
Customer relationships, contracts and agreements (3 to 46 years)
Gross Carrying Amount	9,304	9,098
Accumulated Amortization	(3,654)	(3,196)
Patents (10 years)
Gross Carrying Amount	48	48
Accumulated Amortization	(48)	(48)
Trade names (20 years)
Gross Carrying Amount	66	66
Accumulated Amortization	(48)	(44)
Other (5 to 20 years)
Gross Carrying Amount	12	12
Accumulated Amortization	(11)	(11)
Total Amortizable Intangible Assets [Member]
Gross Carrying Amount	9,430	9,224
Accumulated Amortization	(3,761)	(3,299)
Trademarks [Member]
Gross Carrying Amount	302	302
Accumulated Amortization	0	0
Other
Gross Carrying Amount	0	12
Accumulated Amortization	0	0
Non-amortizable intangible assets [Member]
Gross Carrying Amount	302	314
Accumulated Amortization	$ 0	$ 0

Estimates, Significant Accoun_5

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Useful Lives) (Details) (Details)	Dec. 31, 2024
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
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 Amortizati

Estimates (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Reported in depreciation and amortization	$ 464	$ 399	$ 390

Estimates (Estimated Aggregate

Estimates (Estimated Aggregate Amortization Expense) (Details) $ in Millions	Dec. 31, 2024 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2025	$ 440
2026	437
2027	419
2028	416
2029	$ 408

Estimates (Schedule Of Goodwill

Estimates (Schedule Of Goodwill) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Goodwill [Roll Forward]
Goodwill	$ 4,019	$ 2,566
Goodwill, Acquired During Period	16	1,455
Goodwill	3,903	4,019
Goodwill, Other Changes	6	(2)
Goodwill, Written off Related to Sale of Business Unit	(138)
Intrastate Transportation and Storage
Goodwill [Roll Forward]
Goodwill	0	0
Goodwill, Acquired During Period	0	0
Goodwill	0	0
Goodwill, Other Changes	0	0
Goodwill, Written off Related to Sale of Business Unit	0
Interstate Transportation and Storage
Goodwill [Roll Forward]
Goodwill	0	0
Goodwill, Acquired During Period	0	0
Goodwill	0	0
Goodwill, Other Changes	0	0
Goodwill, Written off Related to Sale of Business Unit	0
Midstream
Goodwill [Roll Forward]
Goodwill	601	0
Goodwill, Acquired During Period	0	601
Goodwill	617	601
Goodwill, Other Changes	16	0
Goodwill, Written off Related to Sale of Business Unit	0
NGL and Refined Products Transportation and Services
Goodwill [Roll Forward]
Goodwill	884	693
Goodwill, Acquired During Period	0	191
Goodwill	886	884
Goodwill, Other Changes	2	0
Goodwill, Written off Related to Sale of Business Unit	0
Crude Oil Transportation and Services
Goodwill [Roll Forward]
Goodwill	853	190
Goodwill, Acquired During Period	0	663
Goodwill	841	853
Goodwill, Other Changes	(12)	0
Goodwill, Written off Related to Sale of Business Unit	0
Investment in Sunoco LP
Goodwill [Roll Forward]
Goodwill	1,599	1,601
Goodwill, Acquired During Period	16	0
Goodwill	1,477	1,599
Goodwill, Other Changes	0	(2)
Goodwill, Written off Related to Sale of Business Unit	(138)
Investment in USAC
Goodwill [Roll Forward]
Goodwill	0	0
Goodwill, Acquired During Period	0	0
Goodwill	0	0
Goodwill, Other Changes	0	0
Goodwill, Written off Related to Sale of Business Unit	0
All Other
Goodwill [Roll Forward]
Goodwill	82	82
Goodwill, Acquired During Period	0	0
Goodwill	82	82
Goodwill, Other Changes	0	$ 0
Goodwill, Written off Related to Sale of Business Unit	$ 0

Estimates (Accrued And Other Cu

Estimates (Accrued And Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Other Information [Abstract]
Interest payable	$ 685	$ 637
Customer advances and deposits	360	240
Accrued capital expenditures	688	442
Accrued wages and benefits	422	406
Taxes payable other than income taxes	737	646
Exchanges payable	90	163
Deferred Revenue	322	312
Other	937	675
Accrued and other current liabilities	$ 4,241	$ 3,521

Estimates (Fair Value Of Financ

Estimates (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Commodity derivatives:	$ 263	$ 610
Other Assets, Fair Value Disclosure	212	217
Total assets	475	833
Interest rate derivatives		(4)
Commodity derivatives:	(293)	(460)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(293)	(464)
Interest Rate Derivative Assets, at Fair Value		6
Level 1 [Member]
Commodity derivatives:	263	602
Other Assets, Fair Value Disclosure	212	217
Total assets	475	819
Interest rate derivatives		0
Commodity derivatives:	(293)	(460)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(293)	(460)
Interest Rate Derivative Assets, at Fair Value		0
Level 2 [Member]
Commodity derivatives:	0	8
Other Assets, Fair Value Disclosure	0	0
Total assets	0	14
Interest rate derivatives		(4)
Commodity derivatives:	0	0
Financial and Nonfinancial Liabilities, Fair Value Disclosure	0	(4)
Interest Rate Derivative Assets, at Fair Value		6
Commodity Derivatives - Power [Member] | Forwards Swaps [Member]
Commodity derivatives:	39	57
Commodity derivatives:	(38)	(56)
Commodity Derivatives - Power [Member] | Future [Member]
Commodity derivatives:	10	8
Commodity derivatives:	(10)	(8)
Commodity Derivatives - Power [Member] | Level 1 [Member] | Forwards Swaps [Member]
Commodity derivatives:	39	57
Commodity derivatives:	(38)	(56)
Commodity Derivatives - Power [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	10	8
Commodity derivatives:	(10)	(8)
Commodity Derivatives - Power [Member] | Level 2 [Member] | Forwards Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
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:	3	35
Commodity derivatives:	(9)	(18)
Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	3	35
Commodity derivatives:	(9)	(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:	25	45
Commodity derivatives:	(35)	(37)
Commodity Derivatives - Crude [Member] | Level 1 [Member] | Forwards Swaps [Member]
Commodity derivatives:	25	45
Commodity derivatives:	(35)	(37)
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:	6	24
Commodity derivatives:	(11)	(3)
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	4	20
Commodity derivatives:	(11)	(2)
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	10	77
Commodity derivatives:	(9)	(16)
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Commodity derivatives:		8
Commodity Derivatives - Natural Gas [Member] | Put Option [Member]
Commodity derivatives:		2
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	6	24
Commodity derivatives:	(11)	(3)
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	4	20
Commodity derivatives:	(11)	(2)
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	10	77
Commodity derivatives:	(9)	(16)
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:		0
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Put Option [Member]
Commodity derivatives:		2
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 Swaps [Member]
Commodity derivatives:		8
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Put Option [Member]
Commodity derivatives:		0
Commodity Derivatives - NGLs [Member] | Forwards Swaps [Member]
Commodity derivatives:	166	336
Commodity derivatives:	(170)	(316)
Commodity Derivatives - NGLs [Member] | Put Option [Member]
Commodity derivatives:		1
Commodity Derivatives - NGLs [Member] | Options - Calls [Member]
Commodity derivatives:		1
Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Forwards Swaps [Member]
Commodity derivatives:	166	336
Commodity derivatives:	(170)	(316)
Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Put Option [Member]
Commodity derivatives:		1
Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Options - Calls [Member]
Commodity derivatives:		1
Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Forwards Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	$ 0	0
Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Put Option [Member]
Commodity derivatives:		0
Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Options - Calls [Member]
Commodity derivatives:		$ 0

Acquisitions and Related Tran_3

Acquisitions and Related Transactions Acquisitions (Details) $ / shares in Units, € in Millions														1 Months Ended	3 Months Ended	12 Months Ended
		Aug. 30, 2024 USD ($)	Jul. 15, 2024 USD ($) shares	Jul. 01, 2024	May 03, 2024 USD ($) shares		Apr. 16, 2024 USD ($)	Mar. 13, 2024 USD ($)	Mar. 13, 2024 EUR (€)	Nov. 03, 2023 USD ($) $ / shares shares	May 02, 2023 USD ($) shares	May 01, 2023 USD ($)	Apr. 01, 2022 USD ($)	Nov. 30, 2022 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2024 USD ($) shares	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Business Acquisition [Line Items]
Goodwill, Acquired During Period																$ 16,000,000	$ 1,455,000,000
Impairment losses and other																52,000,000	12,000,000	$ 386,000,000
Deconsolidation, Gain (Loss), Amount																85,000,000
Payments to Acquire Businesses, Net of Cash Acquired																250,000,000	111,000,000	1,141,000,000
Finance Lease, Liability															$ 59,000,000	59,000,000
Gain (Loss) on Disposition of Assets																586,000,000	0	0
Income tax expense																541,000,000	303,000,000	204,000,000
Federal																175,000,000	227,000,000	239,000,000
ET-S Permian Joint Venture [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				67.50%
WTG Midstream
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest			100%
Contractual Rights [Member]
Business Acquisition [Line Items]
Finite-Lived Contractual Rights, Gross					$ 151,000,000
Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life					7 years
Customer Relationships [Member]
Business Acquisition [Line Items]
Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life					15 years
Finite-Lived Customer Relationships, Gross					$ 44,000,000
Sunoco LP [Member]
Business Acquisition [Line Items]
Goodwill, Acquired During Period													$ 20,000,000
Other Payments to Acquire Businesses													252,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill													98,000,000
Total assets acquired													73,000,000
Sunoco LP [Member] | ET-S Permian Joint Venture [Member]
Business Acquisition [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest				32.50%
Spindletop Assets
Business Acquisition [Line Items]
Asset Acquisition, Consideration Transferred																$ 325,000,000
ET Canada
Business Acquisition [Line Items]
Sale of Stock, Percentage of Ownership before Transaction																51%
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates																$ 302,000,000
Impairment losses and other																300,000,000
ET Canada | Noncontrolling Interest
Business Acquisition [Line Items]
Impairment losses and other																164,000,000
ET Canada | Common Unitholders
Business Acquisition [Line Items]
Impairment losses and other																136,000,000
7-Eleven | Sunoco LP [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred							$ 1,000,000,000
Number of Units in Real Estate Property							204
Gain (Loss) on Disposition of Assets							$ 586,000,000
Income tax expense							175,000,000
Federal							(27,000,000)
7-Eleven | Sunoco LP [Member] | Net of current tax expense [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Assets							$ 438,000,000
Woodford Express Acquisition
Business Acquisition [Line Items]
Repayments of Debt																292,000,000
Business Combination, Consideration Transferred																485,000,000
Working Capital | Sunoco LP [Member]
Business Acquisition [Line Items]
Total assets acquired													$ 76,000,000
Peerless | Sunoco LP [Member]
Business Acquisition [Line Items]
Other Payments to Acquire Businesses														$ 67,000,000
Crestwood Acquisition
Business Acquisition [Line Items]
Goodwill, Acquired During Period										$ 1,455,000,000					$ 1,460,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill										1,139,000,000
Total assets acquired										8,157,000,000
Business Combination, Consideration Transferred										3,645,000,000
Cash received										$ 12,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares										216,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets										$ 657,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment										4,772,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets										95,000,000
Lease right-of-use assets, net										27,000,000
Total liabilities assumed										4,228,000,000
Payments to Acquire Businesses, Gross										300,000,000
Payments to Acquire Businesses, Net of Cash Acquired																$ 0	288,000,000	0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-Term Debt										3,461,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets										12,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities										445,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other										322,000,000
Crestwood Acquisition | Senior Notes [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-Term Debt										2,850,000,000
Crestwood Acquisition | Revolving Credit Facility
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-Term Debt										$ 613,000,000
Crestwood Acquisition | Series I Preferred Units
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares										41,000,000
Crestwood
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares																2.07
Crestwood | Series I Preferred Units
Business Acquisition [Line Items]
Preferred Stock, Redemption Price Per Share | $ / shares										$ 9.857484
Lotus Midstream Acquisition
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill											$ 75,000,000
Total assets acquired											1,551,000,000
Business Combination, Consideration Transferred											1,504,000,000
Cash received											$ 4,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares											44,500,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets											$ 61,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment											1,263,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets											138,000,000
Lease right-of-use assets, net											10,000,000
Total liabilities assumed											43,000,000
Payments to Acquire Businesses, Gross											930,000,000
Equity Issued in Business Combination, Fair Value Disclosure											574,000,000
Payments to Acquire Businesses, Net of Cash Acquired																$ 0	930,000,000	0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets											4,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities											27,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other											$ 16,000,000
Zenith Energy | Sunoco LP [Member]
Business Acquisition [Line Items]
Other Payments to Acquire Businesses												$ 111,000,000
Business Combination, Consideration Transferred								$ 185,000,000	€ 170
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment								204,000,000
Number of Units in Real Estate Property												16
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets								36,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities								14,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other								43,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other								6,000,000
Business Combination, Bargain Purchase, Gain Recognized, Amount								6,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities								4,000,000
Net deferred income tax assets								$ 6,000,000
Nustar Acquisition
Business Acquisition [Line Items]
Goodwill, Acquired During Period					16,000,000	[1]										$ 16,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill	[2]				195,000,000
Total assets acquired					7,618,000,000
Business Combination, Consideration Transferred					2,823,000,000
Cash received					27,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets					186,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment					6,958,000,000
Lease right-of-use assets, net					136,000,000
Total liabilities assumed					3,967,000,000
Business Combination, Reason for Business Combination																NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids.
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-Term Debt	[2],[3]				3,500,000,000
Proceeds from (Repurchase of) Redeemable Preferred Stock					784,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets					127,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities					245,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other					$ 82,000,000
Business Acquisition, Equity Interest Issued or Issuable, Conversion Ratio of Shares					0.400
Repayments of Lines of Credit					$ 455,000,000
Impairment of Real Estate																$ 50,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities					$ 4,000,000
Nustar Acquisition | Sunoco LP [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares					51,500,000
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned					$ 2,850,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-Term Debt					3,500,000,000
Finance Lease, Liability					56,000,000
Proceeds from (Repurchase of) Redeemable Preferred Stock					$ 800,000,000
Other acquisitions [Member] | Sunoco LP [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Net of Cash Acquired		$ 24,000,000
ET-S Permian Joint Venture [Member]
Business Acquisition [Line Items]
Business Combination, Reason for Business Combination				ET-S Permian operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels.
WTG Midstream
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill			$ 20,000,000
Total assets acquired			3,471,000,000
Business Combination, Consideration Transferred			3,007,000,000
Cash received			$ 45,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares			50,800,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets			$ 334,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			3,109,000,000
Lease right-of-use assets, net			8,000,000
Total liabilities assumed			419,000,000
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned			833,000,000
Payments to Acquire Businesses, Gross			$ 2,280,000,000
Payments to Acquire Businesses, Net of Cash Acquired																$ 2,174,000,000	$ 0	$ 0
Business Combination, Reason for Business Combination			The acquired assets include approximately 6,000 miles of complementary gas gathering pipelines that extended Energy Transfer’s network in the Midland Basin. Also, as part of the transaction, the Partnership added eight gas processing plants with a total capacity of approximately 1.3 Bcf/d, and two additional processing plants that were under construction at closing. Since closing the transaction, one of these 200 MMcf/d processing plants was placed into service.
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities			$ 394,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other			$ 20,000,000
[1] Goodwill primarily represents expected commercial and operational synergies. None of the goodwill recorded as a result of this transaction is deductible for tax purposes. Intangible assets, net comprised of $151 million of favorable contracts, with a remaining weighted average life of approximately 7 years, and $44 million of customer relationships, with a remaining weighted average life of approximately 15 years. Subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed all outstanding NuStar preferred units totaling $784 million, redeemed NuStar’s subordinated notes totaling $403 million and repaid the outstanding balance on the NuStar credit facility totaling $455 million.

Acquisitions (Schedule Of Asset

Acquisitions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition Table) (Details) - USD ($) $ in Millions							3 Months Ended	12 Months Ended
		Jul. 15, 2024	May 03, 2024		Nov. 03, 2023	May 02, 2023	Dec. 31, 2024	Dec. 31, 2024	Dec. 31, 2023
Business Acquisition [Line Items]
Goodwill, Acquired During Period								$ 16	$ 1,455
Non-current operating lease liabilities							$ 730	730	$ 778
Woodford Express Acquisition
Business Acquisition [Line Items]
Business Combination, Consideration Transferred								485
Nustar Acquisition
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets			$ 186
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			6,958
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill	[1]		195
Goodwill, Acquired During Period			16	[2]				$ 16
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net			2,850
Total assets acquired			7,618
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities			245
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-Term Debt	[1],[3]		3,500
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other			82
Total liabilities assumed			3,967
Cash received			27
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets			127
Business Combination, Consideration Transferred			2,823
Non-current operating lease liabilities			136
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities			4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities	[3]		$ 801
Lotus Midstream Acquisition
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets						$ 61
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment						1,263
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets						138
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill						75
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net						1,508
Total assets acquired						1,551
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities						27
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other						16
Total liabilities assumed						43
Cash received						4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets						4
Business Combination, Consideration Transferred						$ 1,504
Crestwood Acquisition
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets					$ 657
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment					4,772
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets					95
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill					1,139
Goodwill, Acquired During Period					1,455		$ 1,460
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net					3,657
Total assets acquired					8,157
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities					445
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-Term Debt					3,461
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other					322
Total liabilities assumed					4,228
Cash received					12
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest					272
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets					12
Business Combination, Consideration Transferred					$ 3,645
WTG Midstream
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets		$ 334
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		3,109
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill		20
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net		3,052
Total assets acquired		3,471
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities		394
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other		20
Total liabilities assumed		419
Cash received		45
Business Combination, Consideration Transferred		3,007
Non-current operating lease liabilities		$ 5
[1] Intangible assets, net comprised of $151 million of favorable contracts, with a remaining weighted average life of approximately 7 years, and $44 million of customer relationships, with a remaining weighted average life of approximately 15 years. Goodwill primarily represents expected commercial and operational synergies. None of the goodwill recorded as a result of this transaction is deductible for tax purposes. Subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed all outstanding NuStar preferred units totaling $784 million, redeemed NuStar’s subordinated notes totaling $403 million and repaid the outstanding balance on the NuStar credit facility totaling $455 million.

Advances to and Investments i_3

Advances to and Investments in Unconsolidated Affiliates Narrative (Details)	Dec. 31, 2024
Citrus [Member]
Interest ownership	50%
FGT [Member]
Interest ownership	100%
Midcontinent Express Pipeline, LLC [Member]
Interest ownership	50%
White Cliffs
Interest ownership	54.30%
Explorer
Interest ownership	15%
SESH
Interest ownership	50%

Advances to and Investments i_4

Advances to and Investments in Unconsolidated Affiliates Investment in Affiliates (Carrying Values) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Investments in unconsolidated affiliates	[1]	$ 3,266	$ 3,097	$ 2,893
Equity in earnings of unconsolidated affiliates	[2]	379	383	257
Other Affiliates [Member]
Equity in earnings of unconsolidated affiliates		82	72	67
Citrus [Member]
Investments in unconsolidated affiliates		1,818	1,811
Equity in earnings of unconsolidated affiliates		136	146	141
MEP [Member]
Investments in unconsolidated affiliates		309	332
Equity in earnings of unconsolidated affiliates		63	87	10
White Cliffs
Investments in unconsolidated affiliates		196	203
Equity in earnings of unconsolidated affiliates		19	10	(8)
Other
Investments in unconsolidated affiliates		654	647
Explorer
Investments in unconsolidated affiliates		66	67
Equity in earnings of unconsolidated affiliates		34	37	25
SESH
Investments in unconsolidated affiliates		223	37
Equity in earnings of unconsolidated affiliates		$ 45	$ 31	$ 22
[1] Amounts reflected above exclude Sunoco LP’s investments in the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation. Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Investments in Affiliates (Summ

Investments in Affiliates (Summarized Balance Sheet Information) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule of Investments [Line Items]
Assets, Current	$ 14,202	$ 12,433
Other non-current assets, net	2,017	1,733
Assets	125,380	113,698	$ 105,643
Current Liabilities	12,656	11,277
Equity	46,017	43,939	$ 40,659	$ 39,345
Liabilities and Equity	125,380	113,698
Equity Method Investments [Member]
Schedule of Investments [Line Items]
Assets, Current	446	437
Property, plant and equipment, net	8,478	8,571
Other non-current assets, net	105	88
Assets	9,029	9,096
Current Liabilities	1,160	683
Non-current liabilities	3,541	4,379
Equity	4,328	4,034
Liabilities and Equity	$ 9,029	$ 9,096

Investments in Affiliates (Su_2

Investments in Affiliates (Summarized Income Statement Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]
Revenues	$ 82,671	$ 78,586	$ 89,876
Net income	6,565	5,294	5,868
Equity Method Investments [Member]
Schedule of Equity Method Investments [Line Items]
Revenues	1,898	1,914	1,618
Equity Method Investments Summarized Financial Information, Operating Income	1,009	1,079	754
Net income	$ 750	$ 786	$ 496

Net Income Per Limited Partne_3

Net Income Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Earnings Per Share [Abstract]
NET INCOME	$ 6,565	$ 5,294	$ 5,868
Less: Net income attributable to redeemable noncontrolling interests	59	60	51
NET INCOME ATTRIBUTABLE TO PARTNERS	4,814	3,935	4,756
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units	(1)	(1)	(2)
Diluted income available to Common Unitholders	$ 4,393	$ 3,468	$ 4,328
Weighted average common units	3,395.1	3,161.7	3,086.8
Basic	$ 1.29	$ 1.10	$ 1.40
Dilutive effect of unconverted unit awards and ET Series A Convertible Preferred Units	25.4	15.5	10.2
Weighted average common units, assuming dilutive effect of unvested unit awards	3,420.5	3,177.2	3,097
Diluted	$ 1.28	$ 1.09	$ 1.40
Limited Partners’ interest in net income	$ 4,394	$ 3,469	$ 4,330
Less: Net income attributable to noncontrolling interests	1,692	1,299	1,061
General Partner’s interest in net income	(4)	(3)	(4)
Preferred Unitholders’ interest in net income	$ 362	$ 463	$ 422

Debt Obligations Debt Obligat_2

Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Jun. 30, 2024	May 03, 2024	Apr. 30, 2024	Mar. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		$ 233
Other Long-term Debt		11					$ 18
Long-term Debt		59,760					52,388
Current maturities of long-term debt		8					1,008
Long-term debt, less current maturities		59,752					51,380
Nustar Acquisition
Debt Instrument [Line Items]
Junior Subordinated Notes			$ 403
Long-term Line of Credit		0	455
Senior Notes				$ 2,570
5.875% Senior Notes due January 15, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes						$ 1,150
5.25% Senior Notes due 2029 [Member]
Debt Instrument [Line Items]
Senior Notes			$ 1,000
Five Year Credit Facility
Debt Instrument [Line Items]
Long-term Line of Credit		2,760
Bakken Project [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		0					(1)
Deferred Finance Costs, Noncurrent, Net		(3)					(4)
Long-term Debt		847					1,845
Senior Notes					$ 1,000
Bakken Project [Member] | 3.90% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	[1]	$ 0					1,000
Long-term Debt, Description	[1]	3.90% Senior Notes due April 1, 2024(1)
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		$ 132					94
Debt Instrument, Unamortized Discount (Premium), Net		(15)					0
Deferred Finance Costs, Noncurrent, Net		(37)					(25)
Long-term Debt		7,485					3,580
Sunoco LP [Member] | 6.00% Senior Notes due April 15, 2027 [Member]
Debt Instrument [Line Items]
Senior Notes		$ 600					600
Long-term Debt, Description		6.000% 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		$ 203					411
Long-term Debt, Description		Sunoco LP Credit Facility due May 3, 2029
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		4.500% 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		4.500% Senior Notes due April 30, 2030
Sunoco LP [Member] | 7.00% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior Notes		$ 500					500
Long-term Debt, Description		7.000% Senior Notes due September 25, 2028
Sunoco LP [Member] | 5.75% Senior Notes due October 1, 2025
Debt Instrument [Line Items]
Senior Notes	[2],[3]	$ 600					0
Long-term Debt, Description	[2],[3]	5.750% Senior Notes due October 1, 2025(2)(3)
Sunoco LP [Member] | 6.00% Senior Notes due June 1, 2026
Debt Instrument [Line Items]
Senior Notes	[2]	$ 500					0
Long-term Debt, Description	[2]	6.000% Senior Notes due June 1, 2026(3)
Sunoco LP [Member] | 5.625% Senior Notes due April 28, 2027
Debt Instrument [Line Items]
Senior Notes	[2]	$ 550					0
Long-term Debt, Description	[2]	5.625% Senior Notes due April 28, 2027(3)
Sunoco LP [Member] | 7.00% Senior Notes due May 1, 2029
Debt Instrument [Line Items]
Senior Notes					750		0
Long-term Debt, Description		7.000% Senior Notes due May 1, 2029
Sunoco LP [Member] | 6.375% Senior Notes due October 1, 2030
Debt Instrument [Line Items]
Senior Notes	[2]	$ 600					0
Long-term Debt, Description	[2]	6.375% Senior Notes due October 1, 2030(3)
Sunoco LP [Member] | 7.25% Senior Notes due May 1, 2032
Debt Instrument [Line Items]
Senior Notes					$ 750		0
Long-term Debt, Description		7.250% Senior Notes due May 1, 2032
Sunoco LP [Member] | GoZone Bonds
Debt Instrument [Line Items]
Senior Notes	[2],[3]	$ 322					0
Current maturities of long-term debt	[2],[3]	$ 75
Long-term Debt, Description	[2],[3]	GoZone Bonds(2)(3)
Transwestern [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 75					250
Transwestern [Member] | 5.66% Senior Unsecured Notes, due December 9, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	[1]	$ 0					175
Long-term Debt, Description	[1]	5.66% Senior Notes due December 9, 2024(1)
Transwestern [Member] | 6.16% Senior Unsecured Notes, due May 24, 2037 [Member]
Debt Instrument [Line Items]
Senior Notes		$ 75					75
Long-term Debt, Description		6.16% Senior Notes due May 24, 2037
USA Compression Partners, LP [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		$ 772					872
Deferred Finance Costs, Noncurrent, Net		(20)					(11)
Long-term Debt		$ 2,502					2,336
Long-term Debt, Description		USAC Credit Facility due December 8, 2026
USA Compression Partners, LP [Member] | 6.875% Senior notes due April 2026 [Member]
Debt Instrument [Line Items]
Senior Notes		$ 0					725
Long-term Debt, Description		6.875% Senior Notes due April 1, 2026(1)
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
USA Compression Partners, LP [Member] | 7.125% Senior Notes due March 2029
Debt Instrument [Line Items]
Senior Notes		$ 1,000					0
Long-term Debt, Description		7.125% Senior Notes due March 15, 2029
ET [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		$ 62					128
Deferred Finance Costs, Noncurrent, Net		(250)					(197)
Long-term Debt		48,840					44,359
ET [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	[3]	$ 0					1,127
Long-term Debt, Description		5.875% Senior Notes due January 15, 2024(1)
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] | 4.05% 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(2)
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] | 9.00% Debentures, due 2024 [Member]
Debt Instrument [Line Items]
Subordinated Debt	[3]	$ 0					65
Long-term Debt, Description		9.00% Debentures due November 1, 2024(1)
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	[3]	$ 0					500
Long-term Debt, Description		4.25% Senior Notes due April 1, 2024(1)
ET [Member] | 4.5% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	[3]	$ 0					750
Long-term Debt, Description		4.50% Senior Notes due April 15, 2024(1)
ET [Member] | 5.95% Senior Notes due December 2025 [Member]
Debt Instrument [Line Items]
Senior Notes	[3]	$ 400					400
Long-term Debt, Description	[3]	5.95% Senior Notes due December 1, 2025(2)
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] | 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] | 7.00% Senior Notes, due July 15, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes		$ 66					66
Long-term Debt, Description		7.00% Senior Notes due July 15, 2029
ET [Member] | 4.9% Senior Notes due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	[3]	$ 0					350
Long-term Debt, Description		4.90% Senior Notes due February 1, 2024(1)
ET [Member] | 2.9% Senior Notes due May 15, 2025
Debt Instrument [Line Items]
Senior Notes	[3]	$ 1,000					1,000
Long-term Debt, Description	[3]	2.90% Senior Notes due May 15, 2025(2)
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		$ 2,759					1,412
Long-term Debt, Description		Five-Year Credit Facility due April 11, 2029
ET [Member] | 5.00% Senior Notes due May 15, 2044
Debt Instrument [Line Items]
Senior Notes		$ 531					531
Long-term Debt, Description		5.00% Senior Notes due May 15, 2044
ET [Member] | 3.90% Senior Notes due May 15, 2024
Debt Instrument [Line Items]
Senior Notes	[3]	$ 0					600
Long-term Debt, Description		3.90% Senior Notes due May 15, 2024(1)
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		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		4.15% Senior Notes due September 15, 2029
ET [Member] | 5.875% Senior Notes due January 15, 2024
Debt Instrument [Line Items]
Senior Notes	[3]	$ 0					23
Long-term Debt, Description		5.875% Senior Notes due January 15, 2024(1)
ET [Member] | 5.5% Senior Notes due June 1, 2027
Debt Instrument [Line Items]
Senior Notes		$ 44					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					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					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		$ 33					33
Long-term Debt, Description		8.25% Senior Notes due November 15, 2029
ET [Member] | 7.60% Senior Notes, due February 1, 2024, previously held by Panhandle
Debt Instrument [Line Items]
Senior Notes	[3]	$ 0					82
Long-term Debt, Description		7.60% Senior Notes due February 1, 2024(1)
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] | 5.75% Senior Notes due April 1, 2025
Debt Instrument [Line Items]
Senior Notes	[1]	$ 0					500
Long-term Debt, Description	[1]	5.75% Senior Notes due April 1, 2025(1)
ET [Member] | 6.05% Senior Notes due December 1, 2026
Debt Instrument [Line Items]
Senior Notes		$ 1,000					1,000
Long-term Debt, Description		6.05% Senior Notes due December 1, 2026
ET [Member] | 6.05% Senior Notes due December 1, 2027
Debt Instrument [Line Items]
Senior Notes		$ 600					600
Long-term Debt, Description		6.05% Senior Notes due May 1, 2027
ET [Member] | 6.10% Senior Notes due December 1, 2028
Debt Instrument [Line Items]
Senior Notes		$ 500					500
Long-term Debt, Description		6.10% Senior Notes due December 1, 2028
ET [Member] | 6.0% Senior Notes due February 1, 2029
Debt Instrument [Line Items]
Senior Notes		$ 700					700
Long-term Debt, Description		6.00% Senior Notes due February 1, 2029
ET [Member] | 8.0% Senior Notes due April 1, 2029
Debt Instrument [Line Items]
Senior Notes	[1]	$ 0					450
Long-term Debt, Description	[1]	8.00% Senior Notes due April 1, 2029(1)
ET [Member] | 6.40% Senior Notes due December 1, 2030
Debt Instrument [Line Items]
Senior Notes		$ 1,000					1,000
Long-term Debt, Description		6.40% Senior Notes due December 1, 2030
ET [Member] | 7.38 % Senior Notes due April 1, 2031
Debt Instrument [Line Items]
Senior Notes		$ 600					600
Long-term Debt, Description		7.38% Senior Notes due April 1, 2031
ET [Member] | 4.05% Senior Notes due June 1, 2033
Debt Instrument [Line Items]
Senior Notes		$ 225					225
Long-term Debt, Description		4.05% Tax-Exempt Bonds due June 1, 2033
ET [Member] | 6.55% Senior Notes due December 1, 2033
Debt Instrument [Line Items]
Senior Notes		$ 1,500					1,500
Long-term Debt, Description		6.55% Senior Notes due December 1,2033
ET [Member] | 5.25% Senior Notes due July 2029
Debt Instrument [Line Items]
Senior Notes		$ 1,000					0
Long-term Debt, Description		5.25% Senior Notes due July 1, 2029
ET [Member] | 5.25% Senior Notes due April 2029
Debt Instrument [Line Items]
Senior Notes		$ 1,500					1,500
Long-term Debt, Description		5.25% Senior Notes due April 15, 2029
ET [Member] | 5.55% Senior Notes due May 15, 2034
Debt Instrument [Line Items]
Senior Notes		$ 1,250					0
Long-term Debt, Description		5.55% Senior Notes due May 15, 2034
ET [Member] | 5.60% Senior Notes due September 1, 2034
Debt Instrument [Line Items]
Senior Notes		$ 1,250					0
Long-term Debt, Description		5.60% Senior Notes due September 1, 2034
ET [Member] | 5.95% Senior Notes due May 15, 2054
Debt Instrument [Line Items]
Senior Notes		$ 1,750					0
Long-term Debt, Description		5.95% Senior Notes due May 15, 2054
ET [Member] | 6.05% Senior Notes due September 1, 2054
Debt Instrument [Line Items]
Senior Notes		$ 1,250					0
Long-term Debt, Description		6.05% Senior Notes due September 1, 2054
ET [Member] | Floating Rate Junior Subordinated Notes due November 1, 2066
Debt Instrument [Line Items]
Junior Subordinated Notes		$ 600					600
Long-term Debt, Description		Floating Rate Junior Subordinated Notes due November 1, 2066
ET [Member] | Floating Rate Junior Subordinated Notes Due May 15, 2054
Debt Instrument [Line Items]
Junior Subordinated Notes		$ 800					0
Long-term Debt, Description		8.00% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due May 15, 2054
ET [Member] | Floating Rate Subordinated Notes due October 1, 2054
Debt Instrument [Line Items]
Junior Subordinated Notes		$ 400					$ 0
Long-term Debt, Description		7.125% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due October 1, 2054
[1] These notes were redeemed in 2024. (3) Sunoco LP assumed $2.57 billion aggregate principal amount of NuStar senior notes and bonds in connection with the closing of the NuStar acquisition in May 2024. As of December 31, 2024, these obligations (including $75 million of Sunoco LP’s GoZone bonds) were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.

Debt Obligations Debt Obligat_3

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) $ in Millions	Dec. 31, 2024 USD ($)
Debt Obligations [Abstract]
2025	$ 3,082
2026	3,826
2027	5,554
2028	4,203
2029	10,476
Thereafter	32,852
Long-term Debt	$ 59,993
Schedule of Capitalization, Long-Term Debt [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
2025	$ 3,082
2026	3,826
2027	5,554
2028	4,203
2029	10,476
Thereafter	32,852
Long-term Debt, Gross	$ 59,993
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Schedule of Capitalization, Long-Term Debt [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2025
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Schedule of Capitalization, Long-Term Debt [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2026
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Schedule of Capitalization, Long-Term Debt [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2027
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Schedule of Capitalization, Long-Term Debt [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2028
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Schedule of Capitalization, Long-Term Debt [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2029

Debt Obligations (Debt Narrativ

Debt Obligations (Debt Narrative) (Details) - USD ($) $ in Millions			12 Months Ended
	May 03, 2024	Apr. 30, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Jun. 30, 2024	Mar. 31, 2024
Repayments of Senior Debt			$ 749	$ 0	$ 0
(Gains) losses on extinguishments of debt			12	(2)	$ 0
Nustar Acquisition
Outstanding borrowings			0			$ 455
Senior Notes	$ 2,570
Junior Subordinated Notes						403
Financing Receivable, Revolving			0
Repayments of Senior Debt	$ 403
Five Year Credit Facility
Line of Credit Facility, Current Borrowing Capacity			5,000
Letters of Credit Outstanding, Amount			30
Line of Credit Facility, Remaining Borrowing Capacity			$ 2,210
Line of Credit Facility, Interest Rate at Period End			4.65%
Outstanding borrowings			$ 2,760
Five Year Credit Facility | April 2029
Line of Credit Facility, Current Borrowing Capacity			4,840
Senior Notes due 2034
Senior Notes			$ 1,250
Debt Instrument, Interest Rate, Stated Percentage			5.55%
Senior Notes due 2054
Senior Notes			$ 1,750
Debt Instrument, Interest Rate, Stated Percentage			5.95%
Junior Subordinated Noes due 2054
Debt Instrument, Interest Rate, Stated Percentage			8%
Junior Subordinated Notes			$ 800
5.875% Senior Notes due January 15, 2024 [Member]
Senior Notes							$ 1,150
Debt Instrument, Interest Rate, Stated Percentage							5.875%
4.90% senior notes due February 2024
Senior Notes							$ 350
Debt Instrument, Interest Rate, Stated Percentage							4.90%
7.60% Senior notes due February 2024
Senior Notes							$ 82
Debt Instrument, Interest Rate, Stated Percentage							7.60%
4.25% Senior notes due April 2024
Senior Notes						$ 500
Debt Instrument, Interest Rate, Stated Percentage						4.25%
4.50% Senior notes due April 2024
Senior Notes						$ 750
Debt Instrument, Interest Rate, Stated Percentage						4.50%
8.00% Senior Notes due April 2029
Senior Notes						$ 450
Debt Instrument, Interest Rate, Stated Percentage						8%
3.90% Senior Notes due May 2024
Senior Notes						$ 600
Debt Instrument, Interest Rate, Stated Percentage						3.90%
9.00% debentures due November 2024
Debt Instrument, Interest Rate, Stated Percentage			9%
Junior Subordinated Notes			$ 65
5.66% Senior notes due December 2024
Senior Notes			$ 175
Debt Instrument, Interest Rate, Stated Percentage			5.66%
5.75% Senior notes due April 2025
Senior Notes			$ 500
Debt Instrument, Interest Rate, Stated Percentage			5.75%
5.25% Senior Notes due 2029 [Member]
Senior Notes						$ 1,000
Debt Instrument, Interest Rate, Stated Percentage						525%
5.60% Senior Notes due 2034
Senior Notes						$ 1,250
Debt Instrument, Interest Rate, Stated Percentage						5.60%
6.05% Senior Notes due 2054
Senior Notes						$ 1,250
Debt Instrument, Interest Rate, Stated Percentage						6.05%
7.125% Senior Notes due 2054
Senior Notes						$ 400
Debt Instrument, Interest Rate, Stated Percentage						7.125%
USAC [Member]
(Gains) losses on extinguishments of debt			$ 5
USAC [Member] | goverment securities transferred in connection with the leagal defeasance of senior notes due 2026
Repayments of Senior Debt			749
USAC [Member] | USAC Credit Facility, due 2023 [Member]
Line of Credit Facility, Current Borrowing Capacity			827
Letters of Credit Outstanding, Amount			1
Line of Credit Facility, Remaining Borrowing Capacity			$ 783
Line of Credit Facility, Interest Rate at Period End			6.98%
Outstanding borrowings			$ 772
Line of Credit Facility, Maximum Borrowing Capacity			1,600
USAC [Member] | 6.875% Senior Notes due 2026
Senior Notes							$ 725
Debt Instrument, Interest Rate, Stated Percentage							6.875%
USAC [Member] | 7.125% Senior Notes due 2029
Senior Notes							$ 1,000
Debt Instrument, Interest Rate, Stated Percentage							7.125%
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			43
Line of Credit Facility, Remaining Borrowing Capacity			$ 1,250
Line of Credit Facility, Interest Rate at Period End			6.57%
Outstanding borrowings			$ 203	411
Sunoco LP [Member] | 7.00% Senior Notes due May 1, 2029
Senior Notes		$ 750		0
Debt Instrument, Interest Rate, Stated Percentage		7%
Sunoco LP [Member] | 7.25% Senior Notes due May 1, 2032
Senior Notes		$ 750		$ 0
Debt Instrument, Interest Rate, Stated Percentage		7.25%
Bakken Project [Member]
Senior Notes		$ 1,000
Proceeds from Noncontrolling Interests		$ 637
Bakken Project [Member] | 3.90% Senior Notes due April 2024
Debt Instrument, Interest Rate, Stated Percentage		3.90%
Accordion feature [Member] | Five Year Credit Facility
Line of Credit Facility, Current Borrowing Capacity			$ 7,000

Debt Obligations Debt Obligat_4

Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2024
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
Maximum Leverage Ratio Permitted	5.50
Supplementary Leverage Ratio	0.0312
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%
Five Year Credit Facility | Maximum [Member] | ET [Member] | Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1%
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.

Debt Obligations GoZone Bonds (

Debt Obligations GoZone Bonds (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)
GoZone Series 2008
Debt Instrument [Line Items]
Debt Instrument, Issuance Date	Jun. 26, 2008
Senior Notes	$ 56
Debt Instrument, Interest Rate, Stated Percentage	6.10%
Debt Instrument, Maturity Date	Jun. 01, 2038
GoZone Series 2010
Debt Instrument [Line Items]
Debt Instrument, Issuance Date	Jul. 15, 2010
Senior Notes	$ 100
Debt Instrument, Interest Rate, Stated Percentage	6.35%
Debt Instrument, Maturity Date	Jul. 01, 2040
GoZone Series 2010A
Debt Instrument [Line Items]
Debt Instrument, Issuance Date	Oct. 07, 2010
Senior Notes	$ 43
Debt Instrument, Interest Rate, Stated Percentage	6.35%
Debt Instrument, Maturity Date	Oct. 01, 2040
GoZone Series 2010B
Debt Instrument [Line Items]
Debt Instrument, Issuance Date	Dec. 29, 2010
Senior Notes	$ 48
Debt Instrument, Interest Rate, Stated Percentage	6.10%
Debt Instrument, Maturity Date	Dec. 01, 2040
GoZone Series 2011
Debt Instrument [Line Items]
Debt Instrument, Issuance Date	Aug. 09, 2011
Senior Notes	$ 75
Debt Instrument, Interest Rate, Stated Percentage	5.85%
Debt Instrument, Maturity Date	Aug. 01, 2041

Redeemable Preferred Units (Det

Redeemable Preferred Units (Details) - USD ($)			12 Months Ended
	Apr. 01, 2024	Jan. 12, 2024	Dec. 31, 2024	Dec. 31, 2023
Redeemable noncontrolling interests			$ 417,000,000	$ 778,000,000
Preferred Units, Issued			44,898,959	113,648,967
Preferred Units, Outstanding			44,898,959	113,648,967
USAC [Member]
Redeemable noncontrolling interests			$ 169,000,000	$ 476,000,000
Preferred Units, Issued		40,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.525	$ 0.525
Preferred Units, Outstanding	280,000	40,000
Common Unit, Issued		1,998,850
Stock Issued During Period, Shares, Conversion of Units	13,991,954	1,998,850
Preferred Units, Cumulative Cash Distributions	$ 24.375	$ 24.375
ET [Member]
Redeemable noncontrolling interests			23,000,000	22,000,000
Niobrara
Redeemable noncontrolling interests			225,000,000	$ 280,000,000
Crestwood Niobrara LLC
Proceeds from (Repurchase of) Redeemable Preferred Stock			$ 37,000,000

Equity (Narrative) (Details)

Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended																12 Months Ended
		Dec. 31, 2024		Sep. 30, 2024		Jun. 30, 2024		Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Jan. 12, 2024	Oct. 27, 2023	Apr. 27, 2022
Issuance of Common Units (2)	[1]																	12,700,000	12,900,000	11,900,000
Share Repurchase Program, Authorized, Amount		$ 2,000																$ 2,000
Share Repurchase Program, Remaining Authorized, Amount		$ 880																$ 880
Minimum beneficial percentage ownership, other than the Partnership's General Partner and its affiliates, no voting rights, not considered outstanding		20%																20%
Limited Partners' Capital Account, Units Outstanding		3,431,088,022							3,367,525,806				3,094,400,000				3,082,500,000	3,431,088,022	3,367,525,806	3,094,400,000
Stock Issued During Period, Value, Dividend Reinvestment Plan																		$ 89
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan		38,900,000																38,900,000
Preferred Units, Issued		44,898,959							113,648,967									44,898,959	113,648,967
Incentive Distribution Rights		0%																0%
Issued		3,431,088,022							3,367,525,806									3,431,088,022	3,367,525,806
Series A Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0		$ 0		$ 9.88		$ 23.99	$ 24.71	$ 24.67	$ 23.89	$ 21.98	$ 31.25	$ 0	$ 31.25	$ 0	$ 31.25
Preferred Stock, Dividend Rate, Percentage																		6.25%
Preferred Units, Liquidation Spread, Percent		4.028%																4.028%
Series A Preferred Units [Member] | Tenor spread adjustment
Preferred Units, Liquidation Spread, Percent		0.26161%																0.26161%
Series C Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0		0		0		0	0.6075	0.6489	0.6294	0.4609	0.4609	0.4609	0.4609	0.4609	0.4609
Preferred Stock, Dividend Rate, Percentage																		7.375%
Shares Issued, Price Per Share		$ 25																$ 25
Preferred Units, Liquidation Spread, Percent		4.53%																4.53%
Series C Preferred Units [Member] | Tenor spread adjustment
Preferred Units, Liquidation Spread, Percent		0.26161%																0.26161%
Series D Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0		0		0		0	0.6199	0.6622	0.4766	0.4766	0.4766	0.4766	0.4766	0.4766	0.4766
Preferred Stock, Dividend Rate, Percentage																		7.625%
Shares Issued, Price Per Share		$ 25																$ 25
Preferred Units, Liquidation Spread, Percent		4.738%																4.738%
Series D Preferred Units [Member] | Tenor spread adjustment
Preferred Units, Liquidation Spread, Percent		0.26161%																0.26161%
Series E Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0		0		0		0.4750	0.4750	0.4750	0.4750	0.4750	0.4750	0.4750	0.4750	0.4750	0.4750
Series F Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[2]	$ 0		33.7500		0		33.7500	0	33.7500	0	33.7500	0	33.7500	0	33.7500	0
Preferred Stock, Shares Outstanding		500,000																500,000
Series G Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[2]	$ 0		35.63		0		35.63	0	35.63	0	35.63	0	35.63	0	35.63	0
Preferred Stock, Shares Outstanding		1,484,780																1,484,780
Series B Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[2]	$ 33.125		0		33.125		0	33.125	0	33.125	0	33.125	0	33.125	0	33.125
Preferred Stock, Shares Outstanding		550,000																550,000
Series H Preferred Units
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[2]	$ 0		32.50		0		32.50	0	32.50	0	32.50	0	32.50	0	32.50	0
Preferred Stock, Shares Outstanding		900,000																900,000
Series I Preferred Units
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.2111	[3]	0.2111	[3]	0.2111	[3]	0.2111	0.2111	0	0	0	0	0	0	0	0	$ 0.2111
Preferred Stock, Shares Outstanding		41,464,179																41,464,179
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																28,500,000
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.8865		0.8756		0.8756		0.8756	0.8420	0.8420	0.8420	0.8420	0.8255	0.8255	0.8255	0.8255	0.8255
Limited Partners' Capital Account, Units Outstanding		136,200,000																136,200,000
USAC [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		46,100,000																46,100,000
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.5250		$ 0.5250		$ 0.5250		$ 0.5250	$ 0.5250	$ 0.5250	$ 0.5250	$ 0.5250	$ 0.5250	$ 0.5250	$ 0.5250	$ 0.5250	$ 0.5250
Limited Partners' Capital Account, Units Outstanding		117,000,000																117,000,000
Preferred Units, Issued																					40,000
Stock Issued During Period, Shares, Dividend Reinvestment Plan																		65,352	87,808	124,255
Class of Warrant or Right, Number of Securities Called by Warrants or Rights																						2,360,488
Series A Preferred Units [Member]
Shares Issued, Price Per Share		$ 1,000																$ 1,000
Preferred Units, Liquidation Spread, Percent		4.028%																4.028%
Series B Preferred Units [Member]
Preferred Stock, Dividend Rate, Percentage																		6.625%
Shares Issued, Price Per Share		$ 1,000																$ 1,000
Preferred Units, Liquidation Spread, Percent		4.155%																4.155%
A tenor spread adjustment		0.26161%																0.26161%
Series E Preferred Units [Member]
Preferred Stock, Dividend Rate, Percentage																		7.60%
Shares Issued, Price Per Share		$ 25																$ 25
Series F Preferred Units [Member]
Preferred Stock, Dividend Rate, Percentage																		6.75%
Shares Issued, Price Per Share		$ 1,000																$ 1,000
Preferred Units, Liquidation Spread, Percent		5.134%																5.134%
Series G Preferred Units [Member]
Preferred Stock, Dividend Rate, Percentage																		7.125%
Shares Issued, Price Per Share		$ 1,000																$ 1,000
Preferred Units, Liquidation Spread, Percent		5.306%																5.306%
Series H Preferred Units
Preferred Stock, Dividend Rate, Percentage																		6.50%
Shares Issued, Price Per Share		$ 1,000																$ 1,000
Preferred Units, Liquidation Spread, Percent		5.694%																5.694%
ETE Class A Units [Member] | ETE Merger [Member]
Sale of Stock, Number of Shares Issued in Transaction																		847,443,096
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. Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Distributions on the Series B Preferred Units will begin to be paid quarterly on February 15, 2028. For the period ended December 31, 2024, the cash distribution for the Series I Preferred Units was paid on February 14, 2025 to unitholders of record as of the close of business on February 4, 2025. For the period ended September 30, 2024, the cash distribution for the Series I Preferred Units was paid on November 14, 2024 to unitholders of record as of the close of business on November 4, 2024. For the period ended June 30, 2024, the cash distribution for the Series I Preferred Units was paid on August 14, 2024 to unitholders of record as of the close of business on August 2, 2024.

Equity (Change In ETE Common Un

Equity (Change In ETE Common Units) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Issuance of Common Units (2)	[1]	12,700,000	12,900,000	11,900,000
Outstanding		3,431,088,022	3,367,525,806	3,094,400,000	3,082,500,000
Issuance of restricted Common Units under long-term incentive plans	[2]	(50,800,000)	(260,200,000)	0
Number of Common Units, end of period		3,431,088,022	3,367,525,806	3,094,400,000
Equity		$ 46,017	$ 43,939	$ 40,659	$ 39,345
Distributions to partners		(4,623)	(4,248)	(3,047)
Common units repurchased		$ (2,645)
Common Unitholders
Outstanding		3,431,000,000
Number of Common Units, end of period		3,431,000,000
Crestwood Acquisition
Stock Issued During Period, Value, Acquisitions	[3]	$ 0	3,366	0
Series A Preferred Units [Member]
Equity		0	948	958	958
Distributions to partners		(56)	(96)	(59)
Common units repurchased		(950)
Other, net		13
Net income		45	86	59
Series A Preferred Units [Member] | Crestwood Acquisition
Stock Issued During Period, Value, Acquisitions			0
Series B Preferred Units [Member]
Equity		556	556	556	556
Distributions to partners		(36)	(36)	(36)
Common units repurchased		0
Other, net		0
Net income		36	36	36
Series B Preferred Units [Member] | Crestwood Acquisition
Stock Issued During Period, Value, Acquisitions			0
Series C Preferred Units [Member]
Equity		0	438	440	440
Distributions to partners		(11)	(40)	(33)
Common units repurchased		(450)
Other, net		11
Net income		12	38	33
Series C Preferred Units [Member] | Crestwood Acquisition
Stock Issued During Period, Value, Acquisitions			0
Series D Preferred Units [Member]
Equity		0	435	434	434
Distributions to partners		(11)	(36)	(34)
Common units repurchased		(445)
Other, net		10
Net income		11	37	34
Series D Preferred Units [Member] | Crestwood Acquisition
Stock Issued During Period, Value, Acquisitions			0
Series E Preferred Units [Member]
Equity		0	786	786	786
Distributions to partners		(30)	(61)	(61)
Common units repurchased		(800)
Other, net		20
Net income		24	61	61
Series E Preferred Units [Member] | Crestwood Acquisition
Stock Issued During Period, Value, Acquisitions			0
Series F Preferred Units [Member]
Equity		496	496	496	496
Distributions to partners		(34)	(34)	(34)
Common units repurchased		0
Other, net		0
Net income		34	34	34
Series F Preferred Units [Member] | Crestwood Acquisition
Stock Issued During Period, Value, Acquisitions			0
Series G Preferred Units [Member]
Equity		1,488	1,488	1,488	1,488
Distributions to partners		(106)	(106)	(106)
Common units repurchased		0
Other, net		0
Net income		106	106	106
Series G Preferred Units [Member] | Crestwood Acquisition
Stock Issued During Period, Value, Acquisitions			0
Series H Preferred Units
Equity		893	893	893	893
Distributions to partners		(59)	(59)	(59)
Common units repurchased		0
Other, net		0
Net income		59	59	59
Series H Preferred Units | Crestwood Acquisition
Stock Issued During Period, Value, Acquisitions			0
Preferred Units [Member]
Equity		3,852	6,459	6,051	6,051
Distributions to partners		(378)	(468)	(422)
Common units repurchased		(2,645)
Other, net		54
Net income		362	463	422
Preferred Units [Member] | Crestwood Acquisition
Stock Issued During Period, Value, Acquisitions			413
Series I Preferred Units
Equity		419	419	0	$ 0
Distributions to partners		(35)	0	0
Common units repurchased		0
Other, net		0
Net income		$ 35	6	$ 0
Series I Preferred Units | Crestwood Acquisition
Stock Issued During Period, Value, Acquisitions			$ 413
[1] Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings. Includes common units issued related to our acquisitions of WTG Midstream in 2024 and of Crestwood and Lotus Midstream in 2023. See Note 3 for additional information.

Equity (Quarterly Distributions

Equity (Quarterly Distributions Of Available Cash) (Details) - $ / shares		3 Months Ended																12 Months Ended
		Dec. 31, 2024		Sep. 30, 2024		Jun. 30, 2024		Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Dec. 31, 2024
Parent Company [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.3250		$ 0.3225		$ 0.3200		$ 0.3175	$ 0.3150	$ 0.3125	$ 0.3100	$ 0.3075	$ 0.3050	$ 0.2650	$ 0.2300	$ 0.2000	$ 0.1750
USAC [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		0.5250		0.5250		0.5250		0.5250	0.5250	0.5250	0.5250	0.5250	0.5250	0.5250	0.5250	0.5250	0.5250
Sunoco LP [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		0.8865		0.8756		0.8756		0.8756	0.8420	0.8420	0.8420	0.8420	0.8255	0.8255	0.8255	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		$ 0		0		9.88		23.99	24.71	24.67	23.89	21.98	31.25	0	31.25	0	31.25
Preferred Units, Liquidation Spread, Percent		4.028%																4.028%
Series A Preferred Units [Member] | Tenor spread adjustment
Preferred Units, Liquidation Spread, Percent		0.26161%																0.26161%
Series B Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[1]	$ 33.125		0		33.125		0	33.125	0	33.125	0	33.125	0	33.125	0	33.125
Series C Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0		0		0		0	0.6075	0.6489	0.6294	0.4609	0.4609	0.4609	0.4609	0.4609	0.4609
Preferred Units, Liquidation Spread, Percent		4.53%																4.53%
Series C Preferred Units [Member] | Tenor spread adjustment
Preferred Units, Liquidation Spread, Percent		0.26161%																0.26161%
Series D Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0		0		0		0	0.6199	0.6622	0.4766	0.4766	0.4766	0.4766	0.4766	0.4766	0.4766
Preferred Units, Liquidation Spread, Percent		4.738%																4.738%
Series D Preferred Units [Member] | Tenor spread adjustment
Preferred Units, Liquidation Spread, Percent		0.26161%																0.26161%
Series E Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0		0		0		0.4750	0.4750	0.4750	0.4750	0.4750	0.4750	0.4750	0.4750	0.4750	0.4750
Series F Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[1]	0		33.7500		0		33.7500	0	33.7500	0	33.7500	0	33.7500	0	33.7500	0
Series G Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[1]	0		35.63		0		35.63	0	35.63	0	35.63	0	35.63	0	35.63	0
Series H Preferred Units
Distribution Made to Limited Partner, Distributions Paid, Per Unit	[1]	0		32.50		0		32.50	0	32.50	0	32.50	0	32.50	0	32.50	0
Series I Preferred Units
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.2111	[2]	$ 0.2111	[2]	$ 0.2111	[2]	$ 0.2111	$ 0.2111	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0.2111
[1] Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Distributions on the Series B Preferred Units will begin to be paid quarterly on February 15, 2028. For the period ended December 31, 2024, the cash distribution for the Series I Preferred Units was paid on February 14, 2025 to unitholders of record as of the close of business on February 4, 2025. For the period ended September 30, 2024, the cash distribution for the Series I Preferred Units was paid on November 14, 2024 to unitholders of record as of the close of business on November 4, 2024. For the period ended June 30, 2024, the cash distribution for the Series I Preferred Units was paid on August 14, 2024 to unitholders of record as of the close of business on August 2, 2024.

Equity (Accumulated Other Compr

Equity (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 20	$ 13
Foreign currency translation adjustment	(6)	(5)
Actuarial gain related to pensions and other postretirement benefits	45	6
Investments in unconsolidated affiliates, net	14	14
Total AOCI, net of tax	$ 73	$ 28

Equity Tax amounts in component

Equity Tax amounts in components of other comprehensive income (loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Statement of Comprehensive Income [Abstract]
Available-for-sale securities	$ (3)	$ (3)
Foreign currency translation adjustment	2	6
Other Comprehensive Income (Loss), Tax	$ (1)	$ 3

Equity Incentive Narrative (Det

Equity Incentive Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Awards granted	$ 18.95
Unvested awards	36,100,000	39,100,000
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	3 years 8 months 12 days
Awards granted	8,600,000
Liability of subsidiary outstanding cash restricted units	$ 0.1
Sunoco LP [Member]
Awards granted	134,225
USAC [Member]
Awards granted	107,820
ETE Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	38,600,000
ET Unit Based Compensation Plans [Member]
Awards granted		$ 13.78	$ 11.56
Fair Value Of Units As Of The Vesting Date	$ 194	$ 106	$ 103
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 313
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	3 years
Subsidiary Unit Based Compensation [Member]
Fair Value Of Units As Of The Vesting Date	$ 29	$ 37	$ 26
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 51
ET Cash Restricted Unit Plan [Member]
Unvested awards	6,000,000
Awards granted	2,800,000	3,200,000	3,800,000
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 5.1

ET Equity Incentive Plans (Deta

ET Equity Incentive Plans (Details) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Awards granted	8.6
Awards granted	$ 18.95
Unvested awards	36.1	39.1
Unvested awards	$ 13,180,000	$ 10.84
Awards vested	(10.5)
Awards vested	$ 9.55
Awards forfeited	(1.1)
Awards forfeited	$ 11.13

Subsidiary Equity Incentive Pla

Subsidiary Equity Incentive Plans (Details) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	36.1	39.1
Unvested awards	$ 13,180,000	$ 10.84
Awards granted	8.6
Awards granted	$ 18.95
Awards vested	(10.5)
Awards vested	$ 9.55
Awards forfeited	1.1
Awards forfeited	$ 11.13
Sunoco LP Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	1.7	1.6
Unvested awards	$ 47.55	$ 41.08
Awards granted	0.6
Awards granted	$ 55.24	$ 53.37	$ 43.54
Awards vested	(0.4)
Awards vested	$ 34.76
Awards forfeited	0.1
Awards forfeited	$ 42.06
USAC Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	1.6	1.9
Unvested awards	$ 19.31	$ 17.08
Awards granted	0.3
Awards granted	$ 22.37	$ 23.13	$ 18.31
Awards vested	(0.5)
Awards vested	$ 15.40
Awards forfeited	0.1
Awards forfeited	$ 18.09

Income Taxes Narrative (Details

Income Taxes Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating Loss Carryforwards [Line Items]
Deferred Tax Liabilities, Gross	$ 4,422,000,000	$ 4,348,000,000
Net operating losses and other carryforwards	197,000,000	371,000,000
State	66,000,000	44,000,000	$ 17,000,000
Deferred Income Tax Expense (Benefit)	276,000,000	$ 203,000,000	$ 187,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	74,000,000
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, After Tax	65,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Expense	6,000,000
Income Tax Examination, Penalties and Interest Accrued	5,000,000
Loss Contingency, Range of Possible Loss, Portion Not Accrued	28,000,000
Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset, Interest Carryforward	118,000,000
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	64,000,000
Sunoco Property Company LLC [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	20,000,000
Sunoco Retail LLC
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	0
ETP Holdco
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	537,000,000
Foreign subsidiary
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	56,000,000
PENNSYLVANIA
Operating Loss Carryforwards [Line Items]
State	67,000,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	34,000,000
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	$ 4,000,000

Income Taxes Components of Inco

Income Taxes Components of Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current expense:
Federal	$ 198	$ 56	$ 0
State	66	44	17
Current Foreign Tax Expense (Benefit)	1	0	0
Total	265	100	17
Deferred expense (benefit):
Federal	175	227	239
State	101	(24)	(58)
Deferred Foreign Income Tax Expense (Benefit)	0	0	6
Total	276	203	187
Total income tax expense	541	303	204
Additions attributable to tax positions taken in prior years	34	0	0
Income tax expense	541	303	204
Income (Loss), Including Portion Attributable to Noncontrolling Interest, before Tax	7,106	5,597	6,072
UNITED STATES
Income (Loss), Including Portion Attributable to Noncontrolling Interest, before Tax	7,101	5,602	6,073
Non-US
Income (Loss), Including Portion Attributable to Noncontrolling Interest, before Tax	$ 5	$ (5)	$ (1)

Income Taxes Reconciliation of

Income Taxes Reconciliation of Income Tax Satutory Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income tax expense at United States statutory rate	$ 1,492	$ 1,175	$ 1,275
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax	(1,084)	(884)	(1,086)
Noncontrolling interests	0	0	26
State tax, net of federal tax benefit	113	47	19
Statutory rate change	0	(10)	(42)
Valuation allowance	0	(3)	(4)
Uncertain tax positions	21	(14)	(3)
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Amount	9	0	0
Dividend received deduction	(3)	(3)	(3)
Foreign taxes	0	0	6
Other	(7)	(5)	16
Income tax expense	$ 541	$ 303	$ 204

Income Taxes Effects of Tempora

Income Taxes Effects of Temporary Differences That Comprise Net Deffered Income Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Deferred income tax assets:
Net operating losses and other carryforwards	$ 197	$ 371
Other	42	46
Deferred Tax Assets, Gross	239	417
Deferred income tax liabilities:
Property, plant and equipment	(224)	(232)
Investments in affiliates	(4,098)	(4,003)
Trademarks	(82)	(91)
Other	(18)	(22)
Deferred Tax Liabilities, Gross	4,422	4,348
Deferred Tax Liabilities	$ (4,183)	$ (3,931)

Income Taxes Components of Net

Income Taxes Components of Net Deferred Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Components of Net Deferred Income Tax [Abstract]
Total deferred income tax assets	$ 239	$ 417
Deferred Tax Liabilities, Net	$ (4,183)	$ (3,931)

Income Taxes Changes in Unrecog

Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Changes in Unrecognized Tax Benefits [Abstract]
Balance at beginning of year	$ 40	$ 52	$ 56
Reduction attributable to tax positions taken in prior years	0	(9)	(4)
Tax Adjustments, Settlements, and Unusual Provisions	0	(3)	0
Balance at end of year	$ 74	$ 40	$ 52

Regulatory Matters, Commitmen_3

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details)		1 Months Ended				12 Months Ended
	Aug. 01, 2020 USD ($)	Jan. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Jan. 31, 2023 USD ($)	Jun. 30, 2022 USD ($)	Dec. 31, 2024 USD ($) Rate	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2018 USD ($)
Operating Leases, Rent Expense						$ 72,000,000	$ 68,000,000	$ 64,000,000
Payments for Environmental Liabilities						11,000,000	29,000,000
Total environmental liabilities			$ 278,000,000			$ 278,000,000	$ 277,000,000
Site Contingency, Number of Sites Needing Remediation			31			31
Loss Contingency, Estimate of Possible Loss			$ 75,000,000			$ 75,000,000
Litigation Settlement, Fee 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	Other non-current liabilities
Interest Statutory Rate | Rate						12%
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
Ohio EPA
Loss Contingency, Damages Sought, Value									$ 2,600,000
Proposed Civil Penalty
Payments for Legal Settlements						$ 20,000,000
Litigation Settlement, Fee Expense						40,000,000
Additional Interest | Cline Class Action
Litigation Settlement Interest						23,000,000
Actual Damages | Cline Class Action
Litigation Settlement Interest						104,000,000
Punitive Damages [Member] | Cline Class Action
Litigation Settlement Interest						75,000,000
Culberson
Loss Contingency, Damages Sought, Value						93,000,000
Crestwood
Payments for Legal Settlements				$ 21,200,000
Crestwood | pre-judgement interest award
Litigation Settlement, Amount Awarded to Other Party					$ 20,700,000
Crestwood | attorney fees
Litigation Settlement, Amount Awarded to Other Party					17,700,000
Crestwood | other costs
Litigation Settlement, Amount Awarded to Other Party					$ 4,700,000
Crestwood | reversal reduction
Litigation Settlement, Amount Awarded to Other Party			$ 22,400,000
ETC Marketing Ltd. | Subsequent Event [Member]
Loss Contingency, Damages Sought, Value		$ 75,000
Related To Deductibles [Member]
Loss Contingency Accrual			$ 281,000,000			$ 281,000,000	$ 285,000,000

Regulatory Matters, Commitmen_4

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) $ in Millions	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Environmental Remediation Obligations [Abstract]
Current	$ 51	$ 42
Non-current	227	235
Total environmental liabilities	$ 278	$ 277
Site Contingency, Number of Sites Needing Remediation	31

Revenue Narrative (Details)

Revenue Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Sunoco LP [Member]
Capitalized Contract Cost, Amortization	$ 35	$ 29	$ 22

Revenue Contracts with customer

Revenue Contracts with customers (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Jan. 01, 2019
Contract with Customer, Liability	$ 759	$ 749	$ 615
Additions	1,256	1,254
Deferred Revenue, Revenue Recognized	$ (1,246)	(1,120)
Sunoco LP [Member]
Contract with Customer, Liability		0		$ 39
Accounts receivable from contracts with customers		809		1,084
Contract assets		$ 256		$ 288

Revenue from Contract with Cust

Revenue from Contract with Customer - Performance Obligation (Details) $ in Millions	Dec. 31, 2024 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 37,703
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 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	$ 7,808
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2025
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
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	$ 6,830
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2026
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	2 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	$ 5,591
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2027
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	3 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, Amount	$ 17,474
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2028
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	4 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2029

Lease Accounting Narrative (Det

Lease Accounting Narrative (Details)	Dec. 31, 2024
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 o

Lease Accounting - Components of Leases on BS (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Lessee, Lease, Description [Line Items]
Operating lease current liabilities	$ 67	$ 56
Accrued and other current liabilities	4,241	3,521
Non-current operating lease liabilities	730	778
Property, plant and equipment, net	95,212	85,351	[1]
Current maturities of long-term debt	8	1,008
Long-term debt, less current maturities	59,752	51,380
Other non-current liabilities	1,618	1,611
Operating Leases [Member]
Lessee, Lease, Description [Line Items]
Lease right-of-use assets, net	753	797
Operating lease current liabilities	67	56
Accrued and other current liabilities		5
Non-current operating lease liabilities	730	778
Finance Leases [Member]
Lessee, Lease, Description [Line Items]
Property, plant and equipment, net	1	1
Lease right-of-use assets, net	56	29
Current maturities of long-term debt	8	8
Long-term debt, less current maturities	50	19
Other non-current liabilities	$ 1	$ 0
[1] Certain components of property, plant and equipment were reclassified in the current year. The balances as of December 31, 2023 reflected above have been adjusted to conform to the current year presentation. These changes did not impact total property, plant and equipment.

Lease Accounting - Components_2

Lease Accounting - Components of Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	$ 91	$ 88
Interest on lease liabilities	2	0
Lease, Cost	138	100
Lease costs, gross	183	142
Finance Leases [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost	4	0
Cost of goods sold
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	1	1
Operating expenses
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	71	69
Short-term lease cost	69	38
Variable lease cost	19	16
Selling, general and administrative
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	19	18
Depreciation, depletion and amortization
Lessee, Lease, Description [Line Items]
Amortization of lease assets	2	0
Other Revenue [Member]
Lessee, Lease, Description [Line Items]
Sublease Income	$ 45	$ 42

Lease Accounting - Remaining te

Lease Accounting - Remaining term and rate (Details)	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Operating leases	18 years	21 years
Finance leases	15 years	12 years
Operating leases	6%	6%
Finance leases	6%	5%

Lease Accounting - Cash flow (D

Lease Accounting - Cash flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Lessee, Lease, Description [Line Items]
Operating cash flows from finance leases	$ (2)	$ 0
Financing cash flows from finance leases	(6)	0
Lease assets obtained in exchange for new finance lease liabilities	1	18
Lease assets obtained in exchange for new operating lease liabilities	6	5
Operating Leases [Member]
Lessee, Lease, Description [Line Items]
Net cash provided by operating activities	$ (94)	$ (139)

Lease Accounting - Lease Maturi

Lease Accounting - Lease Maturities (Details) $ in Millions	Dec. 31, 2024 USD ($)
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
2025	$ 99
2025	10
2025	109
2026	92
2026	6
2026	98
2027	83
2027	6
2027	89
2028	81
2028	5
2028	86
2029	75
2029	4
2029	79
Thereafter	812
Thereafter	56
Thereafter	868
Total lease payments	1,242
Total lease payments	87
Lease Liabilities, Due	1,329
Less: present value discount	445
Less: present value discount	28
Less: present value discount	$ 473
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]	Non-current operating lease liabilities
Operating Lease, Liability	$ 797
Finance Lease, Liability	59
Lease, Liabilities	$ 856
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	2025
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	2026
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	2027
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	2028
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2029

Lease Accounting - Lessor (Deta

Lease Accounting - Lessor (Details) $ in Millions	Dec. 31, 2024 USD ($)
Thereafter	$ 812
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
Sunoco LP [Member]
2025	$ 139
2026	121
2027	93
2028	73
2029	61
Thereafter	356
Total undiscounted cash flows	$ 843
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2025
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2026
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2027
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2028
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2029

Derivative Assets And Liabili_3

Derivative Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details)		Dec. 31, 2024 MW BBtu	Dec. 31, 2023 MW BBtu
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Swing Swaps IFERC [Member]
Derivative, Nonmonetary Notional Amount, Volume		156,820	97,728
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount, Volume		(3,490)	46,975
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forward Contracts
Derivative, Nonmonetary Notional Amount, Volume	[1]	0	1,751
Natural Gas [Member] | Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount, Volume		47,170	39,013
Natural Gas [Member] | Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount, Volume		47,170	39,013
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount, Volume		6,630	5,247
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member]
Derivative, Nonmonetary Notional Amount, Volume		0	1,900
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount, Volume		0	250
Natural Gas [Member] | Long [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member]
Derivative, Nonmonetary Notional Amount, Volume		44,170	39,013
Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount, Volume | MW		140,137	464,897
Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member]
Derivative, Nonmonetary Notional Amount, Volume | MW		17,600
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forward Swaps [Member]
Derivative, Nonmonetary Notional Amount, Volume | MW		6,040	155,600
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member]
Derivative, Nonmonetary Notional Amount, Volume | MW			136,000
Commodity Derivatives - Crude [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member]
Derivative, Nonmonetary Notional Amount, Volume		0	15
Commodity Derivatives - Crude [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount, Volume		0	20
Commodity Derivatives - Crude [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forward Contracts
Derivative, Nonmonetary Notional Amount, Volume		22,512	2,674
Commodity Derivatives - NGL/Refined Products | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount, Volume		1,763	4,548
Commodity Derivatives - NGL/Refined Products | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member]
Derivative, Nonmonetary Notional Amount, Volume		9
Commodity Derivatives - NGL/Refined Products | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount, Volume		14	43
Commodity Derivatives - NGL/Refined Products | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forward Contracts
Derivative, Nonmonetary Notional Amount, Volume		15,063	13,870
Commodity Derivatives - NGL/Refined Products | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member]
Derivative, Nonmonetary Notional Amount, Volume			121
[1]Natural gas forward physical contracts are no longer reflected as mark-to-market derivatives in 2024.

Derivative Assets And Liabili_4

Derivative Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) - April 2025 - Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member] - Forward-Starting Swaps [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023
Description of Interest Rate Derivative Activities	[1]	Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR
Derivative, Notional Amount	[1]	$ 0	$ 700
[1] In August 2024, USAC elected to terminate the outstanding interest rate swap.

Derivative Assets And Liabili_5

Derivative Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Asset Derivatives	$ 263	$ 616
Liability Derivatives	(293)	(464)
Designated as Hedging Instrument [Member]
Asset Derivatives	3	51
Liability Derivatives	(7)	(6)
Not Designated as Hedging Instrument [Member]
Asset Derivatives	260	565
Liability Derivatives	(286)	(458)
Broker cleared derivative contracts [Member]
Asset Derivatives	212	478
Liability Derivatives	(236)	(380)
Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Asset Derivatives	51	132
Liability Derivatives	(57)	(80)
Commodity Derivatives (Margin Deposits) [Member] | Designated as Hedging Instrument [Member]
Asset Derivatives	3	51
Liability Derivatives	(7)	(6)
Commodity Derivatives (Margin Deposits) [Member] | Not Designated as Hedging Instrument [Member]
Asset Derivatives	209	427
Liability Derivatives	(229)	(374)
Interest Rate Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Asset Derivatives	0	6
Liability Derivatives	$ 0	$ (4)

Derivative Assets And Liabili_6

Derivative Assets And Liabilities Derivative Assets and Lianilities (Offsetting Agreements Netting Table) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Asset Derivatives	$ 263	$ 616
Derivative Liabilities	(293)	(464)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(42)	(72)
Derivative Liability, Fair Value, Amount Offset Against Collateral	42	72
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(204)	(368)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	204	368
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	17	176
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	47	24
Without offsetting agreements [Member]
Asset Derivatives	0	6
Derivative Liabilities	0	(4)
OTC Contracts [Member]
Asset Derivatives	51	132
Derivative Liabilities	(57)	(80)
Broker cleared derivative contracts [Member]
Asset Derivatives	212	478
Derivative Liabilities	$ (236)	$ (380)

Derivative Assets And Liabili_7

Derivative Assets And Liabilities (Derivative Amount Of Gain (Loss) Recognized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 63	$ 83	$ 417
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments	6	36	293
Cost of goods sold
Gains on interest rate derivatives	$ 57	$ 47	$ 124

Retirement Benefits (Narrative)

Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Retirement Benefits [Line Items]
Defined Contribution Plan, Cost	$ 103	$ 86	$ 79
Pension Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 3
Large Cap US Equitiies	100%	100%
Other Postretirement Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 1

Retirement Benefits (Obligation

Retirement Benefits (Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Defined Benefit Plan, Benefit Obligation, Business Combination	$ 12	$ 0
Nustar Acquisition
Change in plan assets:
Return on plan assets and other	0	0
Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	23	22
Service cost	1	0
Interest cost	6	1
Defined Benefit Plan, Benefit Obligation		23
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	22
Defined Benefit Plan, Plan Assets, Amount	182	22
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position		(1)
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	138	148
Service cost	0	0
Interest cost	7	6
Defined Benefit Plan, Accumulated Benefit Obligation, Increase (Decrease) for Plan Amendment	(11)	0
Benefits paid, net	(13)	(13)
Actuarial gain and other	(6)	(3)
Defined Benefit Plan, Benefit Obligation	127	138
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	277	259
Return on plan assets and other	29	29
Employer contributions	2	2
Benefits paid, net	(13)	(13)
Defined Benefit Plan, Plan Assets, Amount	295	277
Amount underfunded (overfunded) at end of period	(168)	(139)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	185	155
Current liabilities	(3)	(2)
Non-current liabilities	(14)	(14)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	168	139
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	(59)	(12)
Prior service credit	25	(3)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	(34)	(15)
Funded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	23
Interest cost	6	1
Defined Benefit Plan, Accumulated Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Benefits paid, net	(37)	(1)
Actuarial gain and other	13	1
Defined Benefit Plan, Benefit Obligation	158	23
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	22	20
Return on plan assets and other	13	2
Employer contributions	5	1
Benefits paid, net	(36)	(1)
Defined Benefit Plan, Plan Assets, Amount	182	22
Amount underfunded (overfunded) at end of period	(24)	1
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	24	0
Current liabilities	0	0
Non-current liabilities	0	(1)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	24
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	(9)	0
Prior service credit	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	(9)
Defined Benefit Plan, Benefit Obligation, Business Combination	152	0
Funded Plans [Member] | Pension Benefits | Nustar Acquisition
Change in plan assets:
Return on plan assets and other	178	0
Unfunded Plans [Member]
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Defined Benefit Plan, Benefit Obligation, Business Combination	0	0
Unfunded Plans [Member] | Nustar Acquisition
Change in plan assets:
Return on plan assets and other	0	0
Unfunded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	17	19
Service cost	0	0
Interest cost	1	1
Defined Benefit Plan, Accumulated Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Benefits paid, net	(3)	(3)
Actuarial gain and other	1	0
Defined Benefit Plan, Benefit Obligation	16	17
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	16	17
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Current liabilities	(3)	(3)
Non-current liabilities	(13)	(14)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	(16)	(17)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	(1)	(2)
Prior service credit	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	$ (1)	$ (2)

Retirement Benefits (Accumulate

Retirement Benefits (Accumulated Benefit Obligation In Excess of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation		$ 23	$ 22
Fair value of plan assets	$ 182	22
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	127	138	148
Fair value of plan assets	295	277	259
Funded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	22	23
Accumulated benefit obligation	158	23
Fair value of plan assets	182	22	20
Unfunded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	16	15
Accumulated benefit obligation	16	17	19
Fair value of plan assets	$ 0	$ 0	$ 0

Retirement Benefits (Net Period

Retirement Benefits (Net Periodic Benefit Costs Schedule) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 1	$ 0
Interest cost	6	1
Expected return on plan assets	(8)	(1)
Prior service cost amortization	(2)	0
Defined Benefit Plan, Actuarial Gain (Loss), Immediate Recognition as Component in Net Periodic Benefit (Cost) Credit	0	0
Settlements	2	0
Net periodic benefit cost	(1)	0
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0
Interest cost	7	6
Expected return on plan assets	(13)	(12)
Prior service cost amortization	2	2
Defined Benefit Plan, Actuarial Gain (Loss), Immediate Recognition as Component in Net Periodic Benefit (Cost) Credit	(1)	(1)
Settlements	0	0
Net periodic benefit cost	$ (5)	$ (5)

Retirement Benefits (Benefit As

Retirement Benefits (Benefit Assumptions) (Details)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate	7.44%	7.42%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.09%	5.17%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.80%	2.70%
Discount rate	5.40%	2.70%
Tax exempt accounts	7%	7%
Taxable accounts	4.26%	0%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.40%	4.62%
Discount rate	4.40%	4.93%
Tax exempt accounts	7%	7%
Taxable accounts	4.75%	4.75%

Retirement Benefits (Fair Value

Retirement Benefits (Fair Value of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2024		Dec. 31, 2023		Dec. 31, 2022
Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Accumulated benefit obligation	$ 127		$ 138		$ 148
Fair value of plan assets	295		277		259
Pension Benefits
Fair Value of Plan Assets [Line Items]
Accumulated benefit obligation			23		22
Fair value of plan assets	182		22
Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	8		13
Cash and Cash Equivalents [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	81		1
Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	189	[1]	166	[2]
Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	65	[3]	21	[4]
Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	98		98
Fixed Income Securities [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	36
Level 1 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	197		179
Level 1 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	138		22
Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	8		13
Level 1 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	81		1
Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	189	[1]	166	[2]
Level 1 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	21	[3]	21	[4]
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	36
Level 2 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	98		98
Level 2 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	44		0
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	[1]	0	[2]
Level 2 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	44	[3]	0	[4]
Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	98		98
Level 2 [Member] | Fixed Income Securities [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0
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	[1]	0	[2]
Level 3 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Fair value of plan assets	0	[3]	0	[4]
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		23
Accumulated benefit obligation	158		23
Fair value of plan assets	182		22		20
Unfunded Plans [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Projected benefit obligation	16		15
Accumulated benefit obligation	16		17		19
Fair value of plan assets	$ 0		$ 0		$ 0
[1] Primarily composed of market index funds as of December 31, 2024. Primarily composed of market index funds as of December 31, 2023. Comprised of approximately 100% equities as of December 31, 2024. Comprised of approximately 100% equities as of December 31, 2023.

Retirement Benefits (Benefit Pa

Retirement Benefits (Benefit Payments) (Details) $ in Millions	Dec. 31, 2024 USD ($)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2025	$ 14
2026	13
2027	12
2028	12
2029	11
2030 – 2034	46
Defined Benefit Plan, Funded Plan | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2025	72
2026	4
2027	4
2028	4
2029	5
2030 – 2034	26
Defined Benefit Plan, Unfunded Plan | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2025	3
2026	2
2027	2
2028	2
2029	1
2030 – 2034	$ 5

Reportable Segments Revenue (De

Reportable Segments Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenue from External Customer [Line Items]
Revenues	$ (82,671)	$ (78,586)	$ (89,876)
Intersegment Eliminations [Member]
Revenue from External Customer [Line Items]
Revenues	(12,336)	(12,308)	(18,941)
Investment in USAC | Operating Segments
Revenue from External Customer [Line Items]
Revenues	(950)	(846)	(705)
Investment in USAC | Operating Segments | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(909)	(824)	(689)
Investment in USAC | Operating Segments | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(41)	(22)	(16)
All Other | Operating Segments
Revenue from External Customer [Line Items]
Revenues	(1,747)	(1,798)	(3,574)
All Other | Operating Segments | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(1,284)	(1,328)	(2,863)
All Other | Operating Segments | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(463)	(470)	(711)
Crude Oil Transportation and Services | Operating Segments
Revenue from External Customer [Line Items]
Revenues	(28,539)	(26,536)	(25,982)
Crude Oil Transportation and Services | Operating Segments | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(28,528)	(26,534)	(25,980)
Crude Oil Transportation and Services | Operating Segments | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(11)	(2)	(2)
NGL and Refined Products Transportation and Services | Operating Segments
Revenue from External Customer [Line Items]
Revenues	(24,530)	(21,903)	(25,657)
NGL and Refined Products Transportation and Services | Operating Segments | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(20,981)	(18,413)	(21,414)
NGL and Refined Products Transportation and Services | Operating Segments | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(3,549)	(3,490)	(4,243)
Midstream | Operating Segments
Revenue from External Customer [Line Items]
Revenues	(11,199)	(10,406)	(17,101)
Midstream | Operating Segments | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(3,283)	(2,911)	(4,114)
Midstream | Operating Segments | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(7,916)	(7,495)	(12,987)
Interstate Transportation and Storage | Operating Segments
Revenue from External Customer [Line Items]
Revenues	(2,296)	(2,375)	(2,251)
Interstate Transportation and Storage | Operating Segments | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(2,270)	(2,328)	(2,185)
Interstate Transportation and Storage | Operating Segments | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(26)	(47)	(66)
Intrastate Transportation and Storage | Operating Segments
Revenue from External Customer [Line Items]
Revenues	(3,053)	(3,962)	(7,818)
Intrastate Transportation and Storage | Operating Segments | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(2,750)	(3,222)	(6,954)
Intrastate Transportation and Storage | Operating Segments | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(303)	(740)	(864)
Investment in Sunoco LP | Operating Segments
Revenue from External Customer [Line Items]
Revenues	(22,693)	(23,068)	(25,729)
Investment in Sunoco LP | Operating Segments | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(22,666)	(23,026)	(25,677)
Investment in Sunoco LP | Operating Segments | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	$ (27)	$ (42)	$ (52)

Reportable Segments (Operating

Reportable Segments (Operating Segments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cost of Goods and Services Sold		$ (61,975)	$ (60,541)	$ (72,232)
Depreciation, depletion and amortization		5,165	4,385	4,164
Equity in earnings of unconsolidated affiliates	[1]	379	383	257
Intersegment Eliminations [Member]
Cost of Goods and Services Sold		12,324	12,284	18,837
Intrastate Transportation and Storage
Depreciation, depletion and amortization		216	214	209
Equity in earnings of unconsolidated affiliates	[1]	16	17	17
Intrastate Transportation and Storage | Operating Segments
Cost of Goods and Services Sold		(1,390)	(2,616)	(6,000)
Investment in Sunoco LP
Depreciation, depletion and amortization		368	187	193
Investment in Sunoco LP | Operating Segments
Cost of Goods and Services Sold		(20,595)	(21,703)	(24,350)
Corporate Segment and Other Operating Segment [Member] | Operating Segments
Cost of Goods and Services Sold		(1,709)	(1,740)	(3,328)
Interstate Transportation and Storage
Depreciation, depletion and amortization		575	563	513
Equity in earnings of unconsolidated affiliates	[1]	241	260	175
Interstate Transportation and Storage | Operating Segments
Cost of Goods and Services Sold		(9)	(6)	(25)
Midstream
Depreciation, depletion and amortization		1,719	1,451	1,351
Equity in earnings of unconsolidated affiliates	[1]	13	15	19
Midstream | Operating Segments
Cost of Goods and Services Sold		(6,637)	(6,503)	(12,682)
NGL and Refined Products Transportation and Services
Depreciation, depletion and amortization		1,026	915	865
Equity in earnings of unconsolidated affiliates	[1]	83	76	44
NGL and Refined Products Transportation and Services | Operating Segments
Cost of Goods and Services Sold		(19,406)	(17,049)	(21,656)
Crude Oil Transportation and Services
Depreciation, depletion and amortization		965	740	663
Equity in earnings of unconsolidated affiliates	[1]	21	11	(2)
Crude Oil Transportation and Services | Operating Segments
Cost of Goods and Services Sold		(24,407)	(23,071)	(22,917)
All Other
Depreciation, depletion and amortization		31	69	133
Equity in earnings of unconsolidated affiliates	[1]	5	4	4
Investment in USAC
Depreciation, depletion and amortization		265	246	237
Investment in USAC | Operating Segments
Cost of Goods and Services Sold		$ (146)	$ (137)	$ (111)
[1] Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Reportable Segments Reportable

Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA		$ 15,483	$ 13,698	$ 13,093
Depreciation, depletion and amortization		5,165	4,385	4,164
Interest expense, net of interest capitalized		3,125	2,578	2,306
Impairment losses and other		52	12	386
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments		6	36	293
Non-cash compensation expense		151	130	115
Unrealized Gain (Loss) on Derivatives		(56)	3	42
(Gains) losses on extinguishments of debt		12	(2)	0
Inventory valuation adjustments		86	114	(5)
Adjusted EBITDA related to unconsolidated affiliates		692	691	565
Income (Loss) from Equity Method Investments	[1]	(379)	(383)	(257)
Other		9	(12)	82
Income tax expense (benefit) from continuing operations		(541)	(303)	(204)
NET INCOME		6,565	5,294	5,868
Gain (Loss) from Litigation Settlement		0	627	0
Gain (Loss) on Disposition of Assets		(586)	0	0
Intrastate Transportation and Storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA		1,358	1,111	1,396
Depreciation, depletion and amortization		216	214	209
Income (Loss) from Equity Method Investments	[1]	(16)	(17)	(17)
Investment in Sunoco LP
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA		1,457	964	919
Depreciation, depletion and amortization		368	187	193
Investment in USAC
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA		584	512	426
Depreciation, depletion and amortization		265	246	237
Corporate Segment and Other Operating Segment [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA		(10)	2	177
Interstate Transportation and Storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA		1,828	2,009	1,753
Depreciation, depletion and amortization		575	563	513
Income (Loss) from Equity Method Investments	[1]	(241)	(260)	(175)
Midstream
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA		2,910	2,525	3,210
Depreciation, depletion and amortization		1,719	1,451	1,351
Income (Loss) from Equity Method Investments	[1]	(13)	(15)	(19)
NGL and Refined Products Transportation and Services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA		4,179	3,894	3,025
Depreciation, depletion and amortization		1,026	915	865
Income (Loss) from Equity Method Investments	[1]	(83)	(76)	(44)
Crude Oil Transportation and Services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA		3,177	2,681	2,187
Depreciation, depletion and amortization		965	740	663
Income (Loss) from Equity Method Investments	[1]	$ (21)	$ (11)	$ 2
[1] Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Reportable Segments (Assets Seg

Reportable Segments (Assets Segments) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Assets	$ 125,380	$ 113,698	$ 105,643
Intrastate Transportation and Storage | Operating Segments
Assets	6,289	6,112	6,609
Interstate Transportation and Storage | Operating Segments
Assets	17,656	17,708	17,979
Midstream | Operating Segments
Assets	30,473	25,592	21,851
NGL and Refined Products Transportation and Services | Operating Segments
Assets	27,445	27,214	27,903
Crude Oil Transportation and Services | Operating Segments
Assets	25,231	25,464	19,200
Investment in Sunoco LP | Operating Segments
Assets	14,375	6,826	6,830
Investment in USAC | Operating Segments
Assets	2,746	2,737	2,666
Corporate Segment and Other Operating Segment [Member]
Assets	$ 1,165	$ 2,045	$ 2,605

Reporting Segments (Additions T

Reporting Segments (Additions To Property Plant And Equipment Including Acquisitions Net Of Contributions In Aid Of Construction Costs Segments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	$ 4,582	$ 2,868	$ 3,026
Investment in Sunoco LP
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	344	215	186
Intrastate Transportation and Storage
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	118	93	179
Interstate Transportation and Storage
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	332	383	644
Midstream
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	1,323	832	1,004
NGL and Refined Products Transportation and Services
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	1,424	679	507
Crude Oil Transportation and Services
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	423	266	246
Investment in USAC
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	276	300	169
All Other
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	[1]	$ 342	$ 100	$ 91
[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 t

Reportable Segments (Advances to and investments in affiliates) (Details) - USD ($) $ in Millions		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	[1]	$ 3,266	$ 3,097	$ 2,893
Intrastate Transportation and Storage
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	[1]	150	144	139
Interstate Transportation and Storage
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	[1]	2,350	2,179	2,201
Midstream
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	[1]	132	141	54
NGL and Refined Products Transportation and Services
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	[1]	383	390	398
Crude Oil Transportation and Services
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	[1]	193	187	48
All Other
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	[1]	$ 58	$ 56	$ 53
[1] Amounts reflected above exclude Sunoco LP’s investments in the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Reportable Segments (Other Inco

Reportable Segments (Other Income Expense) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Other Operating Income (Expense), Net	[1]	$ 953	$ 859	$ 634
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Other Operating Income (Expense), Net	[1]	(101)	(11)	(9)
Intrastate Transportation and Storage | Operating Segments
Segment Reporting Information [Line Items]
Other Operating Income (Expense), Net	[1]	(9)	95	(35)
Interstate Transportation and Storage | Operating Segments
Segment Reporting Information [Line Items]
Other Operating Income (Expense), Net	[1]	477	501	449
Midstream | Operating Segments
Segment Reporting Information [Line Items]
Other Operating Income (Expense), Net	[1]	97	25	64
NGL and Refined Products Transportation and Services | Operating Segments
Segment Reporting Information [Line Items]
Other Operating Income (Expense), Net	[1]	172	89	113
Crude Oil Transportation and Services | Operating Segments
Segment Reporting Information [Line Items]
Other Operating Income (Expense), Net	[1]	46	35	(9)
Investment in Sunoco LP | Operating Segments
Segment Reporting Information [Line Items]
Other Operating Income (Expense), Net	[1]	236	132	47
Investment in USAC | Operating Segments
Segment Reporting Information [Line Items]
Other Operating Income (Expense), Net	[1]	0	1	0
Corporate Segment and Other Operating Segment [Member] | Operating Segments
Segment Reporting Information [Line Items]
Other Operating Income (Expense), Net	[1]	$ 35	$ (8)	$ 14
[1] Other income and expense include, if applicable to a segment, Adjusted EBITDA related to unconsolidated affiliates, unrealized gains and losses on commodity risk management activities and other items. For the investment in Sunoco LP segment, this also includes inventory valuation adjustments.

Reportable Segments (Selling Ge

Reportable Segments (Selling General and Administrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	$ 1,069	$ 891	$ 937
Intrastate Transportation and Storage
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	50	51	53
Interstate Transportation and Storage
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	129	115	131
Midstream
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	199	199	186
NGL and Refined Products Transportation and Services
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	160	157	127
Crude Oil Transportation and Services
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	149	120	224
Investment in Sunoco LP
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	266	113	111
Investment in USAC
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	54	51	45
Corporate Segment and Other Operating Segment [Member]
Segment Reporting Information [Line Items]
Selling, General and Administrative Expense	$ 62	$ 85	$ 60

Reportable Segments (Operatin_2

Reportable Segments (Operating Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:	$ 5,097	$ 4,315	$ 4,248
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:	(112)	(112)	(170)
Intrastate Transportation and Storage | Operating Segments
Segment Reporting Information [Line Items]
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:	246	279	334
Interstate Transportation and Storage | Operating Segments
Segment Reporting Information [Line Items]
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:	807	746	791
Midstream | Operating Segments
Segment Reporting Information [Line Items]
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:	1,550	1,204	1,087
NGL and Refined Products Transportation and Services | Operating Segments
Segment Reporting Information [Line Items]
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:	957	892	962
Crude Oil Transportation and Services | Operating Segments
Segment Reporting Information [Line Items]
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:	852	699	645
Investment in Sunoco LP | Operating Segments
Segment Reporting Information [Line Items]
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:	611	420	396
Investment in USAC | Operating Segments
Segment Reporting Information [Line Items]
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:	166	147	123
Corporate Segment and Other Operating Segment [Member] | Operating Segments
Segment Reporting Information [Line Items]
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses:	$ 20	$ 40	$ 80

Reportable Segments Equity in E

Reportable Segments Equity in Earnings of Affiliates (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	[1]	$ 379	$ 383	$ 257
Intrastate Transportation and Storage
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	[1]	16	17	17
Interstate Transportation and Storage
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	[1]	241	260	175
Midstream
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	[1]	13	15	19
NGL and Refined Products Transportation and Services
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	[1]	83	76	44
Crude Oil Transportation and Services
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	[1]	21	11	(2)
All Other
Segment Reporting Information [Line Items]
Equity in earnings of unconsolidated affiliates	[1]	$ 5	$ 4	$ 4
[1] Amounts reflected above exclude Sunoco LP’s earnings from the ET-S Permian and J.C. Nolan joint ventures, which are eliminated in consolidation.

Reportable Segments Depreciatio

Reportable Segments Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	$ 5,165	$ 4,385	$ 4,164
Intrastate Transportation and Storage
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	216	214	209
Interstate Transportation and Storage
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	575	563	513
Midstream
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	1,719	1,451	1,351
NGL and Refined Products Transportation and Services
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	1,026	915	865
Crude Oil Transportation and Services
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	965	740	663
Investment in Sunoco LP
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	368	187	193
Investment in USAC
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	265	246	237
All Other
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	$ 31	$ 69	$ 133