0001276187-24-000024 | 10-K | XBRL Viewer

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Investments in Affiliates (Summarized Income Statement Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Revenues	$ 78,586	$ 89,876	$ 67,417
Net income	5,294	5,868	6,687
Equity Method Investments [Member]
Schedule of Equity Method Investments [Line Items]
Revenues	1,798	1,518	1,393
Equity Method Investments Summarized Financial Information, Operating Income	1,012	704	684
Net income	$ 735	$ 463	$ 446

- Definition

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

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- Definition

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

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+ Details

Revenue (Policies)	12 Months Ended
Revenue (Policies)	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Disaggregation of revenue The major types of revenue within our reportable segments are as follows: •intrastate transportation and storage; •interstate transportation and storage; •midstream; •NGL and refined products transportation and services; •crude oil transportation and services; •investment in Sunoco LP; •fuel distribution and marketing; •all other; •investment in USAC; •contract operations; •retail parts and services; and •all other. Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly owned subsidiary of Royal Dutch Shell plc (“Shell”). Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed. The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal. The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. Midstream revenue Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed and/or transported. The various types of revenue contracts our midstream segment enters into include: Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed. Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed. Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below: •In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed. •Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers. NGL and refined products transportation and services revenue Our NGL and refined products transportation and services segment’s revenues are primarily derived from transportation, fractionation, blending and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic 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 and marketing revenue Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to dealers, sales to distributors, unbranded wholesale revenue, commission agent revenue, rental income and other income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method. Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. 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 FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized. Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer. Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor is recognized ratably over the term of the underlying lease. Sunoco LP’s all other revenue Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided). USAC’s contract operations revenue USAC’s revenue from contracted compression, 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.

Advances to and Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2023

Investment In Affiliates [Abstract]

Investments In Affiliates

INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

Description of Investments

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

Citrus

Energy Transfer owns a 50% interest in Citrus. Citrus owns 100% of FGT, an approximately 5,362-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment.

MEP

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

White Cliffs

Energy Transfer owns a 51% interest in White Cliffs, which consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline. These pipelines transport crude and NGLs from Platteville, Colorado to Cushing, Oklahoma.

Explorer

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

Summary of Balances Related to Unconsolidated Affiliates

The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2023 and 2022 were as follows:


	December 31,
	2023		2022
Citrus	$	1,811	$	1,800

MEP	332		360
White Cliffs	203		218
Explorer	67		69
Other	684		446
Total	$	3,097	$	2,893

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


	Years Ended December 31,
	2023		2022		2021
Citrus	$	146	$	141	$	157

MEP	87		10		(17)
White Cliffs	10		(8)		—
Explorer	37		25		24
Other	103		89		82
Total equity in earnings of unconsolidated affiliates	$	383	$	257	$	246

Summarized Financial Information

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


	December 31,
	2023		2022
Current assets	$	378	$	311
Property, plant and equipment, net	7,582		7,722
Other assets	88		86
Total assets	$	8,048	$	8,119

Current liabilities	$	260	$	291
Non-current liabilities	4,379		4,347
Equity	3,409		3,481
Total liabilities and equity	$	8,048	$	8,119


	Years Ended December 31,
	2023		2022		2021
Revenue	$	1,798	$	1,518	$	1,393
Operating income	1,012		704		684
Net income	735		463		446

In addition to the equity method investments described above, we have other equity method investments which are not significant to our consolidated financial statements.

Acquisitions and Related Transactions Acquisitions (Details) $ / shares in Units, NAƒ in Millions									1 Months Ended		3 Months Ended	12 Months Ended
	Jan. 24, 2024 USD ($) shares	Jan. 11, 2024 USD ($)	Jan. 11, 2024 ANG (NAƒ)	Nov. 03, 2023 USD ($) $ / shares shares	May 02, 2023 USD ($) shares	May 01, 2023 USD ($)	Apr. 01, 2022 USD ($)	Dec. 02, 2021 USD ($) shares	Nov. 30, 2022 USD ($)	Feb. 28, 2021 USD ($) shares	Dec. 31, 2023 USD ($) shares	Dec. 31, 2023 USD ($) shares	Dec. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($)	Jan. 22, 2024
Business Acquisition [Line Items]
Goodwill												$ 1,455,000,000	$ 33,000,000
Impairment losses and other												12,000,000	$ 386,000,000	$ 21,000,000
Deconsolidation, Gain (Loss), Amount												$ 85,000,000
Preferred Units, Issued \| shares											113,648,967	113,648,967	72,184,780
Sunoco LP [Member]
Business Acquisition [Line Items]
Goodwill							$ 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
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												51.00%
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
Woodford Express Acquisition
Business Acquisition [Line Items]
Repayments of Debt												292,000,000
Total consideration, net of cash received												$ 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				$ 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
Total consideration, net of cash received				3,645,000,000
Cash received				$ 12,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares				216,000,000
Total current assets				$ 657,000,000
Property, plant and equipment, net				4,772,000,000
Investments in unconsolidated affiliates				95,000,000
Lease right-of-use assets, net				27,000,000
Other non-current assets				12,000,000
Total current liabilities				445,000,000
Long-term debt, less current maturities				3,461,000,000
Other non-current liabilities				322,000,000
Total liabilities assumed				4,228,000,000
Total consideration				3,657,000,000
Noncontrolling interests				272,000,000
Payments to Acquire Businesses, Gross				300,000,000
Crestwood Acquisition \| Senior Notes [Member]
Business Acquisition [Line Items]
Long-term debt, less current maturities				2,850,000,000
Crestwood Acquisition \| Revolving Credit Facility
Business Acquisition [Line Items]
Long-term debt, less current maturities				$ 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
Total consideration, net of cash received					1,504,000,000
Cash received					$ 4,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares					44,500,000
Total current assets					$ 61,000,000
Property, plant and equipment, net					1,263,000,000
Investments in unconsolidated affiliates					138,000,000
Lease right-of-use assets, net					10,000,000
Other non-current assets					4,000,000
Total current liabilities					27,000,000
Other non-current liabilities					16,000,000
Total liabilities assumed					43,000,000
Total consideration					1,508,000,000
Payments to Acquire Businesses, Gross					930,000,000
Equity Issued in Business Combination, Fair Value Disclosure					$ 574,000,000
Zenith Energy \| Sunoco LP [Member]
Business Acquisition [Line Items]
Other Payments to Acquire Businesses						$ 111,000,000
Number of Units in Real Estate Property						16
Zenith Energy \| Sunoco LP [Member] \| Subsequent Event [Member]
Business Acquisition [Line Items]
Business Combination, Price of Acquisition, Expected \| NAƒ			NAƒ 170
Enable
Business Acquisition [Line Items]
Goodwill								$ 138,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill								440,000,000
Total assets acquired								8,326,000,000
Total consideration, net of cash received								3,458,000,000		$ 10,000,000
Cash received								61,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares										0.8595
Total current assets								593,000,000
Property, plant and equipment, net								7,076,000,000
Other non-current assets								39,000,000
Total current liabilities								488,000,000
Long-term debt, less current maturities								4,267,000,000
Other non-current liabilities								18,000,000
Total liabilities assumed								4,773,000,000
Total consideration								3,519,000,000
Noncontrolling interests								34,000,000
Senior Notes								3,180,000,000
Enable \| Enable 2019 Term Loan Agreement
Business Acquisition [Line Items]
Line of Credit Facility, Current Borrowing Capacity								800,000,000
Enable \| Enable Five-Year Revolving Credit Facility
Business Acquisition [Line Items]
Line of Credit Facility, Current Borrowing Capacity								$ 35,000,000
Enable \| Series G Preferred Units [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares										0.0265
Preferred Units, Issued \| shares								384,780
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned								$ 3,500,000,000
Nustar Acquisition \| Sunoco LP [Member] \| Subsequent Event [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares	0.4
Business Combination, Price of Acquisition, Expected	$ 7,300,000,000
Nustar Acquisition \| Sunoco LP [Member] \| Subsequent Event [Member] \| Miles of pipeline [Member]
Business Acquisition [Line Items]
Number of Units in Real Estate Property															9,500
Nustar Acquisition \| Sunoco LP [Member] \| Subsequent Event [Member] \| Terminal and storage facilities [Member]
Business Acquisition [Line Items]
Number of Units in Real Estate Property															63
7-Eleven \| Sunoco LP [Member] \| Subsequent Event [Member]
Business Acquisition [Line Items]
Number of Units in Real Estate Property		204	204
Business Combination, Price of Acquisition, Expected		$ 1,000,000,000.00

Cover Page Cover Page - USD ($) $ in Millions	12 Months Ended
Cover Page Cover Page - USD ($) $ in Millions	Dec. 31, 2023	Feb. 09, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
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			$ 35,670
Entity Common Stock, Shares Outstanding		3,367,757,556
Documents Incorporated by Reference	None
Entity Central Index Key	0001276187
Document Fiscal Year Focus	2023
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, 2023
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
ETprC
Cover [Abstract]
Title of 12(b) Security	7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprC
Security Exchange Name	NYSE
Document Information [Line Items]
Title of 12(b) Security	7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprC
Security Exchange Name	NYSE
ETprD
Cover [Abstract]
Title of 12(b) Security	7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprD
Security Exchange Name	NYSE
Document Information [Line Items]
Title of 12(b) Security	7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprD
Security Exchange Name	NYSE
ETprE
Cover [Abstract]
Title of 12(b) Security	7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprE
Security Exchange Name	NYSE
Document Information [Line Items]
Title of 12(b) Security	7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Trading Symbol	ETprE
Security Exchange Name	NYSE
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

Revenue from Contract with Customer - Performance Obligation (Details) $ in Millions	Dec. 31, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 39,096
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	$ 7,590
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2024
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	$ 6,497
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2025
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	$ 5,769
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2026
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	$ 19,240
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2027
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	2028

Retirement Benefits Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023						December 31, 2022
	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	$	22	$	19	$	148	$	50	$	26	$	195
Service cost	—		—		—		—		—		1
Interest cost	1		1		6		1		1		4

Benefits paid, net	(1)		(3)		(13)		(1)		(3)		(14)

Actuarial gain and other	1		—		(3)		(8)		(3)		(38)

Energy Transfer Canada sale	—		—		—		(20)		(2)		—
Benefit obligation at end of period	23		17		138		22		19		148

Change in plan assets:
Fair value of plan assets at beginning of period	20		—		259		44		—		311
Return on plan assets and other	2		—		29		(4)		—		(41)
Employer contributions	1		—		2		1		—		3
Benefits paid, net	(1)		—		(13)		(1)		—		(14)

Energy Transfer Canada sale	—		—		—		(20)		—		—
Fair value of plan assets at end of period	22		—		277		20		—		259

Amount underfunded (overfunded) at end of period	$	1	$	17	$	(139)	$	2	$	19	$	(111)

Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	$	—	$	—	$	155	$	—	$	—	$	127
Current liabilities	—		(3)		(2)		—		(3)		(2)
Non-current liabilities	(1)		(14)		(14)		(2)		(16)		(14)
	$	(1)	$	(17)	$	139	$	(2)	$	(19)	$	111

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	$	—	$	(2)	$	(12)	$	—	$	(2)	$	5
Prior service credit	—		—		(3)		—		—		(3)
	$	—	$	(2)	$	(15)	$	—	$	(2)	$	2

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, 2023						December 31, 2022
	Pension Benefits						Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits		Funded Plans		Unfunded Plans		Other Postretirement Benefits
Projected benefit obligation	$	23	$	15	N/A		$	22	$	19	N/A
Accumulated benefit obligation	23		17		$	138	22		19		$	148
Fair value of plan assets	22		—		277		20		—		259

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,
	2023		2022
Health care cost trend rate	7.42	%	7.48	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.17	%	5.18	%
Year that the rate reaches the ultimate trend rate	2031		2030

Fair Value of Plan Assets [Table Text Block]

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


			Fair Value Measurements at December 31, 2023
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	2	$	2	$	—	$	—
Mutual funds (1)	20		20		—		—

Total	$	22	$	22	$	—	$	—

(1)Comprised of approximately 100% equities as of December 31, 2023.


			Fair Value Measurements at December 31, 2022
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	2	$	2	$	—	$	—
Mutual funds (1)	18		18		—		—

Total	$	20	$	20	$	—	$	—

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

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


			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.


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

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

The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.

Schedule of Expected Benefit Payments [Table Text Block]

Benefit Payments

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)
2024	$	1	$	3	$	14
2025	1		3		14
2026	1		2		13
2027	1		2		12
2028	1		2		32
2029 – 2033	7		5		23

Schedule of Net Benefit Costs [Table Text Block]

Components of Net Periodic Benefit Cost


	December 31, 2023				December 31, 2022
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—	$	—	$	—	$	1
Interest cost	1		6		2		4
Expected return on plan assets	(1)		(12)		(2)		(11)
Prior service cost amortization	—		2		—		19
Actuarial gain amortization	—		(1)		—		—



Net periodic benefit cost	$	—	$	(5)	$	—	$	13

Defined Benefit Plan, Assumptions [Table Text Block]

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


	December 31, 2023				December 31, 2022
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	2.70	%	4.62	%	5.00	%	2.46	%

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


	December 31, 2023				December 31, 2022
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	2.70	%	4.93	%	2.70	%	2.58	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%	7.00	%
Taxable accounts	—		4.75	%	—		4.75	%

Estimates (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Commodity derivatives:	$ 610	$ 688
Other Assets, Fair Value Disclosure	31	27
Total assets	647	715
Interest rate derivatives	(4)	(23)
Commodity derivatives:	(460)	(526)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(464)	(549)
Interest Rate Derivative Assets, at Fair Value	6	0
Level 1 [Member]
Commodity derivatives:	602	626
Other Assets, Fair Value Disclosure	20	18
Total assets	622	644
Interest rate derivatives	0	0
Commodity derivatives:	(460)	(473)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(460)	(473)
Interest Rate Derivative Assets, at Fair Value	0	0
Level 2 [Member]
Commodity derivatives:	8	62
Other Assets, Fair Value Disclosure	11	9
Total assets	25	71
Interest rate derivatives	(4)	(23)
Commodity derivatives:	0	(53)
Financial and Nonfinancial Liabilities, Fair Value Disclosure	(4)	(76)
Interest Rate Derivative Assets, at Fair Value	6	0
Commodity Derivatives - Power [Member] \| Forwards Swaps [Member]
Commodity derivatives:	57	52
Commodity derivatives:	(56)	(51)
Commodity Derivatives - Power [Member] \| Future [Member]
Commodity derivatives:	8	3
Commodity derivatives:	(8)	(3)
Commodity Derivatives - Power [Member] \| Level 1 [Member] \| Forwards Swaps [Member]
Commodity derivatives:	57	0
Commodity derivatives:	(56)
Commodity Derivatives - Power [Member] \| Level 1 [Member] \| Future [Member]
Commodity derivatives:	8	3
Commodity derivatives:	(8)	(3)
Commodity Derivatives - Power [Member] \| Level 2 [Member] \| Forwards Swaps [Member]
Commodity derivatives:	0	52
Commodity derivatives:	0	(51)
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:	35	20
Commodity derivatives:	(18)	(59)
Commodity Derivatives - Refined Products [Member] \| Level 1 [Member] \| Future [Member]
Commodity derivatives:	35	20
Commodity derivatives:	(18)	(59)
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:	45	38
Commodity derivatives:	(37)	(12)
Commodity Derivatives - Crude [Member] \| Level 1 [Member] \| Forwards Swaps [Member]
Commodity derivatives:	45	38
Commodity derivatives:	(37)	(12)
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:	24	60
Commodity derivatives:	(3)	(25)
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives:	20	75
Commodity derivatives:	(2)	(12)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives:	77	113
Commodity derivatives:	(16)	(4)
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Contracts [Member]
Commodity derivatives:		(2)
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Swaps [Member]
Commodity derivatives:	8	10
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:	24	60
Commodity derivatives:	(3)	(25)
Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Swing Swaps IFERC [Member]
Commodity derivatives:	20	75
Commodity derivatives:	(2)	(12)
Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Fixed Swaps/Futures [Member]
Commodity derivatives:	77	113
Commodity derivatives:	(16)	(4)
Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Forward Physical Contracts [Member]
Commodity derivatives:		0
Commodity Derivatives - Natural Gas [Member] \| Level 1 [Member] \| Forward Physical Swaps [Member]
Commodity derivatives:	0	0
Commodity Derivatives - Natural Gas [Member] \| Level 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 Contracts [Member]
Commodity derivatives:		(2)
Commodity Derivatives - Natural Gas [Member] \| Level 2 [Member] \| Forward Physical Swaps [Member]
Commodity derivatives:	8	10
Commodity Derivatives - Natural Gas [Member] \| Level 2 [Member] \| Put Option [Member]
Commodity derivatives:	0
Commodity Derivatives - NGLs [Member] \| Forwards Swaps [Member]
Commodity derivatives:	336	317
Commodity derivatives:	(316)	(358)
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:	336	317
Commodity derivatives:	(316)	(358)
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

Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Changes in Unrecognized Tax Benefits [Abstract]
Balance at beginning of year	$ 52	$ 56	$ 90
Reduction attributable to tax positions taken in prior years	(9)	(4)	(34)
Tax Adjustments, Settlements, and Unusual Provisions	(3)	0	0
Balance at end of year	$ 40	$ 52	$ 56

Net Income Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
NET INCOME	$ 5,294	$ 5,868	$ 6,687
Less: Net income attributable to redeemable noncontrolling interests	60	51	50
NET INCOME ATTRIBUTABLE TO PARTNERS	3,935	4,756	5,470
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units	(1)	(2)	(2)
Diluted income available to Common Unitholders	$ 3,468	$ 4,328	$ 5,177
Weighted average common units	3,161.7	3,086.8	2,734.4
Basic	$ 1.10	$ 1.40	$ 1.89
Dilutive effect of unconverted unit awards and ET Series A Convertible Preferred Units	15.5	10.2	5.1
Weighted average common units, assuming dilutive effect of unvested unit awards	3,177.2	3,097.0	2,739.5
Diluted	$ 1.09	$ 1.40	$ 1.89
Limited Partners’ interest in net income	$ 3,469	$ 4,330	$ 5,179
Less: Net income attributable to noncontrolling interests	1,299	1,061	1,167
General Partner’s interest in net income	(3)	(4)	(6)
Preferred Unitholders’ interest in net income	$ 463	$ 422	$ 285

Derivative Assets And Liabilities (Tables)

12 Months Ended

Dec. 31, 2023

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Offsetting Assets [Table Text Block]


		Asset Derivatives				Liability Derivatives
	Balance Sheet Location	December 31, 2023		December 31, 2022		December 31, 2023		December 31, 2022
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	6	$	—	$	(4)	$	(23)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	132		95		(80)		(108)
Broker cleared derivative contracts	Other current assets (liabilities)	478		593		(380)		(418)
		616		688		(464)		(549)
Offsetting agreements:

Counterparty netting	Derivative assets (liabilities)	(72)		(85)		72		85
Counterparty netting	Other current assets (liabilities)	(368)		(359)		368		359
Total net derivatives		$	176	$	244	$	(24)	$	(105)

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:


	December 31, 2023		December 31, 2022
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	(1,878)	2024-2025	145	2023
Basis Swaps IFERC/NYMEX(1)	(171,185)	2024	(39,563)	2023
Swing Swaps	(900)	2024	—	—
Options – Puts	1,900	2024	—	—
Options - Calls	250	2024	—	—
Power (Megawatt):
Forwards	155,600	2024-2029	—	2023-2029
Futures	(464,897)	2024	(21,384)	2023
Options – Puts	136,000	2024	119,200	2023

Crude (MBbls):
Option - Puts	(15)	2024	—	—
Option - Calls	(20)	2024	—	—
NGL/Refined Products (MBbls):
Option - Puts	121	2024-2026	—	—
Option - Calls	(43)	2024-2026	—	—
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	124,210	2024-2025	42,440	2023-2024
Swing Swaps IFERC	(96,828)	2024-2025	(202,815)	2023-2024
Fixed Swaps/Futures	7,125	2024-2026	(15,758)	2023-2025
Forward Physical Contracts	(1,751)	2024-2026	2,423	2023-2024

NGL (MBbls) – Forwards/Swaps	(13,870)	2024-2027	6,934	2023-2025
Crude (MBbls) – Forwards/Swaps	(2,674)	2024-2025	795	2023-2024
Refined Products (MBbls) – Futures	(4,548)	2024-2025	(3,547)	2023-2024

Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(39,013)	2024	(37,448)	2023
Fixed Swaps/Futures	(39,013)	2024	(37,448)	2023
Hedged Item – Inventory	39,013	2024	37,448	2023

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

Interest Rate Swaps Outstanding

The following table summarizes our interest rate swaps outstanding (including USAC’s), none of which were designated as hedges for accounting purposes:

Term

Type

Notional Amount Outstanding

December 31, 2023

December 31, 2022

Energy Transfer

July 2024 (1)

Forward-starting to pay a fixed rate of 3.388% and receive a floating rate based on SOFR

—

400

USAC

December 2025

Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR

700

—

(1)The July 2024 interest rate swaps were terminated and settled in August 2023.

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, 2023		December 31, 2022		December 31, 2023		December 31, 2022
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	51	$	87	$	(6)	$	(7)
	51		87		(6)		(7)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	427		506		(374)		(411)
Commodity derivatives	132		95		(80)		(108)



Interest rate derivatives	6		—		(4)		(23)
	565		601		(458)		(542)
Total derivatives	$	616	$	688	$	(464)	$	(549)

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,
		2023		2022		2021
Derivatives not designated as hedging instruments:

Commodity derivatives – Trading	Cost of products sold	$	7	$	83	$	(6)
Commodity derivatives – Non-trading	Cost of products sold	40		41		(141)

Interest rate derivatives	Gains (losses) on interest rate derivatives	36		293		61

Total		$	83	$	417	$	(86)

- Definition

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

+ References + Details

Retirement Benefits (Accumulated Benefit Obligation In Excess of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation		$ 22	$ 50
Fair value of plan assets	$ 22	20
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	138	148	195
Fair value of plan assets	277	259	311
Funded Plans [Member] \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	23	22
Accumulated benefit obligation	23	22
Fair value of plan assets	22	20	44
Unfunded Plans [Member] \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	15	19
Accumulated benefit obligation	17	19	26
Fair value of plan assets	$ 0	$ 0	$ 0

- Definition

Amount of asset segregated and restricted to provide benefit under defined benefit plan. Asset includes, but is not limited to, stock, bond, other investment, earning from investment, and contribution by employer and employee.

+ References + Details

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) $ in Millions	Dec. 31, 2023 USD ($)
Debt Obligations [Abstract]
2024	$ 4,672
2025	2,900
2026	4,147
2027	6,823
2028	4,200
Thereafter	29,756
Long-term Debt	$ 52,498
Schedule of Capitalization, Long-Term Debt [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
2024	$ 4,672
2025	2,900
2026	4,147
2027	6,823
2028	4,200
Thereafter	29,756
Long-term Debt, Gross	$ 52,498
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	2024
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	2025
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	2026
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	2027
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	2028

Reportable Segments (Advances to and investments in affiliates) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	$ 3,097	$ 2,893	$ 2,947
Intrastate Transportation and Storage
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	144	139	110
Interstate Transportation and Storage
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	2,179	2,201	2,209
Midstream
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	141	54	101
NGL and Refined Products Transportation and Services
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	390	398	457
Crude Oil Transportation and Services
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	187	48	19
All Other
Segment Reporting Information [Line Items]
Investments in unconsolidated affiliates	$ 56	$ 53	$ 51

Debt Obligations

12 Months Ended

Dec. 31, 2023

Debt Obligations [Abstract]

Debt Disclosure [Text Block]

DEBT OBLIGATIONS:

Our debt obligations consist of the following:


	December 31,
	2023	2022
Energy Transfer Indebtedness














3.45% Senior Notes due January 15, 2023(1)	—	350
3.60% Senior Notes due February 1, 2023(1)	—	800
4.25% Senior Notes due March 15, 2023(1)	—	5
4.25% Senior Notes due March 15, 2023(1)	—	995
4.20% Senior Notes due September 15, 2023(1)	—	500
4.50% Senior Notes due November 1, 2023(1)	—	600
5.875% Senior Notes due January 15, 2024(2)(3)	23	23
5.875% Senior Notes due January 15, 2024(2)(3)	1,127	1,127
7.60% Senior Notes due February 1, 2024(2)(3)	82	82
4.90% Senior Notes due February 1, 2024(2)(3)	350	350
7.60% Senior Notes due February 1, 2024(1)	—	277
4.25% Senior Notes due April 1, 2024(3)	500	500
4.50% Senior Notes due April 15, 2024(3)	750	750
3.90% Senior Notes due May 15, 2024(3)	600	600
9.00% Debentures due November 1, 2024(3)	65	65
4.05% Senior Notes due March 15, 2025	1,000	1,000
5.75% Senior Notes due April 1, 2025(4)	500	—
2.90% Senior Notes due May 15, 2025	1,000	1,000
5.95% Senior Notes due December 1, 2025	400	400
4.75% Senior Notes due January 15, 2026	1,000	1,000
3.90% Senior Notes due July 15, 2026	550	550
6.05% Senior Notes due December 1, 2026	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(4)	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	—
6.00% Senior Notes due February 1, 2029(4)	700	—
8.00% Senior Notes due April 1, 2029(4)	450	—
5.25% Senior Notes due April 15, 2029	1,500	1,500
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	—
7.38% Senior Notes due April 1, 2031(4)	600	—
5.75% Senior Notes due February 15, 2033	1,500	1,500


4.05% Tax-Exempt Bonds due June 1, 2033(5)	225	—
6.55% Senior Notes due December 1,2033	1,500	—
4.90% Senior Notes due March 15, 2035	500	500
6.625% Senior Notes due October 15, 2036	400	400
5.80% Senior Notes due June 15, 2038	500	500
7.50% Senior Notes due July 1, 2038	550	550
6.85% Senior Notes due February 15, 2040	250	250
6.05% Senior Notes due June 1, 2041	700	700
6.50% Senior Notes due February 1, 2042	1,000	1,000
6.10% Senior Notes due February 15, 2042	300	300
4.95% Senior Notes due January 15, 2043	350	350
5.15% Senior Notes due February 1, 2043	450	450
5.95% Senior Notes due October 1, 2043	450	450
5.30% Senior Notes due April 1, 2044	700	700
5.00% Senior Notes due May 15, 2044	531	531
5.15% Senior Notes due March 15, 2045	1,000	1,000
5.35% Senior Notes due May 15, 2045	800	800
6.125% Senior Notes due December 15, 2045	1,000	1,000
5.30% Senior Notes due April 15, 2047	900	900
5.40% Senior Notes due October 1, 2047	1,500	1,500
6.00% Senior Notes due June 15, 2048	1,000	1,000
6.25% Senior Notes due April 15, 2049	1,750	1,750
5.00% Senior Notes due May 15, 2050	2,000	2,000
Floating Rate Junior Subordinated Notes due November 1, 2066	600	600

Five-Year Credit Facility	1,412	793

Unamortized premiums, discounts and fair value adjustments, net	128	184
Deferred debt issuance costs	(197)	(181)
	44,359	40,264

Subsidiary Indebtedness
Transwestern Debt


5.66% Senior Notes due December 9, 2024(3)	175	175
6.16% Senior Notes due May 24, 2037	75	75

	250	250




Bakken Project Debt

3.90% Senior Notes due April 1, 2024	1,000	1,000
4.625% Senior Notes due April 1, 2029	850	850

Unamortized premiums, discounts and fair value adjustments, net	(1)	(1)
Deferred debt issuance costs	(4)	(7)
	1,845	1,842


Sunoco LP Debt
6.00% Senior Notes Due April 15, 2027	600		600
5.875% Senior Notes Due March 15, 2028	400		400
7.00% Senior Notes due September 25, 2028	500		—
4.50% Senior Notes due May 15, 2029	800		800
4.50% Senior Notes due April 30, 2030	800		800
Sunoco LP Credit Facility due April 7, 2027	411		900
Lease-related obligations	94		94
Deferred debt issuance costs	(25)		(23)
	3,580		3,571

USAC Debt
6.875% Senior Notes due April 1, 2026	725		725
6.875% Senior Notes due September 1, 2027	750		750
USAC Credit Facility due December 2026(6)	872		646

Deferred debt issuance costs	(11)		(14)
	2,336		2,107

HFOTCO Debt
HFOTCO Tax Exempt Notes due 2050 (5)	—		225


	—		225








Other long-term debt	18		3
Total debt	52,388		48,262
Less: Current maturities of long-term debt	1,008		2
Long-term debt, less current maturities	$	51,380	$	48,260

(1)These notes were redeemed in 2023.

(2)These notes were redeemed subsequent to December 31, 2023.

(3)As of December 31, 2023, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.

(4)These notes, totaling $2.85 billion aggregate principal amount, were assumed by the Partnership in connection with the closing of the Crestwood acquisition in November 2023.

(5)In May 2023, the Partnership refinanced all of the $225 million outstanding principal amount of HFOTCO tax-exempt bonds with new 10-year tax-exempt bonds. The new bonds, which were issued through the Harris County Industrial Development Corporation and are obligations of Energy Transfer, accrue interest at a fixed rate of 4.05% and are mandatorily redeemable in 2033. Upon redemption, these tax-exempt bonds may be remarketed on different terms through final maturity of November 1, 2050.

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

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $237 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net:


2024	$	4,672
2025	2,900
2026	4,147
2027	6,823
2028	4,200
Thereafter	29,756
Total	$	52,498

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.

January 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 intends to use the proceeds to redeem its Series E Preferred Units in May 2024.

Credit Facilities and Commercial Paper

Five-Year Credit Facility

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

As of December 31, 2023, the Five-Year Credit Facility had $1.41 billion of outstanding borrowings, $1.37 billion of which consisted of commercial paper. The amount available for future borrowings was $3.56 billion, after accounting for outstanding letters of credit in the amount of $29 million. The weighted average interest rate on the total amount outstanding as of December 31, 2023 was 5.87%.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”). As of December 31, 2023, the Sunoco LP Credit Facility had $411 million of outstanding borrowings and $5 million in standby letters of credit and matures in April 2027. The amount available for future borrowings was $1.08 billion at December 31, 2023. The weighted average interest rate on the total amount outstanding as of December 31, 2023 was 7.54%.

USAC Credit Facility

USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”) which matures on December 8, 2026, except that if any portion of USAC’s senior notes due 2026 are outstanding on December 31, 2025, the USAC Credit Facility will mature on December 31, 2025. As of December 31, 2023, USAC had $872 million of outstanding borrowings

and no outstanding letters of credit under the credit agreement. As of December 31, 2023, USAC had $728 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $529 million was available to be drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2023 was 7.98%.

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 3.31 to 1.00 at December 31, 2023, 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, 2023.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480678/235-10-S99-1

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 470
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//470/tableOfContent

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1B

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1C

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1E
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1E

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1I
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481139/470-20-50-1I

+ Details

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

3 Months Ended

12 Months Ended

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

Sep. 30, 2021

Jun. 30, 2021

Mar. 31, 2021

Dec. 31, 2020

Dec. 31, 2023

Feb. 15, 2028

May 15, 2024

Parent Company [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.3150

$ 0.3125

$ 0.3100

$ 0.3075

$ 0.3050

$ 0.2650

$ 0.2300

$ 0.2000

$ 0.1750

$ 0.1525

USAC [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.5250

Sunoco LP [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

0.8420

0.8255

$ 0.8255

Minimum Quarterly Distribution [Member]

Distribution Payment Targets

$0.4375

First Target Distribution [Member]

Distribution Payment Targets

$0.4375 to $0.503125

Second Target Distribution [Member]

Distribution Payment Targets

$0.503125 to $0.546875

Third Target Distribution [Member]

Distribution Payment Targets

$0.546875 to $0.656250

Thereafter [Member]

Distribution Payment Targets

Above $0.656250

Common Stock | Minimum Quarterly Distribution [Member]

Distribution Payment Targets

100%

Common Stock | First Target Distribution [Member]

Distribution Payment Targets

100%

Common Stock | Second Target Distribution [Member]

Distribution Payment Targets

85%

Common Stock | Third Target Distribution [Member]

Distribution Payment Targets

75%

Common Stock | Thereafter [Member]

Distribution Payment Targets

50%

IDRs [Member] | Minimum Quarterly Distribution [Member]

Distribution Payment Targets

—%

IDRs [Member] | First Target Distribution [Member]

Distribution Payment Targets

—%

IDRs [Member] | Second Target Distribution [Member]

Distribution Payment Targets

15%

IDRs [Member] | Third Target Distribution [Member]

Distribution Payment Targets

25%

IDRs [Member] | Thereafter [Member]

Distribution Payment Targets

50%

Series A Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

$ 24.71

24.67

23.89

21.98

31.25

^[2]

31.25

Preferred Units, Liquidation Spread, Percent

4.028%

Series A Preferred Units [Member] | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series B Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

$ 33.125

33.125

^[2]

33.125

Series B Preferred Units [Member] | Subsequent Event [Member]

Preferred Units, Liquidation Spread, Percent

4.155%

Series B Preferred Units [Member] | Subsequent Event [Member] | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series C Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.6075

0.6489

0.6294

0.4609

Preferred Units, Liquidation Spread, Percent

4.53%

Series C Preferred Units [Member] | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series D Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.6199

0.6622

0.4766

^[2]

0.4766

Preferred Units, Liquidation Spread, Percent

4.738%

Series D Preferred Units [Member] | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series E Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.4750

0.4750

^[2]

0.4750

Series E Preferred Units [Member] | Subsequent Event [Member]

Preferred Units, Liquidation Spread, Percent

5.161%

Series E Preferred Units [Member] | Subsequent Event [Member] | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series F Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

33.7500

^[2]

33.7500

Series G Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

35.63

^[2]

35.63

Series H Preferred Units

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[1]

32.50

27.08

^[2]

Series I Preferred Units

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.2111

^[2]

$ 0

$ 0.2111

[1]	(1) Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Pursuant to their terms, distributions on the Series A preferred units began to be paid quarterly on February 15, 2023, and distributions on the Series B preferred units will begin to be paid quarterly on February 15, 2028.
[2]	* Represents prorated initial distribution.

Equity Incentive Plans

12 Months Ended

Dec. 31, 2023

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, 2023, an aggregate total of 42.9 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, 2022	37.7	$	9.62

Awards granted	10.7	13.78
Awards vested	(7.7)	9.22
Awards forfeited	(1.6)	9.52
Unvested awards as of December 31, 2023	39.1	$	10.84

During the years ended December 31, 2023, 2022, and 2021, the weighted average grant-date fair value per unit award granted was $13.78, $11.56 and $8.46, respectively, and the total fair value of awards vested was $106 million, $103 million and $52 million, respectively, based on the market price of the respective Common Units as of the vesting date. As of December 31, 2023, a total of 39.1 million unit awards remain unvested, for which Energy Transfer expects to recognize a total of $279 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, 2023, 2022 and 2021, the Partnership granted a total of 3.2 million, 3.8 million and 3.9 million cash restricted units, respectively. As of December 31, 2023, a total of 6.9 million cash restricted units were unvested. As of December 31, 2023, the Partnership’s consolidated balance sheet reflected aggregate liabilities of $3.0 million related to cash restricted units.

Subsidiary Long-Term Incentive Plans

Each of Sunoco LP and USAC has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards”) to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a three or five-year period, that entitles the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding.

The following table summarizes the activity of the Subsidiary Unit Awards:


	Sunoco LP			USAC
	Number of Units	Weighted Average Grant-Date Fair Value Per Unit		Number of Units	Weighted Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 2022	1.8	$	34.29	2.1	$	14.21
Awards granted	0.4	53.37		0.5	23.13
Awards vested	(0.6)	28.35		(0.6)	13.29
Awards forfeited	—	34.64		(0.1)	17.50
Unvested awards as of December 31, 2023	1.6	$	41.08	1.9	$	17.08

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


	Years Ended December 31,
	2023		2022		2021
Sunoco LP	$	53.37	$	43.54	$	37.72
USAC	23.13		18.31		14.92

The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2023, 2022 and 2021 was $37 million, $26 million and $24 million, respectively, based on the market price of Sunoco LP and USAC common units as of the vesting date. As of December 31, 2023, estimated compensation cost related to Subsidiary Unit Awards not yet

recognized was $55 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.5 years.

Acquisitions and Related Transactions

12 Months Ended

Dec. 31, 2023

Acquisitions and Dispositions [Abstract]

Acquisitions and Related Transactions

ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

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.

Enable Acquisition

On December 2, 2021, the Partnership completed the previously announced merger with Enable. Under the terms of the merger agreement, Enable’s common unitholders received 0.8595 of an Energy Transfer common unit in exchange for each

Enable common unit. In addition, each outstanding Enable Series A preferred unit was exchanged for 0.0265 of an Energy Transfer Series G Preferred Unit. A total of 384,780 Series G Preferred Units were issued in connection with the Enable acquisition. The total fair value of Energy Transfer common units and Series G Preferred Units issued was approximately $3.5 billion at the closing date. Energy Transfer also made a $10 million cash payment for Enable’s general partner and assumed $3.18 billion aggregate principal amount of Enable senior notes. In addition, Enable’s $800 million term loan and $35 million revolving credit facility were repaid and terminated in December 2021, immediately subsequent to the close of the Enable acquisition.

The Enable acquisition was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions. Acquired assets were valued based on a combination of the discounted cash flow, the guideline company and the reproduction and replacement methods.

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


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

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

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

Noncontrolling interests	34

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

Reportable Segments

12 Months Ended

Dec. 31, 2023

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS:

Our reportable segments currently reflect the following segments, which conduct their business primarily in the United States:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services;

•investment in Sunoco LP;

•investment in USAC; and

•all other.

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

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

We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as

non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items, 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 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,
	2023		2022		2021
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	3,222	$	6,954	$	7,307
Intersegment revenues	740		864		1,264
	3,962		7,818		8,571
Interstate transportation and storage:
Revenues from external customers	2,328		2,185		1,802
Intersegment revenues	47		66		39
	2,375		2,251		1,841
Midstream:
Revenues from external customers	2,911		4,114		2,620
Intersegment revenues	7,495		12,987		8,696
	10,406		17,101		11,316
NGL and refined products transportation and services:
Revenues from external customers	18,413		21,414		16,989
Intersegment revenues	3,490		4,243		2,972
	21,903		25,657		19,961
Crude oil transportation and services:
Revenues from external customers	26,534		25,980		17,442
Intersegment revenues	2		2		4
	26,536		25,982		17,446
Investment in Sunoco LP:
Revenues from external customers	23,026		25,677		17,571
Intersegment revenues	42		52		25
	23,068		25,729		17,596
Investment in USAC:
Revenues from external customers	824		689		621
Intersegment revenues	22		16		12
	846		705		633
All other:
Revenues from external customers	1,328		2,863		3,065
Intersegment revenues	470		711		411
	1,798		3,574		3,476
Eliminations	(12,308)		(18,941)		(13,423)
Total revenues	$	78,586	$	89,876	$	67,417


	Years Ended December 31,
	2023		2022		2021
Cost of products sold:
Intrastate transportation and storage	$	2,616	$	6,000	$	4,769
Interstate transportation and storage	6		25		11
Midstream	6,503		12,682		8,569
NGL and refined products transportation and services	17,049		21,656		16,248
Crude oil transportation and services	23,071		22,917		14,759
Investment in Sunoco LP	21,703		24,350		16,246
Investment in USAC	137		111		85
All other	1,740		3,328		3,068
Eliminations	(12,284)		(18,837)		(13,360)
Total cost of products sold	$	60,541	$	72,232	$	50,395


	Years Ended December 31,
	2023		2022		2021
Depreciation, depletion and amortization:
Intrastate transportation and storage	$	214	$	209	$	191
Interstate transportation and storage	563		513		457
Midstream	1,451		1,351		1,190
NGL and refined products transportation and services	915		865		778
Crude oil transportation and services	740		663		588
Investment in Sunoco LP	187		193		177
Investment in USAC	246		237		239
All other	69		133		197
Total depreciation, depletion and amortization	$	4,385	$	4,164	$	3,817


	Years Ended December 31,
	2023		2022		2021
Equity in earnings (losses) of unconsolidated affiliates:
Intrastate transportation and storage	$	17	$	17	$	20
Interstate transportation and storage	260		175		140
Midstream	15		19		24
NGL and refined products transportation and services	76		44		51
Crude oil transportation and services	11		(2)		10


All other	4		4		1
Total equity in earnings of unconsolidated affiliates	$	383	$	257	$	246


	Years Ended December 31,
	2023		2022		2021
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	1,111	$	1,396	$	3,483
Interstate transportation and storage	2,009		1,753		1,515
Midstream	2,525		3,210		1,868
NGL and refined products transportation and services	3,894		3,025		2,828
Crude oil transportation and services	2,681		2,187		2,023
Investment in Sunoco LP	964		919		754
Investment in USAC	512		426		398
All Other	2		177		177
Adjusted EBITDA (consolidated)	$	13,698	$	13,093	$	13,046


	Years Ended December 31,
	2023		2022		2021
Reconciliation of net income to Adjusted EBITDA:
Net income	$	5,294	$	5,868	$	6,687
Depreciation, depletion and amortization	4,385		4,164		3,817
Interest expense, net of interest capitalized	2,578		2,306		2,267
Income tax expense	303		204		184
Impairment losses and other	12		386		21
Gains on interest rate derivatives	(36)		(293)		(61)
Non-cash compensation expense	130		115		111
Unrealized gains on commodity risk management activities	(3)		(42)		(162)
Inventory valuation adjustments	114		(5)		(190)
(Gains) losses on extinguishments of debt	(2)		—		38
Adjusted EBITDA related to unconsolidated affiliates	691		565		523
Equity in earnings of unconsolidated affiliates	(383)		(257)		(246)

Non-operating litigation-related loss	627		—		—
Other, net	(12)		82		57
Adjusted EBITDA (consolidated)	$	13,698	$	13,093	$	13,046


	December 31,
	2023		2022		2021
Segment assets:
Intrastate transportation and storage	$	6,112	$	6,609	$	7,322
Interstate transportation and storage	17,708		17,979		17,774
Midstream	25,592		21,851		21,960
NGL and refined products transportation and services	27,214		27,903		28,160
Crude oil transportation and services	25,464		19,200		19,649
Investment in Sunoco LP	6,826		6,830		5,815
Investment in USAC	2,737		2,666		2,768
All other and eliminations	2,045		2,605		2,515
Total segment assets	$	113,698	$	105,643	$	105,963


	Years Ended December 31,
	2023		2022		2021
Additions to property, plant and equipment (1):
Intrastate transportation and storage	$	93	$	179	$	52
Interstate transportation and storage	383		644		159
Midstream	832		1,004		484
NGL and refined products transportation and services	679		507		751
Crude oil transportation and services	266		246		343
Investment in Sunoco LP	215		186		174
Investment in USAC	300		169		60
All other	100		91		135
Total additions to property, plant and equipment (1)	$	2,868	$	3,026	$	2,158

(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,
	2023		2022		2021
Investments in unconsolidated affiliates:
Intrastate transportation and storage	$	144	$	139	$	110
Interstate transportation and storage	2,179		2,201		2,209
Midstream	141		54		101
NGL and refined products transportation and services	390		398		457
Crude oil transportation and services	187		48		19


All other	56		53		51
Total investments in unconsolidated affiliates	$	3,097	$	2,893	$	2,947

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-22

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-15

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 31
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-31

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-42

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-40

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//280/tableOfContent

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-26

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 34
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-34

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-41

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-21

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482810/280-10-50-32

+ Details

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) $ in Millions	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Environmental Remediation Obligations [Abstract]
Current	$ 42	$ 54
Non-current	235	228
Total environmental liabilities	$ 277	$ 282
Site Contingency, Number of Sites Needing Remediation	32

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, 2023

Dec. 31, 2022

Dec. 31, 2021

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

$ 2,868

$ 3,026

$ 2,158

Investment in Sunoco LP

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

215

186

174

Intrastate Transportation and Storage

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

179

Interstate Transportation and Storage

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

383

644

159

Midstream

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

832

1,004

484

NGL and Refined Products Transportation and Services

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

679

507

751

Crude Oil Transportation and Services

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

266

246

343

Investment in USAC

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

300

169

All Other

Segment Reporting Information [Line Items]

Property, Plant and Equipment, Additions

^[1]

$ 100

$ 91

$ 135

[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 (Operating Segments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cost of Goods and Services Sold	$ (60,541)	$ (72,232)	$ (50,395)
Depreciation, depletion and amortization	4,385	4,164	3,817
Equity in earnings of unconsolidated affiliates	383	257	246
Intersegment Eliminations [Member]
Cost of Goods and Services Sold	(12,284)	(18,837)	(13,360)
Intrastate Transportation and Storage
Depreciation, depletion and amortization	214	209	191
Equity in earnings of unconsolidated affiliates	17	17	20
Intrastate Transportation and Storage \| Operating Segments
Cost of Goods and Services Sold	(2,616)	(6,000)	(4,769)
Investment in Sunoco LP
Depreciation, depletion and amortization	187	193	177
Investment in Sunoco LP \| Operating Segments
Cost of Goods and Services Sold	(21,703)	(24,350)	(16,246)
Interstate Transportation and Storage
Depreciation, depletion and amortization	563	513	457
Equity in earnings of unconsolidated affiliates	260	175	140
Interstate Transportation and Storage \| Operating Segments
Cost of Goods and Services Sold	(6)	(25)	(11)
Midstream
Depreciation, depletion and amortization	1,451	1,351	1,190
Equity in earnings of unconsolidated affiliates	15	19	24
Midstream \| Operating Segments
Cost of Goods and Services Sold	(6,503)	(12,682)	(8,569)
NGL and Refined Products Transportation and Services
Depreciation, depletion and amortization	915	865	778
Equity in earnings of unconsolidated affiliates	76	44	51
NGL and Refined Products Transportation and Services \| Operating Segments
Cost of Goods and Services Sold	(17,049)	(21,656)	(16,248)
Crude Oil Transportation and Services
Depreciation, depletion and amortization	740	663	588
Equity in earnings of unconsolidated affiliates	11	(2)	10
Crude Oil Transportation and Services \| Operating Segments
Cost of Goods and Services Sold	(23,071)	(22,917)	(14,759)
All Other
Depreciation, depletion and amortization	69	133	197
Equity in earnings of unconsolidated affiliates	4	4	1
All Other \| Operating Segments
Cost of Goods and Services Sold	(1,740)	(3,328)	(3,068)
Investment in USAC
Depreciation, depletion and amortization	246	237	239
Investment in USAC \| Operating Segments
Cost of Goods and Services Sold	$ (137)	$ (111)	$ (85)

Estimates (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Reported in depreciation and amortization	$ 399	$ 390	$ 352

Revenue (Tables)

12 Months Ended

Dec. 31, 2023

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, 2021	$	459
Additions	1,113
Revenue recognized	(944)
Other	(13)
Balance, December 31, 2022	615
Additions	1,254
Revenue recognized	(1,120)

Balance, December 31, 2023	$	749

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

As of December 31, 2023, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $39.10 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:


	Years Ending December 31,
	2024		2025		2026		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of December 31, 2023	$	7,590	$	6,497	$	5,769	$	19,240	$	39,096

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, 2023 and 2022 were as follows:


	December 31,
	2023		2022
Contract Balances
Contract assets	$	256	$	200
Accounts receivable from contracts with customers	809		834
Contract liabilities	—		—

Investments in Affiliates (Summarized Balance Sheet Information) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Schedule of Investments [Line Items]
Assets, Current	$ 12,433	$ 12,081
Other non-current assets, net	1,733	1,558
Assets	113,698	105,643	$ 105,963
Current Liabilities	11,277	10,368
Equity	43,939	40,659	$ 39,345	$ 31,388
Liabilities and Equity	113,698	105,643
Equity Method Investments [Member]
Schedule of Investments [Line Items]
Assets, Current	378	311
Property, plant and equipment, net	7,582	7,722
Other non-current assets, net	88	86
Assets	8,048	8,119
Current Liabilities	260	291
Non-current liabilities	4,379	4,347
Equity	3,409	3,481
Liabilities and Equity	$ 8,048	$ 8,119

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 5,294	$ 5,868	$ 6,687
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	4	(10)	1
Actuarial gain (loss) relating to pension and other postretirement benefits	13	(12)	12
Foreign currency translation adjustment	(6)	(6)	4
Change in other comprehensive income from unconsolidated affiliates	1	24	3
Other comprehensive income (loss), net of tax, total	12	(4)	20
Comprehensive income	5,306	5,864	6,707
Less: Comprehensive income attributable to noncontrolling interests	1,299	1,055	1,170
Less: Comprehensive income attributable to redeemable noncontrolling interests	60	51	50
Comprehensive income attributable to partners	$ 3,947	$ 4,758	$ 5,487

Lease Accounting - Cash flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Net cash provided by operating activities	$ 9,555	$ 9,051	$ 11,162
Lease assets obtained in exchange for new finance lease liabilities	18	1
Lease assets obtained in exchange for new operating lease liabilities	5	41
Operating Leases [Member]
Lessee, Lease, Description [Line Items]
Net cash provided by operating activities	$ (139)	$ (133)

Retirement Benefits (Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Change in benefit obligation:
Defined Benefit Plan, Plan Assets, Divestiture	$ 0	$ 0
Defined Benefit Plan, Benefit Obligation, Divestiture	0	0
Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	22	50
Service cost	0	0
Interest cost	1	2
Defined Benefit Plan, Benefit Obligation		22
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	20
Defined Benefit Plan, Plan Assets, Amount	22	20
Amounts recognized in the consolidated balance sheets consist of:
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position		(2)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
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	148	195
Service cost	0	1
Interest cost	6	4
Benefits paid, net	(13)	(14)
Actuarial gain and other	(3)	(38)
Defined Benefit Plan, Benefit Obligation	138	148
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	259	311
Return on plan assets and other	29	(41)
Employer contributions	2	3
Benefits paid, net	(13)	(14)
Defined Benefit Plan, Plan Assets, Amount	277	259
Amount underfunded (overfunded) at end of period	(139)	(111)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	155	127
Current liabilities	(2)	(2)
Non-current liabilities	(14)	(14)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	139	111
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	(12)	5
Prior service credit	(3)	(3)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	(15)	2
Funded Plans [Member] \| Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	22
Interest cost	1	1
Benefits paid, net	(1)	(1)
Actuarial gain and other	1	(8)
Defined Benefit Plan, Plan Assets, Divestiture	0	(20)
Defined Benefit Plan, Benefit Obligation, Divestiture	0	(20)
Defined Benefit Plan, Benefit Obligation	23	22
Change in plan assets:
Defined Benefit Plan, Plan Assets, Amount	20	44
Return on plan assets and other	2	(4)
Employer contributions	1	1
Benefits paid, net	(1)	(1)
Defined Benefit Plan, Plan Assets, Amount	22	20
Amount underfunded (overfunded) at end of period	1	2
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Current liabilities	0	0
Non-current liabilities	(1)	(2)
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:
Net actuarial gain (loss)	0	0
Prior service credit	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	0
Unfunded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Plan Assets, Divestiture	0	0
Defined Benefit Plan, Benefit Obligation, Divestiture	0	(2)
Unfunded Plans [Member] \| Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	19	26
Service cost	0	0
Interest cost	1	1
Benefits paid, net	(3)	(3)
Actuarial gain and other	0	(3)
Defined Benefit Plan, Benefit Obligation	17	19
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	17	19
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	0	0
Current liabilities	(3)	(3)
Non-current liabilities	(14)	(16)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	(17)	(19)
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	(2)	(2)
Prior service credit	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	$ (2)	$ (2)

Advances to and Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023 and 2022 were as follows:


	December 31,
	2023		2022
Citrus	$	1,811	$	1,800

MEP	332		360
White Cliffs	203		218
Explorer	67		69
Other	684		446
Total	$	3,097	$	2,893

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


	Years Ended December 31,
	2023		2022		2021
Citrus	$	146	$	141	$	157

MEP	87		10		(17)
White Cliffs	10		(8)		—
Explorer	37		25		24
Other	103		89		82
Total equity in earnings of unconsolidated affiliates	$	383	$	257	$	246

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


	December 31,
	2023		2022
Current assets	$	378	$	311
Property, plant and equipment, net	7,582		7,722
Other assets	88		86
Total assets	$	8,048	$	8,119

Current liabilities	$	260	$	291
Non-current liabilities	4,379		4,347
Equity	3,409		3,481
Total liabilities and equity	$	8,048	$	8,119


	Years Ended December 31,
	2023		2022		2021
Revenue	$	1,798	$	1,518	$	1,393
Operating income	1,012		704		684
Net income	735		463		446

In addition to the equity method investments described above, we have other equity method investments which are not significant to our consolidated financial statements.

Derivative Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) - Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member] - Forward-Starting Swaps [Member] - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

July 2024

Description of Interest Rate Derivative Activities

^[1]

Forward-starting to pay a fixed rate of 3.388% and receive a floating rate based on SOFR

Derivative, Notional Amount

^[1]

$ 0

$ 400

April 2025

Description of Interest Rate Derivative Activities

Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR

Derivative, Notional Amount

$ 700

$ 0

[1]	The July 2024 interest rate swaps were terminated and settled in August 2023.

Lease Accounting (Tables)

12 Months Ended

Dec. 31, 2023

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, 2023 and 2022 were as follows:


	December 31,
	2023		2022
Operating leases:
Lease right-of-use assets, net	$	797	$	808
Operating lease current liabilities	56		45
Accrued and other current liabilities	5		1
Non-current operating lease liabilities	778		798
Finance leases:
Property, plant and equipment, net	$	1	$	1
Lease right-of-use assets, net	29		11

Current maturities of long-term debt	8		2
Long-term debt, less current maturities	19		9
Other non-current liabilities	—		1

Lease, Cost [Table Text Block]

The components of lease expense for the years ended December 31, 2023 and 2022 were as follows:


		Year Ended December 31,
	Income Statement Location	2023		2022
Operating lease costs:
Operating lease cost	Cost of goods sold	$	1	$	3
Operating lease cost	Operating expenses	69		63
Operating lease cost	Selling, general and administrative	18		22
Total operating lease costs		88		88
Finance lease costs:
Amortization of lease assets	Depreciation, depletion and amortization	—		—
Interest on lease liabilities	Interest expense, net of capitalized interest	—		—
Total finance lease costs		—		—
Short-term lease cost	Operating expenses	38		33
Variable lease cost	Operating expenses	16		13
Lease costs, gross		142		134
Less: Sublease income	Other revenue	42		40
Lease costs, net		$	100	$	94

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

The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2023 and 2022 were as follows:


	December 31,
	2023		2022
Weighted-average remaining lease term (years):
Operating leases	21		21
Finance leases	12		27
Weighted-average discount rate (%):
Operating leases	6	%	5	%
Finance leases	5	%	4	%

Maturities of lease liabilities as of December 31, 2023 are as follows:


	Operating leases		Finance leases		Total
2024	$	96	$	7	$	103
2025	90		8		98
2026	81		4		85
2027	71		2		73
2028	70		1		71
Thereafter	979		12		991
Total lease payments	1,387		34		1,421
Less: present value discount	553		7		560
Present value of lease liabilities	$	834	$	27	$	861

Schedule of additional lease information [Table Text Block]

Cash flows and non-cash activity related to leases for the years ended December 31, 2023 and 2022 were as follows:


	Year Ended December 31,
	2023		2022


Operating cash flows from operating leases	$	(139)	$	(133)



Lease assets obtained in exchange for new finance lease liabilities	18		1
Lease assets obtained in exchange for new operating lease liabilities	5		41

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

Sunoco LP’s future minimum operating lease payments receivable as of December 31, 2023 are as follows:


	Lease Payments
2024	$	108
2025	99
2026	82
2027	63
2028	38
Thereafter	17
Total undiscounted cash flows	$	407

Lease Accounting - Components of Leases on BS (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Operating lease current liabilities	$ 56	$ 45
Accrued and other current liabilities	3,521	3,329
Non-current operating lease liabilities	778	798
Property, plant and equipment, net	85,351	80,311
Current maturities of long-term debt	1,008	2
Long-term debt, less current maturities	51,380	48,260
Other non-current liabilities	1,611	1,341
Operating Leases [Member]
Lessee, Lease, Description [Line Items]
Lease right-of-use assets, net	797	808
Operating lease current liabilities	56	45
Accrued and other current liabilities	5	1
Non-current operating lease liabilities	778	798
Finance Leases [Member]
Lessee, Lease, Description [Line Items]
Property, plant and equipment, net	1	1
Lease right-of-use assets, net	29	11
Current maturities of long-term debt	8	2
Long-term debt, less current maturities	19	9
Other non-current liabilities	$ 0	$ 1

ET Equity Incentive Plans (Details) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Awards granted	10.7
Awards granted	$ 13.78
Unvested awards	39.1	37.7
Unvested awards	$ 10,840,000	$ 9.62
Awards vested	(7.7)
Awards vested	$ 9.22
Awards forfeited	(1.6)
Awards forfeited	$ 9.52

Reportable Segments (Assets Segments) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Assets	$ 113,698	$ 105,643	$ 105,963
Intrastate Transportation and Storage \| Operating Segments
Assets	6,112	6,609	7,322
Interstate Transportation and Storage \| Operating Segments
Assets	17,708	17,979	17,774
Midstream \| Operating Segments
Assets	25,592	21,851	21,960
NGL and Refined Products Transportation and Services \| Operating Segments
Assets	27,214	27,903	28,160
Crude Oil Transportation and Services \| Operating Segments
Assets	25,464	19,200	19,649
Investment in Sunoco LP \| Operating Segments
Assets	6,826	6,830	5,815
Investment in USAC \| Operating Segments
Assets	2,737	2,666	2,768
Corporate and Other [Member]
Assets	$ 2,045	$ 2,605	$ 2,515

Estimates (Schedule of Inventory) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Inventory, Net [Abstract]
Natural gas, NGLs and refined products	$ 1,658	$ 1,802
Crude oil	258	246
Spare parts and other	562	413
Total inventories	$ 2,478	$ 2,461

Retirement Benefits (Net Periodic Benefit Costs Schedule) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 0	$ 0
Interest cost	1	2
Expected return on plan assets	(1)	(2)
Prior service cost amortization	0	0
Defined Benefit Plan, Actuarial Gain (Loss), Immediate Recognition as Component in Net Periodic Benefit (Cost) Credit	0	0
Net periodic benefit cost	0	0
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	1
Interest cost	6	4
Expected return on plan assets	(12)	(11)
Prior service cost amortization	2	19
Defined Benefit Plan, Actuarial Gain (Loss), Immediate Recognition as Component in Net Periodic Benefit (Cost) Credit	(1)	0
Net periodic benefit cost	$ (5)	$ 13

Equity (Change In ETE Common Units) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Issuance of Common Units (2)

^[1]

12,900,000

11,900,000

9,700,000

Outstanding

3,367,525,806

3,094,425,367

3,082,500,000

2,702,400,000

Issuance of restricted Common Units under long-term incentive plans

^[2]

(260,200,000)

(374,600,000)

Common Units repurchased

(4,200,000)

Number of Common Units, end of period

3,367,525,806

3,094,425,367

3,082,500,000

Equity

$ 43,939

$ 40,659

$ 39,345

$ 31,388

Distributions to partners

(4,248)

(3,047)

(1,898)

Crestwood Acquisition

Units issued in connection with the Enable acquisition (1)

^[3]

3,366

Series A Preferred Units [Member]

Equity

948

958

Preferred units conversion (1)

^[4]

$ 943

Units issued for cash

Distributions to partners

(96)

(59)

$ (30)

Units issued in connection with the Enable acquisition (1)

Other, net

Net income

Series A Preferred Units [Member] | Crestwood Acquisition

Units issued in connection with the Enable acquisition (1)

Series B Preferred Units [Member]

Equity

556

Preferred units conversion (1)

^[4]

$ 547

Units issued for cash

Distributions to partners

(36)

$ (18)

Units issued in connection with the Enable acquisition (1)

Other, net

Net income

Series B Preferred Units [Member] | Crestwood Acquisition

Units issued in connection with the Enable acquisition (1)

Series C Preferred Units [Member]

Equity

438

440

Preferred units conversion (1)

^[4]

$ 440

Units issued for cash

Distributions to partners

(40)

(33)

$ (25)

Units issued in connection with the Enable acquisition (1)

Other, net

Net income

Series C Preferred Units [Member] | Crestwood Acquisition

Units issued in connection with the Enable acquisition (1)

Series D Preferred Units [Member]

Equity

435

434

Preferred units conversion (1)

^[4]

$ 434

Units issued for cash

Distributions to partners

(36)

(34)

$ (25)

Units issued in connection with the Enable acquisition (1)

Other, net

Net income

Series D Preferred Units [Member] | Crestwood Acquisition

Units issued in connection with the Enable acquisition (1)

Series E Preferred Units [Member]

Equity

786

Preferred units conversion (1)

^[4]

$ 786

Units issued for cash

Distributions to partners

(61)

$ (45)

Units issued in connection with the Enable acquisition (1)

Other, net

Net income

Series E Preferred Units [Member] | Crestwood Acquisition

Units issued in connection with the Enable acquisition (1)

Series F Preferred Units [Member]

Equity

496

Preferred units conversion (1)

^[4]

$ 504

Units issued for cash

Distributions to partners

(34)

$ (34)

Units issued in connection with the Enable acquisition (1)

Other, net

Net income

Series F Preferred Units [Member] | Crestwood Acquisition

Units issued in connection with the Enable acquisition (1)

Series G Preferred Units [Member]

Equity

1,488

Preferred units conversion (1)

^[4]

$ 1,114

Units issued for cash

Distributions to partners

(106)

$ (79)

Units issued in connection with the Enable acquisition (1)

392

Other, net

Net income

106

Series G Preferred Units [Member] | Crestwood Acquisition

Units issued in connection with the Enable acquisition (1)

Series H Preferred Units

Equity

893

Preferred units conversion (1)

^[4]

$ 0

Units issued for cash

889,000,000

Distributions to partners

(59)

$ (24)

Units issued in connection with the Enable acquisition (1)

Other, net

(3)

Net income

Series H Preferred Units | Crestwood Acquisition

Units issued in connection with the Enable acquisition (1)

Preferred Units [Member]

Equity

6,459

6,051

Preferred units conversion (1)

^[4]

$ 4,768

Units issued for cash

889,000,000

Distributions to partners

(468)

(422)

$ (280)

Units issued in connection with the Enable acquisition (1)

392

Other, net

(3)

Net income

463

422

285

Preferred Units [Member] | Crestwood Acquisition

Units issued in connection with the Enable acquisition (1)

413

Series I Preferred Units

Equity

419

$ 0

Preferred units conversion (1)

^[4]

$ 0

Units issued for cash

Distributions to partners

$ 0

Units issued in connection with the Enable acquisition (1)

Other, net

Net income

$ 0

Series I Preferred Units | Crestwood Acquisition

Units issued in connection with the Enable acquisition (1)

$ 413

[1]	Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.
[2]	Common units issued related to our acquisitions of Crestwood and Lotus Midstream in 2023 and of Enable in 2021.
[3]	See Note 3 for additional information.
[4]	In connection with the Rollup Mergers on April 1, 2021, as discussed in Note 1, all of ETO’s previously outstanding preferred units were converted to Energy Transfer Preferred Units with identical distribution and redemption rights.

Operations And Organization	12 Months Ended
Operations And Organization	Dec. 31, 2023
Operations And Organization [Abstract]
Operations And Organization	OPERATIONS AND BASIS OF PRESENTATION: The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “Energy Transfer”). On April 1, 2021, Energy Transfer, ETO and certain of ETO’s subsidiaries consummated several internal reorganization transactions (the “Rollup Mergers”). In connection with the Rollup Mergers, ETO merged with and into Energy Transfer, with Energy Transfer surviving. The impacts of the Rollup Mergers also included the following: •All of ETO’s long-term debt was assumed by Energy Transfer. •Each issued and outstanding ETO preferred unit was converted into the right to receive one newly created Energy Transfer preferred unit. A description of the Energy Transfer Preferred Units is included in Note 8. •Each of ETO’s issued and outstanding Class K, Class L, Class M and Class N units were converted into an aggregate 675,625,000 newly created Class B Units representing limited partner interests in Energy Transfer. All of the Class B Units are held by ETP Holdco, a wholly owned subsidiary of Energy Transfer. 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, acquisition and marketing activities, as well as NGL storage, fractionation and LNG regasification. The Partnership owns a controlling interest in Sunoco LP which is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites. As of December 31, 2023, 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, 2023, 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 majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. The consolidated financial statements of Energy Transfer presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC.

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Useful Lives) (Details) (Details)	Dec. 31, 2023
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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

12 Months Ended

Dec. 31, 2023

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 (“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 District Court ordered that the 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. Energy Transfer and Rover intend to vigorously defend this claim. On November 13, 2023, the FERC appealed the 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 District Court proceedings remain stayed pending resolution of the case pending before the United States Supreme Court. A decision on that Supreme Court case is expected by June 2024.

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 NGA, 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 NGA 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 NGA. The NGA 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 has timely 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 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which has been 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 December 1, 2022, Sea Robin filed a rate case pursuant to Section 4 of the NGA. By order dated June 29, 2023, a revised procedural schedule was adopted in this proceeding setting the commencement of the hearing for January 9, 2024, with an initial decision anticipated by May 21, 2024. Subsequently, by Order of the Acting Chief Administrative Law Judge, deadlines in the procedural schedule were extended, including revised hearing commencement and initial decisions deadlines to March 26, 2024 and August 8, 2024, respectively. On November 29, 2023, the parties reached a settlement in principle and the settlement was filed with the FERC on December 29, 2023.

In May 2021, the FERC commenced an audit of SPLP for the period from January 1, 2018 to present to evaluate SPLP’s compliance with its FERC oil tariffs, the accounting requirements of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s Form No. 6 reporting requirements. An audit report was received in September 2023 noting no issues that would have a material impact on the Partnership's financial position or results of operations.

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,
	2023		2022		2021
ROW expense	$	68	$	64	$	48

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, 2023 and 2022, accruals of approximately $285 million and $200 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 $200 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 to the Draft EIS were due on December 13, 2023. The USACE anticipates that a Final EIS and Record of Decision would be issued in 2024. 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, which consists of both Dakota Access and the Energy Transfer Crude Oil 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.

Louisiana Dispute with New Generation Gas Gathering LLC

On August 31, 2023, Energy Partners, LP and ETC Texas Pipeline, LTD—corrected 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 causes of action against of all the entities asserting the claim as well as Energy Transfer LP. 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 and monopolies/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 tentatively set a trial date for September 9, 2024. The parties have begun written discovery. The Court’s schedule is subject to dispute among the parties and has not yet been resolved by the Court.

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 same.

Energy Transfer cannot predict the ultimate outcome of this litigation but intends to vigorously defend themselves.

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, 2023, 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 Corporation and Sunoco Partners Marketing & Terminals L.P., now known as Energy Transfer Marketing & Terminals L.P. ETP Holdco Corporation 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.

Litigation Filed By or Against Williams

In April and May 2016, The Williams Companies, Inc. (“Williams”) filed two lawsuits (the “Williams Litigation”) against Energy Transfer, LE GP, LLC, and, in one of the lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC (collectively, “Energy Transfer Defendants”) in the Delaware Court of Chancery (“the Court”), alleging that the Energy Transfer Defendants breached their obligations under the Energy Transfer-Williams merger agreement (the “Merger Agreement”). In general, Williams alleges that the Energy Transfer Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) issuing the Partnership’s Series A convertible preferred units (the “Issuance”) and (c) making allegedly untrue representations and

warranties in the Merger Agreement. Williams asked the Court to compel the Energy Transfer Defendants to close the merger or take various other affirmative actions.

After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of the Energy Transfer Defendants and issued a declaratory judgment that Energy Transfer could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court did not reach a decision regarding Williams’ claims related to the Issuance or certain of the alleged untrue representations and warranties. On March 23, 2017, the Delaware Supreme Court affirmed this ruling on the June 2016 trial. In September 2016, the parties filed amended pleadings. Williams filed an amended complaint seeking a $410 million termination fee (the “Termination Fee”) based on the alleged breaches of the Merger Agreement listed above. The Energy Transfer Defendants filed amended counterclaims and affirmative defenses, asserting that Williams materially breached the Merger Agreement by, among other things, (a) modifying and qualifying its board recommendation in a manner adverse to the merger, (b) failing to use its reasonable best efforts to consummate the merger, (c) failing to provide material information to Energy Transfer for inclusion in the Form S-4 related to the merger, (d) failing to facilitate the financing of the merger and (e) breaching the Merger Agreement’s forum-selection clause. The Energy Transfer Defendants sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct.

On September 29, 2016, Williams filed a motion to dismiss the Energy Transfer Defendants’ amended counterclaims and to strike certain of the Energy Transfer Defendants’ affirmative defenses. On December 1, 2017, the Court issued a Memorandum Opinion granting in part and denying in part Williams’ motion to dismiss. The Court dismissed, among other things, the Energy Transfer Defendants’ claim for a $1.48 billion termination fee.

Trial was held on all remaining claims on May 10-17, 2021, and on December 29, 2021, the Court ruled in favor of Williams and awarded it the Termination Fee plus certain fees and expenses, holding that the Issuance breached the Merger Agreement and that Williams had not materially breached the Merger Agreement, though the Court awarded sanctions against Williams due to its CEO’s intentional spoliation of evidence. The Court subsequently awarded Williams approximately $190 million in attorneys’ fees, expenses and pre-judgment interest.

On September 21, 2022, the Court entered a final judgment against the Energy Transfer Defendants in the amount of approximately $601 million plus post-judgment interest at a rate of 3.5% per year, compounded quarterly. The Energy Transfer Defendants filed a notice of appeal on October 21, 2022 and filed their opening brief in support of their appeal on December 30, 2022. Williams filed their answering brief on January 20, 2023, and the Energy Transfer Defendants filed their reply brief on February 6, 2023. The Delaware Supreme Court heard oral argument on July 12, 2023.

On October 10, 2023, the Delaware Supreme Court affirmed. On October 25, 2023, Energy Transfer Defendants filed a motion for reargument. On November 17, 2023, the Delaware Supreme Court denied the motion.

The mandate issued upon the disposition of that motion; at which time the previously-stayed judgment became effective, plus additional post-judgment interest.

The Energy Transfer Defendants paid the judgment (in the amount of approximately $627 million) on November 28, 2023, concluding this matter.

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 and Energy Transfer’s and Rover’s responsive brief is currently due February 20, 2024. 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 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 well as Michael J. Hennigan and Joseph McGinn. The amended complaint asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the construction of pipelines in Pennsylvania. On August 14, 2020, the defendants filed a motion to dismiss ACERS’ amended complaint. On April 6, 2021, the court granted in part and denied in part the defendants’ motion to dismiss. The court held that ACERS could proceed with its claims regarding certain statements put at issue by the amended complaint while also dismissing claims based on other statements. The court also dismissed without prejudice the claims against defendants McReynolds, McGinn and Hennigan. Discovery is ongoing. On August 23, 2022, the court granted in part and denied in part ACERS’ motion for class certification. The court certified a class consisting of those who purchased or otherwise acquired common units of Energy Transfer between February 25, 2017 and November 11, 2019.

On June 3, 2022, another purported unitholder of Energy Transfer, Mike Vega, filed suit, purportedly on behalf of a class, against Energy Transfer and Messrs. Warren, Long, McCrea and Whitehurst. See Vega v. Energy Transfer LP et al., Case No. 1:22-cv-4614 (S.D.N.Y.). The action asserts claims for violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder related primarily to statements made in connection with the construction of Rover. On August 10, 2022, the court appointed the New Mexico State Investment Council and Public Employees Retirement Association of New Mexico (the “New Mexico Funds”) as lead plaintiffs. New Mexico Funds filed an amended complaint on September 30, 2022 and added as additional defendants Energy Transfer directors John W. McReynolds and Matthew S. Ramsey. On November 7, 2022, the court granted the defendants’ motion to transfer and transferred this action to the United States District Court for the Northern District of Texas. On January 27, 2023, the defendants filed their motion to dismiss the New Mexico Funds’ amended complaint.

The defendants cannot predict the outcome of these lawsuits or any lawsuits that might be filed subsequent to the date of this filing, nor can the defendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the defendants believe that the claims are without merit and intend to vigorously contest them.

Cline Class Action

On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco, Inc. (R&M), LLC (now known as Energy Transfer R&M) and Energy Transfer Marketing & Terminals L.P. (collectively, “ETMT”) that alleged ETMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the District Court certified a class to include all persons

who received untimely payments from Oklahoma wells on or after July 7, 2012, and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.

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

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

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

ETMT cannot predict the outcome of the case, nor can ETMT predict the amount of time and expense that will be required to resolve the appeal. ETMT has been vigorous and diligent in its appeals relating to the finality issues underlying the Order and appealed the denial of the Motion to Modify to the 10th Circuit in an attempt to get a decision on finality. The appeal was fully briefed, and oral argument was held on March 21, 2023. On August 3, 2023, the 10th Circuit ruled in favor of ETMT and found that the district court’s plan of allocation (which was part of the final judgment) did not satisfy all finality requirements. The Court held that the district court abused its discretion in denying ETMT’s Rule 60(b)(6) Motion to Modify and reversed and remanded for further proceedings. The case was sent back to the trial court so that the district court could fix the finality requirements with the judgment. Further, ETMT sought and recovered a return of funds deposited with the Plan Administrator; Class Counsel did not oppose this motion.

At a status hearing on September 28, 2023, Class Counsel indicated that it would seek additional interest up until the date that the final judgment is entered. The District Court asked for briefing on the issue of additional interest and held a hearing on October 17, 2023 to address this issue further and enter a ruling as to whether additional interest should be added to the judgment total. During the hearing, the District Court ruled that additional interest should be awarded at the 12% statutory rate from the date of the prior improper judgment up until October 17, 2023. However, the Judge tolled the running of interest for the time period during which the Plan Administrator was in possession of ETMT’s funds (between November 2, 2022 and October 10, 2023). Based on this ruling, the Class calculated that approximately $23 million in additional interest should be added to the final judgment. On October 19, 2023, the District Court entered the new final judgment with a corrected Plan of Allocation. Both parties agree that this newly entered judgment fixes the finality concerns and will allow an appeal to the 10th Circuit on the merits. With the inclusion of additional interest, the total amount awarded to the Plaintiffs is approximately $104 million in actual damages and $75 million in punitive damages. ETMT intends on appealing the entirety of the judgment and filed its Notice of Appeal to the Tenth Circuit on December 15, 2023.

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

On April 8, 2022, Energy Transfer and ETC Texas Pipeline, Ltd. (“ETC,” and together with Energy Transfer, “Plaintiffs”) filed suit against Culberson Midstream LLC (“Culberson”), Culberson Midstream Equity, LLC (“Culberson Equity”), and Moontower Resources Gathering, LLC (“Moontower”). On October 1, 2018, ETC and Culberson entered into a Gas

Gathering and Processing Agreement (the “Bypass GGPA”) under which Culberson was to gather gas from its dedicated acreage and deliver all committed gas exclusively to ETC. In connection with the Bypass GGPA, on October 18, 2018, Energy Transfer and Culberson Equity also entered into an Option Agreement. Under the Option Agreement, Culberson Equity and Moontower had the right (but not the obligation) to require Energy Transfer to purchase their respective interests in Culberson by way of a put option. Notably, the Option Agreement is only enforceable so long as the parties comply with the Bypass GGPA. In late March 2022, Culberson Equity and Moontower submitted a put notice to Energy Transfer seeking to require Energy Transfer to purchase their respective interests in Culberson for approximately $93 million. On April 8, 2022, Plaintiffs filed suit against Culberson, Culberson Equity and Moontower asserting claims for declaratory judgment and breach of contract, contending that they materially breached the Bypass GGPA by sending some committed gas to third parties and also by failing to send any gas to Plaintiffs since March 2020, and thus that Culberson Equity’s and Moontower’s put notice is void. Culberson, Culberson Equity, and Moontower have answered the lawsuit. Additionally, Culberson filed a counterclaim against ETC for breach of the Bypass GGPA, seeking the recovery of damages and attorneys’ fees. Culberson Equity and Moontower also filed a counterclaim against Energy Transfer for (1) breach of the Option Agreement, and (2) a declaratory judgment concerning Energy Transfer’s alleged obligation to purchase the Culberson interests. The lawsuit is pending in the 193rd Judicial District Court (“the Court”) in Dallas County, Texas. On April 27, 2022, Culberson filed an application for a temporary restraining order, temporary injunction, and permanent injunction, and Culberson Equity and Moontower joined in that request. The Court held a hearing on the application on April 28 and denied the injunction. In early May, Culberson filed a motion to enforce the appraisal process and confirm the validity of their put price calculation, to which Plaintiffs objected. On July 11, 2022, the Court held a hearing on the motion, and on July 19, 2022, the Court ordered the parties to engage in an appraisal process regarding the put price. An independent appraiser was appointed and issued his decision on October 15, 2022, concluding that the put price totals $93 million. Plaintiffs have consistently reiterated their objection to the appraisal process and conclusion.

On October 6, 2022, Culberson, Culberson Equity and Moontower filed a motion for summary judgment, but the Court postponed considering it until after further document discovery and depositions. On December 7, 2022, Plaintiffs amended their petition to add Moontower Resources Operating, LLC and Moontower Resources WI, LLC as Defendants, and to assert a claim against all Defendants for fraudulent inducement.

Defendants refiled updated motions for summary judgment on May 5, 2023, seeking summary judgment on: (1) Plaintiffs’ breach of contract and declaratory judgment claims on a no-evidence basis; (2) Plaintiffs’ fraud and alter ego claims on a no-evidence basis; and (3) Plaintiffs’ fraud claim on a traditional basis. Plaintiffs responded on June 6, 2023. Defendants submitted their replies in support of summary judgment on June 12, 2023.

On June 5, 2023, counsel for Defendants informed the Court via a letter that Defendants were continuing the submission date of the no-evidence motion regarding Plaintiffs’ breach of contract and declaratory judgment claims, noting that such submission would be rescheduled along with a traditional summary judgment motion regarding the same subject matter. To that end, on July 17, 2023, Defendant Culberson Midstream, LLC filed a Traditional Motion for Summary Judgment on Plaintiffs’ Breach of Contract and Declaratory Judgment Claims, while Defendants Culberson Midstream Equity, LLC and Moontower Resources Gathering filed a Motion for Partial Summary Judgment Regarding the Breach of the Option Agreement. Further, on July 25, 2023, Defendants filed a Traditional and No-Evidence Motion for Summary Judgment Regarding Damages and Recission. On July 28, 2023, in turn, Plaintiff ETC Texas Pipeline, Ltd. filed a Traditional Motion for Partial Summary Judgment on Breach of Contract and Declaratory Judgment.

On September 20, 2023, the Court held oral argument on the various Motions for Summary Judgment. Following oral argument, on September 26, 2023, the Court ruled on each of the Motions. The Court denied Defendants’ Traditional Motion for Partial Summary Judgment Regarding Fraud, Defendants’ No Evidence Motion for Summary Judgment Regarding Plaintiffs’ Fraud and Alter Ego Claims, Defendants’ Traditional and No Evidence Motion for Partial Summary Judgment Regarding Damages and Rescission, and Plaintiff ETC Texas Pipeline, Ltd.’s Traditional Motion for Partial Summary Judgment on Breach of Contract and Declaratory Judgment. The Court granted Culberson Midstream, LLC’s Traditional Motion for Partial Summary Judgment Seeking Dismissal of Plaintiffs’ Breach of Contract and Declaratory Judgment Claims and Culberson Midstream Equity, LLC and Moontower Resources Gathering, LLC’s Motion for Partial Summary Judgment Regarding Breach of the Option Agreement. Defendants have filed a motion seeking permission from the appellate court to allow an interlocutory appeal of the order denying their Traditional Motion for Partial Summary Judgment Regarding Fraud. That motion remains pending before the appellate court.

Discovery has closed in this matter. Trial on Plaintiff Energy Transfer LP’s fraud claim is currently set for June 18, 2024. Plaintiffs cannot predict the ultimate outcome of this litigation or the amount of time and expense that will be required to resolve it.

Massachusetts Attorney General v. New England Gas Company

On July 7, 2011, the Massachusetts Attorney General (the “MA AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“DPU”) against New England Gas Company (“NEG”) with respect to certain environmental cost recoveries. NEG was an operating division of Southern Union Company (“SUG”), and the NEG assets were acquired in connection with the merger transaction with Energy Transfer in March 2012. Subsequent to the merger, in 2013, SUG sold the NEG assets to Liberty Utilities (“Liberty,” and together with NEG and SUG, “Respondents”) and retained certain potential liabilities, including the environmental cost recoveries with respect to the pending complaint before the DPU. Specifically, the MA AG seeks a refund to NEG’s ratepayers for approximately $18 million in legal fees associated with SUG environmental response activities. The MA AG requests that the DPU initiate an investigation into NEG’s collection and reconciliation of recoverable environmental costs, namely: (1) the legal fees charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005; (2) the legal fees charged by the Bishop, London & Dodds firm and passed through the recovery mechanisms since 2005; and (3) the legal fees passed through the recovery mechanism that the MA AG contends only qualify for a lesser (i.e., 50%) level of recovery. Respondents maintain that, by tariff, these costs are recoverable through rates charged to NEG customers pursuant to the environmental remediation adjustment clause program. After the Respondents answered the complaint and filed a motion to dismiss in 2011, the Hearing Officer deferred decision on the motion to dismiss and issued a stay of discovery pending resolution of a discovery dispute, which it later lifted on June 24, 2013, permitting the case to resume. However, the MA AG failed to take any further steps to prosecute its claims for nearly seven years. The case remained largely dormant until February 2022, when the Hearing Officer denied the motion to dismiss. After receiving input from the parties, the Hearing Officer entered a procedural schedule on March 16, 2022 (which was amended slightly on August 22, 2022). The parties engaged in discovery and the preparation of pre-filed testimony. Respondents submitted their pre-filed testimony on July 11, 2022. The MA AG served three sets of discovery requests on Respondents on September 9, September 12, and September 20, respectively, to which Respondents timely responded. On October 5, 2022, the MA AG requested that the DPU issue a ruling on whether the information that Respondents redacted in their attorneys’ fees invoices is protected by the attorney-client privilege. On the same day, the MA AG also filed a Motion to Stay the Procedural Schedule pending a ruling on the privilege issue. On October 6, 2022, without even affording Respondents the opportunity to respond, the DPU granted the MA AG’s request to stay the procedural schedule. Accordingly, all previous deadlines (including the MA AG’s October 7, 2022, deadline to submit direct pre-filed testimony) are presently stayed. On October 18, 2023, the DPU issued an Order on Attorney General’s Motion to Compel, ruling on issues originally raised in a motion to compel that the MA AG filed in 2013. The October 18, 2023 Order directs NEG to review its redactions again and, to the extent any invoices are completely redacted or heavily redacted, to provide more lightly redacted versions within 30 days. The October 18, 2023 Order also states that the MDPU will set a new procedural schedule in this matter sometime after NEG complies with the directives in the order, which the Company has completed as of January 17, 2024.

Crestwood Midstream Partners, LP – Linde Litigation

On December 23, 2019, Linde Engineering North America Inc. (“Linde”) filed a lawsuit in the District Court of Harris County, Texas alleging that Arrow Field Services, LLC, our consolidated subsidiary, and Crestwood Midstream Partners, LP (collectively, “Crestwood”) breached a contract entered into in March 2018 under which Linde was to provide engineering, procurement and construction services to Crestwood related to the completion of the construction of the Bear Den II cryogenic processing plant.

Trial was held in June 2022, and a final judgment was entered on October 24, 2022. The final judgment includes an award of damages of approximately $20.7 million, a pre-judgment interest award of approximately $17.7 million and attorney fees and other costs of approximately $4.7 million. Crestwood has insurance coverage related to certain pre-judgment interest awards but has not recorded a receivable related to any potential insurance recovery on June 30, 2023. On January 9, 2023, Crestwood paid approximately $21.2 million to the Court Registry under protest to mitigate the impact of post-judgment interest. Crestwood filed a Notice of Appeal on January 13, 2023, and filed its Appellate Brief on September 29, 2023. Linde’s response was filed on February 8, 2024. Crestwood anticipates that oral argument will be held in late 2024. Crestwood is unable to predict the ultimate outcome on the appeal related to this matter.

Environmental Matters

Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and

operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on our results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

•Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties.

•Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

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

•The Partnership is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2023, the Partnership had been named as a PRP at approximately 32 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. The Partnership is usually one of a number of companies identified as a PRP at a site. The Partnership has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon the Partnership’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

The following table reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.


	December 31,
	2023		2022
Current	$	42	$	54
Non-current	235		228
Total environmental liabilities	$	277	$	282

We have established a wholly owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined

fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the years ended December 31, 2023 and 2022, the Partnership recorded $29 million and $30 million, respectively, of expenditures related to environmental cleanup programs.

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

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

Consolidated Statements Of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
REVENUES:
Total revenues	$ 78,586	$ 89,876	$ 67,417
COSTS AND EXPENSES:
Cost of products sold	60,541	72,232	50,395
Operating expenses	4,368	4,338	3,574
Depreciation, depletion and amortization	4,385	4,164	3,817
Selling, general and administrative	985	1,018	818
Impairment losses and other	12	386	21
Total costs and expenses	70,291	82,138	58,625
OPERATING INCOME	8,295	7,738	8,792
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(2,578)	(2,306)	(2,267)
Equity in earnings of unconsolidated affiliates	383	257	246
Gains (losses) on extinguishments of debt	2	0	(38)
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments	36	293	61
Gain (Loss) Related to Litigation Settlement	(627)	0	0
Other, net	86	90	77
Income before income tax expense	5,597	6,072	6,871
Income tax expense	303	204	184
NET INCOME	5,294	5,868	6,687
Less: Net income attributable to noncontrolling interests	1,299	1,061	1,167
Less: Net income attributable to redeemable noncontrolling interests	60	51	50
NET INCOME ATTRIBUTABLE TO PARTNERS	3,935	4,756	5,470
General Partner’s interest in net income	3	4	6
Preferred Unitholders’ interest in net income	463	422	285
Limited Partners’ interest in net income	$ 3,469	$ 4,330	$ 5,179
NET INCOME PER COMMON UNIT:
Basic	$ 1.10	$ 1.40	$ 1.89
Diluted	$ 1.09	$ 1.40	$ 1.89
Refined product sales
REVENUES:
REVENUES:	$ 23,389	$ 26,020	$ 17,766
Crude sales
REVENUES:
REVENUES:	23,492	23,473	15,299
Natural gas sales
REVENUES:
REVENUES:	3,259	8,535	9,159
Gathering, transportation and other fees
REVENUES:
REVENUES:	11,428	10,907	9,229
NGL sales
REVENUES:
REVENUES:	15,957	20,114	15,243
Other
REVENUES:
REVENUES:	$ 1,061	$ 827	$ 721

Equity (Tables)

12 Months Ended

Dec. 31, 2023

Change In ETE Common Units

The change in Energy Transfer Common Units during the years ended December 31, 2023, 2022 and 2021 was as follows:


	Years Ended December 31,
	2023	2022	2021
Number of Common Units, beginning of period	3,094.4	3,082.5	2,702.4

Common Units issued in mergers and acquisitions (1)	260.2	—	374.6
Common Units repurchased	—	—	(4.2)
Issuance of Common Units (2)	12.9	11.9	9.7
Number of Common Units, end of period	3,367.5	3,094.4	3,082.5

(1)Common units issued related to our acquisitions of Crestwood and Lotus Midstream in 2023 and of Enable in 2021.

(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,
	2023		2022
Available-for-sale securities	$	13	$	9
Foreign currency translation adjustment	(5)		1

Actuarial gain (loss) related to pensions and other postretirement benefits	6		(7)
Investments in unconsolidated affiliates, net	14		13
Total AOCI, net of tax	$	28	$	16

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


	December 31,
	2023		2022
Available-for-sale securities	$	(3)	$	1
Foreign currency translation adjustment	6		6
Actuarial loss relating to pension and other postretirement benefits	—		1
Total	$	3	$	8

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

(1)In connection with the Rollup Mergers on April 1, 2021, as discussed in Note 1, all of ETO’s previously outstanding preferred units were converted to Energy Transfer Preferred Units with identical distribution and redemption rights.

Variable Rate Terms [Member]

Schedule of Preferred Units

Distributions on the Energy Transfer Series B Preferred Units and Series E Preferred Units are scheduled to begin accruing at a floating rate as follows:


	Beginning of floating rate period	Applicable Spread		Tenor spread adjustment		Floating rate
Series B Preferred Units	February 15, 2028	4.155	%	0.26161	%	Three-month SOFR
Series E Preferred Units	May 15, 2024	5.161	%	0.26161	%	Three-month SOFR

As discussed above, the Partnership expects to redeem the Series E Preferred Units at the beginning of the floating rate period on May 15, 2024.

Sunoco LP [Member]

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

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

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2020

February 8, 2021

February 19, 2021

0.8255

March 31, 2021

May 11, 2021

May 19, 2021

0.8255

June 30, 2021

August 6, 2021

August 19, 2021

0.8255

September 30, 2021

November 5, 2021

November 19, 2021

0.8255

December 31, 2021

February 8, 2022

February 18, 2022

0.8255

March 31, 2022

May 9, 2022

May 19, 2022

0.8255

June 30, 2022

August 8, 2022

August 19, 2022

0.8255

September 30, 2022

November 4, 2022

November 18, 2022

0.8255

December 31, 2022

February 7, 2023

February 21, 2023

0.8255

March 31, 2023

May 8, 2023

May 22, 2023

0.8420

June 30, 2023

August 14, 2023

August 21, 2023

0.8420

September 30, 2023

October 30, 2023

November 20, 2023

0.8420

December 31, 2023

February 7, 2024

February 20, 2024

0.8420

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, 2023, USAC had approximately 101.0 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.

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

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2020

January 25, 2021

February 5, 2021

0.5250

March 31, 2021

April 26, 2021

May 7, 2021

0.5250

June 30, 2021

July 26, 2021

August 6, 2021

0.5250

September 30, 2021

October 25, 2021

November 5, 2021

0.5250

December 31, 2021

January 24, 2022

February 4, 2022

0.5250

March 31, 2022

April 25, 2022

May 6, 2022

0.5250

June 30, 2022

July 25, 2022

August 5, 2022

0.5250

September 30, 2022

October 24, 2022

November 4, 2022

0.5250

December 31, 2022

January 23, 2023

February 3, 2023

0.5250

March 31, 2023

April 24, 2023

May 5, 2023

0.5250

June 30, 2023

July 24, 2023

August 4, 2023

0.5250

September 30, 2023

October 23, 2023

November 3, 2023

0.5250

December 31, 2023

January 22, 2024

February 2, 2024

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, 2020

February 8, 2021

February 19, 2021

0.1525

March 31, 2021

May 11, 2021

May 19, 2021

0.1525

June 30, 2021

August 6, 2021

August 19, 2021

0.1525

September 30, 2021

November 5, 2021

November 19, 2021

0.1525

December 31, 2021

February 8, 2022

February 18, 2022

0.1750

March 31, 2022

May 9, 2022

May 19, 2022

0.2000

June 30, 2022

August 8, 2022

August 19, 2022

0.2300

September 30, 2022

November 4, 2022

November 21, 2022

0.2650

December 31, 2022

February 7, 2023

February 21, 2023

0.3050

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

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 (1)	Series B (1)	Series C	Series D	Series E	Series F (1)	Series G (1)	Series H (1)		Series I
March 31, 2021	May 3, 2021	May 17, 2021	$—	$—	$0.4609	$0.4766	$0.4750	$33.7500	$35.63	$—		$—
June 30, 2021	August 2, 2021	August 16, 2021	31.25	33.125	0.4609	0.4766	0.4750	—	—	—		—
September 30, 2021	November 1, 2021	November 15, 2021	—	—	0.4609	0.4766	0.4750	33.7500	35.63	27.08	*	—
December 31, 2021	February 1, 2022	February 15, 2022	31.25	33.125	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

* Represents prorated initial distribution.

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

Redeemable Noncontrolling Interest	12 Months Ended
Redeemable Noncontrolling Interest	Dec. 31, 2023
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, 2023 and 2022, redeemable noncontrolling interests included $476 million and $477 million, respectively, related to the USAC Preferred Units, described below, and $22 million and $16 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. As of December 31, 2023, redeemable noncontrolling interests also included $280 million related to the Niobrara Preferred Units described below. USAC Series A Preferred Units As of December 31, 2023 and 2022, USAC had 500,000 preferred units issued and outstanding. The USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the USAC Preferred Units are convertible into USAC common units at the election of the holders. The USAC Preferred Units are convertible, at the option of the holder, into a maximum of 24,985,633 USAC common units in the aggregate. USAC has the option to redeem all or any portion of the USAC Preferred Units then outstanding, subject to certain minimum redemption threshold amounts, for a redemption price set forth in USAC’s partnership agreement. In addition, beginning April 2028, the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and USAC may elect to pay up to 50% of such redemption amount in USAC common units. 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. 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.

Income Taxes Income Taxes (Notes)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES:

As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries are summarized as follows:


	Years Ended December 31,
	2023		2022		2021
Current expense:
Federal	$	56	$	—	$	19
State	44		17		24

Total	100		17		43
Deferred expense (benefit):
Federal	227		239		246
State	(24)		(58)		(106)
Foreign	—		6		1
Total	203		187		141
Total income tax expense	$	303	$	204	$	184

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, 2023, 2022 and 2021 is as follows:


	Years Ended December 31,
	2023		2022		2021

Income tax expense at United States statutory rate	$	1,175	$	1,275	$	1,443
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax	(884)		(1,086)		(1,211)
Noncontrolling interests	—		26		—
State tax, net of federal tax benefit	47		19		85
Statutory rate change	(10)		(42)		(46)
Valuation allowance	(3)		(4)		(63)
Uncertain tax positions	(14)		(3)		(34)
Dividend received deduction	(3)		(3)		(4)


Foreign taxes	—		6		1

Other	(5)		16		13
Income tax expense	$	303	$	204	$	184

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,
	2023		2022
Deferred income tax assets:
Net operating losses and other carryforwards	$	371	$	603


Other	46		60
Total deferred income tax assets	417		663
Valuation allowance	—		(19)
Net deferred income tax assets	417		644

Deferred income tax liabilities:
Property, plant and equipment	(232)		(218)

Investments in affiliates	(4,003)		(4,010)
Trademarks	(91)		(89)
Other	(22)		(28)
Total deferred income tax liabilities	(4,348)		(4,345)
Net deferred income taxes	$	(3,931)	$	(3,701)

As of December 31, 2023, ETP Holdco had a federal net operating loss carryforward of $1.4 billion, 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, 2023, Sunoco Retail LLC, a corporate subsidiary of Sunoco LP, had a state net operating loss carryforward of $75 million, which we expect to fully utilize. Sunoco Retail LLC has no federal net operating loss carryforward.

Our corporate subsidiaries have state net operating loss carryforward benefits of $75 million, net of federal tax, some of which expire between 2024 and 2042, while others are carried forward indefinitely. Our corporate subsidiaries have cumulative excess business interest expense of $136 million available for carryforward indefinitely, of which $23 million is limited under IRC §382.

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


	Years Ended December 31,
	2023		2022		2021
Balance at beginning of year	$	52	$	56	$	90



Reduction attributable to tax positions taken in prior years	(9)		(4)		(34)
Settlements	(3)		—		—

Balance at end of year	$	40	$	52	$	56

As of December 31, 2023, we had $40 million ($38 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 2023, we recognized an interest and penalty benefit of $7 million. At December 31, 2023, we have interest and penalties accrued of $11 million, net of tax.

In November 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact. Nextel subsequently filed a petition for writ of certiorari with the United States Supreme Court, and this was denied on June 11, 2018. Certain Pennsylvania taxpayers have subsequently undertaken litigation in Pennsylvania state courts on issues not addressed by the

Pennsylvania Supreme Court in Nextel, specifically, whether the Due Process and Equal Protection Clauses of the United States Constitution and the Remedies Clause of the Pennsylvania Constitution require a court to grant the taxpayer relief. On December 22, 2021, the Pennsylvania Supreme Court found in General Motors Corporation v. Commonwealth (“GM”) that the taxpayer was entitled to meaningful backwards looking relief under the Due Process Clause, meaning the Commonwealth must equalize the taxpayer’s position with taxpayers who were not affected by the NOL cap in place for the year at issue. The Court therefore held the taxpayer was entitled to a refund by calculating its tax for that year with an uncapped NOL deduction. We believe the Pennsylvania Supreme Court’s ruling in GM will more likely than not be upheld if challenged by the Commonwealth. ETC Sunoco previously recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter. In addition, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, ETC Sunoco previously reserved $34 million ($27 million after federal income tax benefits) against the receivable. Subsequent to the Pennsylvania Supreme Court’s decision in GM, the reserve has been reversed and the entire tax benefit of $34 million ($27 million after federal income tax benefit) has been recognized by the Partnership.

The Partnership’s 2020 U.S. Federal income tax return is currently under examination by the Internal Revenue Service. The IRS is auditing Crestwood’s 2020 U.S. Federal income tax return. In general, Energy Transfer and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2018 and prior tax years.

USAC is currently under examination by the IRS for years 2019 and 2020. Energy Transfer and its other subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480990/946-20-50-13

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(h)(2))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480678/235-10-S99-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org//740/tableOfContent

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-14

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-21

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 270
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482526/740-270-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 17
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-17

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.5.Q1)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479360/740-10-S99-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SAB Topic 11.C)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479360/740-10-S99-2

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482603/740-30-50-2

+ Details

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

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities

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


	Years Ended December 31,
	2023		2022		2021
Accounts receivable	$	(171)	$	(863)	$	(3,356)
Accounts receivable from related companies	(5)		23		38
Inventories	35		(361)		(19)
Other current assets	221		(326)		(216)
Other non-current assets, net	(125)		146		1
Accounts payable	(501)		25		3,834
Accounts payable to related companies	(38)		6		(34)
Accrued and other current liabilities	209		131		238
Other non-current liabilities	(33)		66		117
Derivative assets and liabilities, net	(43)		(349)		(88)
Net change in operating assets and liabilities, net of effects of acquisitions	$	(451)	$	(1,502)	$	515

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,
	2023		2022		2021
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	$	442	$	575	$	464
Units issued in connection with the Enable acquisition (1)	—		—		3,509
Units issued in connection with the Crestwood acquisition (1)	3,366		—		—
Units issued in connection with the Lotus Midstream acquisition (1)	574		—		—
Lease assets obtained in exchange for new lease liabilities	23		42		18
Acquisition of interest in unconsolidated affiliate	—		—		49






SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	2,298	$	2,167	$	2,188
Cash paid for income taxes (net of refunds)	103		54		41

(1)See Note 3 for additional information.

Schedule of Inventory

The Partnership’s inventories consisted of the following:


	December 31,
	2023		2022
Natural gas, NGLs and refined products	$	1,658	$	1,802
Crude oil	258		246
Spare parts and other	562		413
Total inventories	$	2,478	$	2,461

Other Current Assets

Other current assets consisted of the following:


	December 31,
	2023		2022
Deposits paid to vendors	$	205	$	334
Prepaid expenses and other	308		392
Total other current assets	$	513	$	726

Property, Plant and Equipment

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


	December 31,
	2023		2022
Land and improvements	$	1,529	$	1,427
Buildings and improvements (1 to 45 years)	3,848		3,546
Pipelines and equipment (5 to 83 years)	88,195		82,353
Product storage and related facilities (2 to 83 years)	7,978		7,274
Right of way (20 to 83 years)	7,379		6,252
Other (1 to 48 years)	3,688		2,739
Construction work-in-process	2,315		2,405
	114,932		105,996
Less – Accumulated depreciation and depletion	(29,581)		(25,685)
Property, plant and equipment, net	$	85,351	$	80,311

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

We recognized the following amounts for the periods presented:


	Years Ended December 31,
	2023		2022		2021
Depreciation, depletion and amortization expense	$	3,986	$	3,774	$	3,465
Capitalized interest	77		112		135

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,
	2023		2022
Crude pipeline linefill and tank bottoms	$	598	$	489
Regulatory assets	48		55
Pension assets	145		129
Deferred charges	148		140
Restricted funds	121		121
Other	673		624
Total other non-current assets, net	$	1,733	$	1,558

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

Components And Useful Lives Of Intangibles And Other Assets

Components and useful lives of intangible assets were as follows:


	December 31, 2023				December 31, 2022
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	9,098	$	(3,196)	$	7,884	$	(2,807)
Patents (10 years)	48		(48)		48		(48)

Trade names (20 years)	66		(44)		66		(41)
Other (5 to 20 years)	12		(11)		12		(13)
Total amortizable intangible assets	9,224		(3,299)		8,010		(2,909)
Non-amortizable intangible assets:
Trademarks	302		—		302		—
Other	12		—		12		—
Total non-amortizable intangible assets	314		—		314		—
Total intangible assets	$	9,538	$	(3,299)	$	8,324	$	(2,909)

Aggregate Amortization Expense Of Intangibles And Other Assets

Aggregate amortization expense of intangible assets was as follows:


	Years Ended December 31,
	2023		2022		2021
Reported in depreciation, depletion and amortization expense	$	399	$	390	$	352

Estimated Aggregate Amortization Expense

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


Years Ending December 31:
2024	$	434
2025	423
2026	417
2027	400
2028	397

Schedule of Goodwill

Changes in the carrying amount of goodwill were as follows:


	Intrastate Transportation and Storage		Interstate Transportation and Storage		Midstream		NGL and Refined Products Transportation and Services		Crude Oil Transportation and Services		Investment in Sunoco LP		Investment in USAC		All Other		Total
Balance, December 31, 2021	$	—	$	—	$	—	$	693	$	190	$	1,568	$	—	$	82	$	2,533
Acquired	—		—		—		—		—		33		—		—		33



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

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:


	December 31,
	2023		2022
Interest payable	$	637	$	559
Customer advances and deposits	240		222
Accrued capital expenditures	442		575
Accrued wages and benefits	406		376
Taxes payable other than income taxes	646		519


Exchanges payable	163		224
Deferred revenue	312		268
Other	675		586
Total accrued and other current liabilities	$	3,521	$	3,329

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, 2023 and 2022 based on inputs used to derive their fair values:


	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 FERC/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	31		20		11
Total assets	$	647	$	622	$	25
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)


	Fair Value Total		Fair Value Measurements at December 31, 2022
			Level 1		Level 2
Assets:
Interest rate derivatives	$	—	$	—	$	—
Commodity derivatives:

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


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


NGLs – Forwards/Swaps	317		317		—
Refined Products – Futures	20		20		—
Crude - Forwards/Swaps	38		38		—
Total commodity derivatives	688		626		62
Other non-current assets	27		18		9
Total assets	$	715	$	644	$	71
Liabilities:
Interest rate derivatives	$	(23)	$	—	$	(23)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(25)		(25)
Swing Swaps IFERC	(12)		(12)		—
Fixed Swaps/Futures	(4)		(4)		—


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


NGLs – Forwards/Swaps	(358)		(358)		—
Refined Products – Futures	(59)		(59)		—
Crude - Forwards/Swaps	(12)		(12)		—

Total commodity derivatives	(526)		(473)		(53)
Total liabilities	$	(549)	$	(473)	$	(76)

Income Taxes Narrative (Details) - USD ($)	12 Months Ended
Income Taxes Narrative (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Loss Carryforwards [Line Items]
Deferred Tax Liabilities, Gross	$ 4,348,000,000	$ 4,345,000,000
Net operating losses and other carryforwards	371,000,000	603,000,000
Valuation allowance	0	(19,000,000)
State	44,000,000	17,000,000	$ 24,000,000
Deferred Income Tax Expense (Benefit)	203,000,000	$ 187,000,000	$ 141,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	40,000,000
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, After Tax	38,000,000
Unrecognized Tax Benefits, Interest on Income Taxes Expense	7,000,000
Income Tax Examination, Penalties and Interest Accrued	11,000,000
Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset, Interest Carryforward	136,000,000
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	75,000,000
Sunoco Property Company LLC [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	75,000,000
Sunoco Retail LLC
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	0
ETP Holdco
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	1,400,000,000
PENNSYLVANIA
Operating Loss Carryforwards [Line Items]
State	67,000,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	34,000,000
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	$ 23,000,000

Insider Trading Arrangements	12 Months Ended
Insider Trading Arrangements	Dec. 31, 2023
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

Revenue Narrative (Details) - USD ($) $ in Millions	12 Months Ended
Revenue Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Sunoco LP [Member]
Capitalized Contract Cost, Amortization	$ 29	$ 22	$ 21

Estimates (Schedule of Other Non-Current Assets, net) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Crude pipeline linefill and tank bottoms	$ 598	$ 489
Regulatory assets	48	55
Pension assets	145	129
Deferred charges	148	140
Restricted funds	121	121
Other	673	624
Total other non-current assets, net	$ 1,733	$ 1,558

Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2023

Financial Information By Segment

The following tables present financial information by segment:


	Years Ended December 31,
	2023		2022		2021
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	3,222	$	6,954	$	7,307
Intersegment revenues	740		864		1,264
	3,962		7,818		8,571
Interstate transportation and storage:
Revenues from external customers	2,328		2,185		1,802
Intersegment revenues	47		66		39
	2,375		2,251		1,841
Midstream:
Revenues from external customers	2,911		4,114		2,620
Intersegment revenues	7,495		12,987		8,696
	10,406		17,101		11,316
NGL and refined products transportation and services:
Revenues from external customers	18,413		21,414		16,989
Intersegment revenues	3,490		4,243		2,972
	21,903		25,657		19,961
Crude oil transportation and services:
Revenues from external customers	26,534		25,980		17,442
Intersegment revenues	2		2		4
	26,536		25,982		17,446
Investment in Sunoco LP:
Revenues from external customers	23,026		25,677		17,571
Intersegment revenues	42		52		25
	23,068		25,729		17,596
Investment in USAC:
Revenues from external customers	824		689		621
Intersegment revenues	22		16		12
	846		705		633
All other:
Revenues from external customers	1,328		2,863		3,065
Intersegment revenues	470		711		411
	1,798		3,574		3,476
Eliminations	(12,308)		(18,941)		(13,423)
Total revenues	$	78,586	$	89,876	$	67,417


	Years Ended December 31,
	2023		2022		2021
Cost of products sold:
Intrastate transportation and storage	$	2,616	$	6,000	$	4,769
Interstate transportation and storage	6		25		11
Midstream	6,503		12,682		8,569
NGL and refined products transportation and services	17,049		21,656		16,248
Crude oil transportation and services	23,071		22,917		14,759
Investment in Sunoco LP	21,703		24,350		16,246
Investment in USAC	137		111		85
All other	1,740		3,328		3,068
Eliminations	(12,284)		(18,837)		(13,360)
Total cost of products sold	$	60,541	$	72,232	$	50,395


	Years Ended December 31,
	2023		2022		2021
Depreciation, depletion and amortization:
Intrastate transportation and storage	$	214	$	209	$	191
Interstate transportation and storage	563		513		457
Midstream	1,451		1,351		1,190
NGL and refined products transportation and services	915		865		778
Crude oil transportation and services	740		663		588
Investment in Sunoco LP	187		193		177
Investment in USAC	246		237		239
All other	69		133		197
Total depreciation, depletion and amortization	$	4,385	$	4,164	$	3,817


	Years Ended December 31,
	2023		2022		2021
Equity in earnings (losses) of unconsolidated affiliates:
Intrastate transportation and storage	$	17	$	17	$	20
Interstate transportation and storage	260		175		140
Midstream	15		19		24
NGL and refined products transportation and services	76		44		51
Crude oil transportation and services	11		(2)		10


All other	4		4		1
Total equity in earnings of unconsolidated affiliates	$	383	$	257	$	246


	Years Ended December 31,
	2023		2022		2021
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	1,111	$	1,396	$	3,483
Interstate transportation and storage	2,009		1,753		1,515
Midstream	2,525		3,210		1,868
NGL and refined products transportation and services	3,894		3,025		2,828
Crude oil transportation and services	2,681		2,187		2,023
Investment in Sunoco LP	964		919		754
Investment in USAC	512		426		398
All Other	2		177		177
Adjusted EBITDA (consolidated)	$	13,698	$	13,093	$	13,046


	Years Ended December 31,
	2023		2022		2021
Reconciliation of net income to Adjusted EBITDA:
Net income	$	5,294	$	5,868	$	6,687
Depreciation, depletion and amortization	4,385		4,164		3,817
Interest expense, net of interest capitalized	2,578		2,306		2,267
Income tax expense	303		204		184
Impairment losses and other	12		386		21
Gains on interest rate derivatives	(36)		(293)		(61)
Non-cash compensation expense	130		115		111
Unrealized gains on commodity risk management activities	(3)		(42)		(162)
Inventory valuation adjustments	114		(5)		(190)
(Gains) losses on extinguishments of debt	(2)		—		38
Adjusted EBITDA related to unconsolidated affiliates	691		565		523
Equity in earnings of unconsolidated affiliates	(383)		(257)		(246)

Non-operating litigation-related loss	627		—		—
Other, net	(12)		82		57
Adjusted EBITDA (consolidated)	$	13,698	$	13,093	$	13,046


	December 31,
	2023		2022		2021
Segment assets:
Intrastate transportation and storage	$	6,112	$	6,609	$	7,322
Interstate transportation and storage	17,708		17,979		17,774
Midstream	25,592		21,851		21,960
NGL and refined products transportation and services	27,214		27,903		28,160
Crude oil transportation and services	25,464		19,200		19,649
Investment in Sunoco LP	6,826		6,830		5,815
Investment in USAC	2,737		2,666		2,768
All other and eliminations	2,045		2,605		2,515
Total segment assets	$	113,698	$	105,643	$	105,963


	Years Ended December 31,
	2023		2022		2021
Additions to property, plant and equipment (1):
Intrastate transportation and storage	$	93	$	179	$	52
Interstate transportation and storage	383		644		159
Midstream	832		1,004		484
NGL and refined products transportation and services	679		507		751
Crude oil transportation and services	266		246		343
Investment in Sunoco LP	215		186		174
Investment in USAC	300		169		60
All other	100		91		135
Total additions to property, plant and equipment (1)	$	2,868	$	3,026	$	2,158


	December 31,
	2023		2022		2021
Investments in unconsolidated affiliates:
Intrastate transportation and storage	$	144	$	139	$	110
Interstate transportation and storage	2,179		2,201		2,209
Midstream	141		54		101
NGL and refined products transportation and services	390		398		457
Crude oil transportation and services	187		48		19


All other	56		53		51
Total investments in unconsolidated affiliates	$	3,097	$	2,893	$	2,947

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

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,
	2023		2022		2021
Current expense:
Federal	$	56	$	—	$	19
State	44		17		24

Total	100		17		43
Deferred expense (benefit):
Federal	227		239		246
State	(24)		(58)		(106)
Foreign	—		6		1
Total	203		187		141
Total income tax expense	$	303	$	204	$	184

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


	Years Ended December 31,
	2023		2022		2021

Income tax expense at United States statutory rate	$	1,175	$	1,275	$	1,443
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax	(884)		(1,086)		(1,211)
Noncontrolling interests	—		26		—
State tax, net of federal tax benefit	47		19		85
Statutory rate change	(10)		(42)		(46)
Valuation allowance	(3)		(4)		(63)
Uncertain tax positions	(14)		(3)		(34)
Dividend received deduction	(3)		(3)		(4)


Foreign taxes	—		6		1

Other	(5)		16		13
Income tax expense	$	303	$	204	$	184

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


	December 31,
	2023		2022
Deferred income tax assets:
Net operating losses and other carryforwards	$	371	$	603


Other	46		60
Total deferred income tax assets	417		663
Valuation allowance	—		(19)
Net deferred income tax assets	417		644

Deferred income tax liabilities:
Property, plant and equipment	(232)		(218)

Investments in affiliates	(4,003)		(4,010)
Trademarks	(91)		(89)
Other	(22)		(28)
Total deferred income tax liabilities	(4,348)		(4,345)
Net deferred income taxes	$	(3,931)	$	(3,701)

ScheduleOfUnrecognizedTaxBenefits [Table Text Block]

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


	Years Ended December 31,
	2023		2022		2021
Balance at beginning of year	$	52	$	56	$	90



Reduction attributable to tax positions taken in prior years	(9)		(4)		(34)
Settlements	(3)		—		—

Balance at end of year	$	40	$	52	$	56

Lease Accounting - Lease Maturities (Details) $ in Millions	Dec. 31, 2023 USD ($)
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
2024	$ 96
2024	7
2024	103
2025	90
2025	8
2025	98
2026	81
2026	4
2026	85
2027	71
2027	2
2027	73
2028	70
2028	1
2028	71
Thereafter	979
Thereafter	12
Thereafter	991
Total lease payments	1,387
Total lease payments	34
Lease Liabilities, Due	1,421
Less: present value discount	553
Less: present value discount	7
Less: present value discount	$ 560
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]	Non-current operating lease liabilities
Operating Lease, Liability	$ 834
Finance Lease, Liability	27
Lease, Liabilities	$ 861
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2024
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2025
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2026
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Lessee, Lease, Description [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2027
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	2028

Estimates (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Depreciation, depletion and amortization expense	$ 3,986	$ 3,774	$ 3,465
Capitalized interest	$ 77	$ 112	$ 135
Property, Plant and Equipment [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
2024	$ 434
2025	423
2026	417
2027	400
2028	$ 397
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	2024
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	2025
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	2026
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	2027
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	2028

Operations And Organization Operations and Organization (Policies)	12 Months Ended
	Dec. 31, 2023
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 majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation.

Income Taxes Components of Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current expense:
Federal	$ 56	$ 0	$ 19
State	44	17	24
Total	100	17	43
Deferred expense (benefit):
Federal	227	239	246
State	(24)	(58)	(106)
Deferred Foreign Income Tax Expense (Benefit)	0	6	1
Total	203	187	141
Total income tax expense	$ 303	$ 204	$ 184

Estimates (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Other Information [Abstract]
Deposits paid to vendors	$ 205	$ 334
Prepaid expenses and other	308	392
Total other current assets	$ 513	$ 726

Subsidiary Equity Incentive Plans (Details) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	39.1	37.7
Unvested awards	$ 10,840,000	$ 9.62
Awards granted	10.7
Awards granted	$ 13.78
Awards vested	(7.7)
Awards vested	$ 9.22
Awards forfeited	1.6
Awards forfeited	$ 9.52
Sunoco LP Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	1.6	1.8
Unvested awards	$ 41.08	$ 34.29
Awards granted	0.4
Awards granted	$ 53.37	$ 43.54	$ 37.72
Awards vested	(0.6)
Awards vested	$ 28.35
Awards forfeited	0.0
Awards forfeited	$ 34.64
USAC Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	1.9	2.1
Unvested awards	$ 17.08	$ 14.21
Awards granted	0.5
Awards granted	$ 23.13	$ 18.31	$ 14.92
Awards vested	(0.6)
Awards vested	$ 13.29
Awards forfeited	0.1
Awards forfeited	$ 17.50

Retirement Benefits (Benefit Payments) (Details) $ in Millions	Dec. 31, 2023 USD ($)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2024	$ 14
2025	14
2026	13
2027	12
2028	32
2029 – 2033	23
Defined Benefit Plan, Funded Plan \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2024	1
2025	1
2026	1
2027	1
2028	1
2029 – 2033	7
Defined Benefit Plan, Unfunded Plan \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2024	3
2025	3
2026	2
2027	2
2028	2
2029 – 2033	$ 5

Derivative Assets And Liabilities Derivative Assets and Lianilities (Offsetting Agreements Netting Table) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Asset Derivatives	$ 616	$ 688
Derivative Liabilities	(464)	(549)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(72)	(85)
Derivative Liability, Fair Value, Amount Offset Against Collateral	72	85
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(368)	(359)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	368	359
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	176	244
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	24	105
Without offsetting agreements [Member]
Asset Derivatives	6	0
Derivative Liabilities	(4)	(23)
OTC Contracts [Member]
Asset Derivatives	132	95
Derivative Liabilities	(80)	(108)
Broker cleared derivative contracts [Member]
Asset Derivatives	478	593
Derivative Liabilities	$ (380)	$ (418)

Lease Accounting (Policies)	12 Months Ended
Lease Accounting (Policies)	Dec. 31, 2023
Leases [Abstract]
Lessee, Leases [Policy Text Block]	Lessee Accounting The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on our consolidated balance sheets. At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term. To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives. Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance. For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.
Lessor, Leases [Policy Text Block]	Lessor Accounting Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement.

Advances to and Investments in Unconsolidated Affiliates Investment in Affiliates (Carrying Values) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Investments in unconsolidated affiliates	$ 3,097	$ 2,893	$ 2,947
Equity in earnings of unconsolidated affiliates	383	257	246
Other Affiliates [Member]
Equity in earnings of unconsolidated affiliates	103	89	82
Citrus [Member]
Investments in unconsolidated affiliates	1,811	1,800
Equity in earnings of unconsolidated affiliates	146	141	157
MEP [Member]
Investments in unconsolidated affiliates	332	360
Equity in earnings of unconsolidated affiliates	87	10	(17)
White Cliffs
Investments in unconsolidated affiliates	203	218
Equity in earnings of unconsolidated affiliates	10	(8)	0
Other
Investments in unconsolidated affiliates	684	446
Explorer
Investments in unconsolidated affiliates	67	69
Equity in earnings of unconsolidated affiliates	$ 37	$ 25	$ 24

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details)				1 Months Ended		12 Months Ended
	Sep. 21, 2022 USD ($)	Dec. 29, 2021 USD ($)	Aug. 01, 2020 USD ($)	Jan. 31, 2023 USD ($)	Jun. 30, 2022 USD ($)	Dec. 31, 2023 USD ($) Rate	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Operating Leases, Rent Expense						$ 68,000,000	$ 64,000,000	$ 48,000,000
Payments for Environmental Liabilities						29,000,000	30,000,000
Total environmental liabilities						$ 277,000,000	$ 282,000,000
Site Contingency, Number of Sites Needing Remediation						32
Loss Contingency, Estimate of Possible Loss						$ 200,000,000
Litigation Settlement, Expense						161,000,000
Legal Fees						$ 18,000,000
Environmental Loss Contingency, Statement of Financial Position [Extensible Enumeration]						Other non-current liabilities	Other non-current liabilities
Interest Statutory Rate \| Rate						12.00%
Williams
Loss Contingency, Damages Sought, Value						$ 410,000,000				$ 1,480,000,000
Payments for Legal Settlements						627,000,000
Litigation Settlement, Expense	$ 601,000,000
Debt Instrument, Interest Rate, Stated Percentage	3.50%
Litigation Settlement, Amount Awarded to Other Party		$ 190,000,000
Cline Class Action \| Actual Damages
Payments for Legal Settlements			$ 74,800,000
Cline Class Action \| Punitive Damages [Member]
Payments for Legal Settlements			75,000,000
Cline Class Action \| Amended Actual Damages
Payments for Legal Settlements			$ 80,700,000
Ohio EPA
Loss Contingency, Damages Sought, Value									$ 2,600,000
Proposed Civil Penalty
Payments for Legal Settlements						20,000,000
Litigation Settlement, 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
Related To Deductibles [Member]
Loss Contingency Accrual						$ 285,000,000	$ 200,000,000

Income Taxes Components of Net Deferred Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Components of Net Deferred Income Tax [Abstract]
Total deferred income tax assets	$ 417	$ 663
Deferred Tax Liabilities, Net	(3,931)	(3,701)
Valuation allowance	0	19
Net deferred income tax assets	$ 417	$ 644

Revenue Contracts with customers (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jan. 01, 2019
Contract with Customer, Liability	$ 749	$ 615	$ 459
Additions	1,254	1,113
Deferred Revenue, Revenue Recognized	$ (1,120)	(944)
Deferred Revenue, Period Increase (Decrease)		(13)
Sunoco LP [Member]
Contract with Customer, Liability		0		$ 0
Accounts receivable from contracts with customers		834		809
Contract assets		$ 200		$ 256

Net Income Per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2023

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,
	2023		2022		2021
Net income	$	5,294	$	5,868	$	6,687
Less: Net income attributable to redeemable noncontrolling interests	60		51		50
Less: Net income attributable to noncontrolling interests	1,299		1,061		1,167
Net income, net of noncontrolling interests	3,935		4,756		5,470
Less: General Partner’s interest in income	3		4		6
Less: Preferred Unitholders’ interest in income	463		422		285
Common Unitholders’ interest in net income	$	3,469	$	4,330	$	5,179
Basic Income per Common Unit:
Weighted average common units	3,161.7		3,086.8		2,734.4
Basic income per common unit	$	1.10	$	1.40	$	1.89

Diluted Income per Common Unit:
Common Unitholders’ interest in net income	$	3,469	$	4,330	$	5,179
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units	(1)		(2)		(2)
Diluted income available to Common Unitholders	$	3,468	$	4,328	$	5,177
Weighted average common units	3,161.7		3,086.8		2,734.4

Dilutive effect of unvested unit awards	15.5		10.2		5.1
Weighted average common units, assuming dilutive effect of unvested unit awards	3,177.2		3,097.0		2,739.5
Diluted income per common unit	$	1.09	$	1.40	$	1.89

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

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Regulatory Accounting - Regulatory Assets and Liabilities

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.

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 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, 2023 and 2022, Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $230 million and $116 million, respectively. For the years ended December 31, 2023, 2022 and 2021, 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, 2023, 2022 and 2021, the Partnership’s cost of products sold included an unfavorable inventory adjustment of $114 million, a favorable inventory adjustment of $5 million and a favorable inventory adjustment of $190 million, respectively, related to Sunoco LP’s LIFO inventory.

The Partnership’s inventories consisted of the following:


	December 31,
	2023		2022
Natural gas, NGLs and refined products	$	1,658	$	1,802
Crude oil	258		246
Spare parts and other	562		413
Total inventories	$	2,478	$	2,461

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.

Property, Plant and Equipment

Property, Plant and Equipment, 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 2023, 2022 and 2021, USAC recognized fixed asset impairments of $12 million, $1 million and $5 million, respectively, 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 current borrowing rate of our revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed

by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

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, 2023				December 31, 2022
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	9,098	$	(3,196)	$	7,884	$	(2,807)
Patents (10 years)	48		(48)		48		(48)

Trade names (20 years)	66		(44)		66		(41)
Other (5 to 20 years)	12		(11)		12		(13)
Total amortizable intangible assets	9,224		(3,299)		8,010		(2,909)
Non-amortizable intangible assets:
Trademarks	302		—		302		—
Other	12		—		12		—
Total non-amortizable intangible assets	314		—		314		—
Total intangible assets	$	9,538	$	(3,299)	$	8,324	$	(2,909)

Aggregate amortization expense of intangible assets was as follows:


	Years Ended December 31,
	2023		2022		2021
Reported in depreciation, depletion and amortization expense	$	399	$	390	$	352

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


Years Ending December 31:
2024	$	434
2025	423
2026	417
2027	400
2028	397

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

Goodwill

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

Changes in the carrying amount of goodwill were as follows:


	Intrastate Transportation and Storage		Interstate Transportation and Storage		Midstream		NGL and Refined Products Transportation and Services		Crude Oil Transportation and Services		Investment in Sunoco LP		Investment in USAC		All Other		Total
Balance, December 31, 2021	$	—	$	—	$	—	$	693	$	190	$	1,568	$	—	$	82	$	2,533
Acquired	—		—		—		—		—		33		—		—		33



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

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During the fourth quarter of 2023, $1.46 billion of goodwill was recorded in conjunction with the acquisition of Crestwood, which is not expected to be deductible for tax purposes. In 2022, Sunoco LP recorded $33 million of goodwill in conjunction with its acquisitions.

The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. The fair value estimates used in the long-lived asset and goodwill tests were primarily based on Level 3 inputs of the fair value hierarchy.

Management does not believe that any of the goodwill balances in its reporting units is currently at significant risk of impairment; however, of the $4.02 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2023, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by approximately 20% or less in the most recent quantitative test.

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, 2023 and 2022, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $410 million and $362 million, respectively. For the years ended December 31, 2023, 2022 and 2021 aggregate accretion expense related to AROs was $10 million, $4 million and $12 million, respectively.

Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2023 and 2022, 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.

Redeemable Noncontrolling Interest [Text Block]

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 Costs, Policy [Policy Text Block]

Environmental Remediation

We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.

Fair Value of Financial Instruments

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, 2023, 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. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received.

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, 2023, 2022 and 2021, excise taxes collected by Sunoco LP were $274 million, $285 million and $332 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.

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, 2023, 2022 and 2021, our qualifying income met the statutory requirement.

The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local, and foreign income taxes. These corporate subsidiaries include ETP Holdco, Sunoco Retail LLC, and Aloha, among others. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.

Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our consolidated financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.

If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.

Share-based Payment Arrangement [Policy Text Block]

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

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

Pensions and Other Postretirement Benefit Plans

The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.

Allocation of Income (Loss)

Allocation of Income

For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

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.

Retirement Benefits

12 Months Ended

Dec. 31, 2023

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 $86 million, $79 million and $65 million to these 401(k) savings plans for the years ended December 31, 2023, 2022 and 2021, respectively.

Pension and Other Postretirement Benefit Plans


	December 31, 2023						December 31, 2022
	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	$	22	$	19	$	148	$	50	$	26	$	195
Service cost	—		—		—		—		—		1
Interest cost	1		1		6		1		1		4

Benefits paid, net	(1)		(3)		(13)		(1)		(3)		(14)

Actuarial gain and other	1		—		(3)		(8)		(3)		(38)

Energy Transfer Canada sale	—		—		—		(20)		(2)		—
Benefit obligation at end of period	23		17		138		22		19		148

Change in plan assets:
Fair value of plan assets at beginning of period	20		—		259		44		—		311
Return on plan assets and other	2		—		29		(4)		—		(41)
Employer contributions	1		—		2		1		—		3
Benefits paid, net	(1)		—		(13)		(1)		—		(14)

Energy Transfer Canada sale	—		—		—		(20)		—		—
Fair value of plan assets at end of period	22		—		277		20		—		259

Amount underfunded (overfunded) at end of period	$	1	$	17	$	(139)	$	2	$	19	$	(111)

Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	$	—	$	—	$	155	$	—	$	—	$	127
Current liabilities	—		(3)		(2)		—		(3)		(2)
Non-current liabilities	(1)		(14)		(14)		(2)		(16)		(14)
	$	(1)	$	(17)	$	139	$	(2)	$	(19)	$	111

Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)	$	—	$	(2)	$	(12)	$	—	$	(2)	$	5
Prior service credit	—		—		(3)		—		—		(3)
	$	—	$	(2)	$	(15)	$	—	$	(2)	$	2

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


	December 31, 2023						December 31, 2022
	Pension Benefits						Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits		Funded Plans		Unfunded Plans		Other Postretirement Benefits
Projected benefit obligation	$	23	$	15	N/A		$	22	$	19	N/A
Accumulated benefit obligation	23		17		$	138	22		19		$	148
Fair value of plan assets	22		—		277		20		—		259

Components of Net Periodic Benefit Cost


	December 31, 2023				December 31, 2022
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—	$	—	$	—	$	1
Interest cost	1		6		2		4
Expected return on plan assets	(1)		(12)		(2)		(11)
Prior service cost amortization	—		2		—		19
Actuarial gain amortization	—		(1)		—		—



Net periodic benefit cost	$	—	$	(5)	$	—	$	13

Assumptions

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


	December 31, 2023				December 31, 2022
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	2.70	%	4.62	%	5.00	%	2.46	%

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


	December 31, 2023				December 31, 2022
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	2.70	%	4.93	%	2.70	%	2.58	%
Expected return on assets:
Tax exempt accounts	7.00	%	7.00	%	7.00	%	7.00	%
Taxable accounts	—		4.75	%	—		4.75	%

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

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


	December 31,
	2023		2022
Health care cost trend rate	7.42	%	7.48	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.17	%	5.18	%
Year that the rate reaches the ultimate trend rate	2031		2030

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, 2023
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	2	$	2	$	—	$	—
Mutual funds (1)	20		20		—		—

Total	$	22	$	22	$	—	$	—

(1)Comprised of approximately 100% equities as of December 31, 2023.


			Fair Value Measurements at December 31, 2022
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and cash equivalents	$	2	$	2	$	—	$	—
Mutual funds (1)	18		18		—		—

Total	$	20	$	20	$	—	$	—

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

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


			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.


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

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

Contributions

We expect to contribute $3 million to pension plans and $1 million to other postretirement plans in 2024. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

Benefit Payments


	Pension Benefits - Funded Plans		Pension Benefits - Unfunded Plans		Other Postretirement Benefits (Gross, Before Medicare Part D)
2024	$	1	$	3	$	14
2025	1		3		14
2026	1		2		13
2027	1		2		12
2028	1		2		32
2029 – 2033	7		5		23

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

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

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 70
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480794/715-70-50-1

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480482/715-20-55-17

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(i)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (q)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

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

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iii)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
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-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
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-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480506/715-20-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480126/715-20-S99-2

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 60
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147480266/715-60-50-3

+ Details

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

Dec. 31, 2023

BBtu

MB_bls

barrels

Dec. 31, 2022

BBtu

MB_bls

barrels

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

Derivative, Nonmonetary Notional Amount, Volume

(96,828)

(202,815)

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

Derivative, Nonmonetary Notional Amount, Volume

(15,758)

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

Derivative, Nonmonetary Notional Amount, Volume

(1,751)

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

Derivative, Nonmonetary Notional Amount, Volume

(900)

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

Derivative, Nonmonetary Notional Amount, Volume

(1,878)

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

Derivative, Nonmonetary Notional Amount, Volume

^[1]

(171,185)

(39,563)

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

Derivative, Nonmonetary Notional Amount, Volume

(39,013)

(37,448)

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

Derivative, Nonmonetary Notional Amount, Volume

(39,013)

(37,448)

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

Derivative, Nonmonetary Notional Amount, Volume

(7,125)

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

Derivative, Nonmonetary Notional Amount, Volume

(124,210)

(42,440)

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

Derivative, Nonmonetary Notional Amount, Volume

(2,423)

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

Derivative, Nonmonetary Notional Amount, Volume

(145)

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

Derivative, Nonmonetary Notional Amount, Volume

(1,900)

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

Derivative, Nonmonetary Notional Amount, Volume

(250)

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

Derivative, Nonmonetary Notional Amount, Volume

(39,013)

(37,448)

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

Derivative, Nonmonetary Notional Amount, Volume | MW

(464,897)

(21,384)

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

Derivative, Nonmonetary Notional Amount, Volume | MW

(155,600)

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

Derivative, Nonmonetary Notional Amount, Volume | MW

(136,000)

(119,200)

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

Derivative, Nonmonetary Notional Amount, Volume | MB_bls

(13,870)

Natural Gas Liquids [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member]

Derivative, Nonmonetary Notional Amount, Volume | MB_bls

(6,934)

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

Derivative, Nonmonetary Notional Amount, Volume | MB_bls

(4,548)

(3,547)

Crude Oil [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member]

Derivative, Nonmonetary Notional Amount, Volume | barrels

(2,674)

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

Derivative, Nonmonetary Notional Amount, Volume | barrels

(795)

Commodity Derivatives - Crude [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member]

Derivative, Nonmonetary Notional Amount, Volume

(15)

Commodity Derivatives - Crude [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]

Derivative, Nonmonetary Notional Amount, Volume

(20)

Commodity Derivatives - NGL/Refined Products | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]

Derivative, Nonmonetary Notional Amount, Volume

(43)

Commodity Derivatives - NGL/Refined Products | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member]

Derivative, Nonmonetary Notional Amount, Volume

(121)

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

Income Taxes Reconciliation of Income Tax Satutory Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income tax expense at United States statutory rate	$ 1,175	$ 1,275	$ 1,443
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax	(884)	(1,086)	(1,211)
Noncontrolling interests	0	26	0
State tax, net of federal tax benefit	47	19	85
Statutory rate change	(10)	(42)	(46)
Valuation allowance	(3)	(4)	(63)
Uncertain tax positions	(14)	(3)	(34)
Dividend received deduction	(3)	(3)	(4)
Foreign taxes	0	6	1
Other	(5)	16	13
Income tax expense	$ 303	$ 204	$ 184

Lease Accounting - Components of Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	$ 88	$ 88
Interest on lease liabilities	0	0
Lease, Cost	100	94
Lease costs, gross	142	134
Finance Leases [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost	0	0
Cost of goods sold
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	1	3
Operating expenses
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	69	63
Short-term lease cost	38	33
Variable lease cost	16	13
Selling, general and administrative
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	18	22
Depreciation, depletion and amortization
Lessee, Lease, Description [Line Items]
Amortization of lease assets	0	0
Other Revenue [Member]
Lessee, Lease, Description [Line Items]
Sublease Income	$ 42	$ 40

Income Taxes Effects of Temporary Differences That Comprise Net Deffered Income Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred income tax assets:
Net operating losses and other carryforwards	$ 371	$ 603
Other	46	60
Deferred Tax Assets, Gross	417	663
Valuation allowance	0	(19)
Net deferred income tax assets	417	644
Deferred income tax liabilities:
Property, plant and equipment	(232)	(218)
Investments in affiliates	(4,003)	(4,010)
Trademarks	(91)	(89)
Other	(22)	(28)
Deferred Tax Liabilities, Gross	4,348	4,345
Deferred Tax Liabilities	$ (3,931)	$ (3,701)

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
Pay vs Performance Disclosure - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
NET INCOME ATTRIBUTABLE TO PARTNERS	$ 3,935	$ 4,756	$ 5,470

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(ii))
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 323
-SubTopic 10
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Consolidated Statement Of Equity - USD ($) $ in Thousands	Total	General Partner	Accumulated Other Comprehensive Income	Common Unitholders	Non- controlling Interests	Preferred Unitholders	Rollup Mergers	Rollup Mergers General Partner	Rollup Mergers Accumulated Other Comprehensive Income	Rollup Mergers Common Unitholders	Rollup Mergers Non- controlling Interests	Rollup Mergers Preferred Unitholders	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
Balance at Dec. 31, 2020	$ 31,388,000	$ (8,000)	$ 6,000	$ 18,531,000	$ 12,859,000	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(1,898,000)	(2,000)	0	(1,616,000)	0	(280,000)
Distributions to noncontrolling interests	(1,487,000)	0	0	0	(1,487,000)	0
Common units repurchased	(31,000)	0	0	(31,000)	0	0
Common units repurchased under buyback program	(31,000)
Units issued	889,000	0	0	0	0	889,000
Capital contributions from noncontrolling interests	226,000	0	0	0	226,000	0
Other, net	58,000	0	0	50,000	11,000	(3,000)
Partners' Capital Account, Acquisitions	3,543,000	0	0	3,117,000	34,000	392,000	$ 0	$ 0	$ 0	$ 0	$ (4,768,000)	$ 4,768,000
Other comprehensive income, net of tax	20,000	0	17,000	0	3,000	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	6,637,000	6,000	0	5,179,000	1,167,000	285,000
Balance at Dec. 31, 2021	39,345,000	(4,000)	23,000	25,230,000	8,045,000	6,051,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(3,047,000)	(2,000)	0	(2,623,000)	0	(422,000)
Distributions to noncontrolling interests	(1,547,000)	0	0	0	(1,547,000)	0
Common units repurchased under buyback program	0
Capital contributions from noncontrolling interests	405,000	0	0	0	405,000	0
Noncontrolling Interest, Decrease from Deconsolidation	(346,000)	0	(9,000)	0	(337,000)	0
Other, net	36,000	0	0	23,000	13,000	0
Other comprehensive income, net of tax	(4,000)	0	2,000	0	(6,000)	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	5,817,000	4,000	0	4,330,000	1,061,000	422,000
Balance at Dec. 31, 2022	40,659,000	(2,000)	16,000	26,960,000	7,634,000	6,051,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(4,248,000)	(3,000)	0	(3,777,000)	0	(468,000)
Distributions to noncontrolling interests	(1,691,000)	0	0	0	(1,691,000)	0
Common units repurchased under buyback program	0
Capital contributions from noncontrolling interests	3,000	0	0	0	3,000	0
Other, net	30,000	0	0	18,000	12,000	0
Partners' Capital Account, Acquisitions													$ 574,000	$ 0	$ 0	$ 574,000	$ 0	$ 0	$ 3,366,000	$ 0	$ 0	$ 2,953,000	$ 0	$ 413,000
Other comprehensive income, net of tax	12,000	0	12,000	0	0	0
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest	5,234,000	3,000	0	3,469,000	1,299,000	463,000
Balance at Dec. 31, 2023	$ 43,939,000	$ (2,000)	$ 28,000	$ 30,197,000	$ 7,257,000	$ 6,459,000

Debt Obligations (Debt Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Unamortized Discounts, Premiums, Fair Value Adjustments and Deferred Debt Issuance Costs	$ (237)
Five Year Credit Facility
Line of Credit Facility, Current Borrowing Capacity	5,000
Letters of Credit Outstanding, Amount	29
Line of Credit Facility, Remaining Borrowing Capacity	$ 3,560
Line of Credit Facility, Interest Rate at Period End	5.87%
Outstanding borrowings	$ 1,410
Commercial Paper	1,370
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	8.00%
Junior Subordinated Notes	$ 800
HFOTCO tax-exempt bonds
Debt Instrument, Interest Rate, Stated Percentage	4.05%
Unsecured Debt	$ 225
6.875% Senior Notes due 2026
Debt Instrument, Interest Rate, Stated Percentage	6.875%
USAC [Member] \| USAC Credit Facility, due 2023 [Member]
Line of Credit Facility, Current Borrowing Capacity	$ 728
Letters of Credit Outstanding, Amount	0
Line of Credit Facility, Remaining Borrowing Capacity	$ 529
Line of Credit Facility, Interest Rate at Period End	7.98%
Outstanding borrowings	$ 872
Line of Credit Facility, Maximum Borrowing Capacity	1,600
Sunoco LP [Member] \| Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member]
Line of Credit Facility, Current Borrowing Capacity	1,500
Letters of Credit Outstanding, Amount	5
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,080
Line of Credit Facility, Interest Rate at Period End	7.54%
Outstanding borrowings	$ 411	$ 900
Accordion feature [Member] \| Five Year Credit Facility
Line of Credit Facility, Current Borrowing Capacity	$ 7,000

Consolidated Balance Sheets Balance Sheet (Paranthetical) - shares	Dec. 31, 2023	Dec. 31, 2022
Class of Stock [Line Items]
Authorized	3,367,525,806	3,094,425,367
Issued	3,367,525,806	3,094,425,367
Outstanding	3,367,525,806	3,094,425,367
Preferred Units, Authorized	113,648,967	72,184,780
Preferred Units, Issued	113,648,967	72,184,780
Preferred Units, Outstanding	113,648,967	72,184,780

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
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Reference 2: http://www.xbrl.org/2003/role/recommendedDisclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Revenue (Notes)

12 Months Ended

Dec. 31, 2023

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE:

Disaggregation of revenue

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

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services;

•investment in Sunoco LP;

•fuel distribution and marketing;

•all other;

•investment in USAC;

•contract operations;

•retail parts and services; and

•all other.

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

Intrastate transportation and storage revenue

Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay

any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed.

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

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

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

Interstate transportation and storage revenue

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

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

Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly owned subsidiary of Royal Dutch Shell plc (“Shell”). Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed.

The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal.

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

Midstream revenue

Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed and/or transported. The various types of revenue contracts our midstream segment enters into include:

Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed.

Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed.

Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:

•In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.

•Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received.

Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition.

Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints.

Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers.

NGL and refined products transportation and services revenue

Our NGL and refined products transportation and services segment’s revenues are primarily derived from transportation, fractionation, blending and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic 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.

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 and marketing revenue

Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to dealers, sales to distributors, unbranded wholesale revenue, commission agent revenue, rental income and other income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method.

Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right

to return motor fuel. 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 FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized.

Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer.

Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor is recognized ratably over the term of the underlying lease.

Sunoco LP’s all other revenue

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

USAC’s contract operations revenue

USAC’s revenue from contracted compression, 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, 2021	$	459
Additions	1,113
Revenue recognized	(944)
Other	(13)
Balance, December 31, 2022	615
Additions	1,254
Revenue recognized	(1,120)

Balance, December 31, 2023	$	749

The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2023 and 2022 were as follows:


	December 31,
	2023		2022
Contract Balances
Contract assets	$	256	$	200
Accounts receivable from contracts with customers	809		834
Contract liabilities	—		—

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, 2023, 2022 and 2021 was $29 million, $22 million and $21 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.


	Years Ending December 31,
	2024		2025		2026		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of December 31, 2023	$	7,590	$	6,497	$	5,769	$	19,240	$	39,096

Practical Expedients Utilized by the Partnership

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

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

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

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

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

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

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

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

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-9

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-10

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-15

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-12

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147479806/606-10-50-13

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org//606/tableOfContent

+ Details

Retirement Benefits (Benefit Assumptions) (Details)	12 Months Ended
Retirement Benefits (Benefit Assumptions) (Details)	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate	7.42%	7.48%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.17%	5.18%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.70%	5.00%
Discount rate	2.70%	2.70%
Tax exempt accounts	7.00%	7.00%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.62%	2.46%
Discount rate	4.93%	2.58%
Tax exempt accounts	7.00%	7.00%
Taxable accounts	4.75%	4.75%

Lease Accounting Narrative (Details)	Dec. 31, 2023
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

Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Retirement Benefits [Line Items]
Defined Contribution Plan, Cost	$ 86	$ 79	$ 65
Pension Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 3
Large Cap US Equitiies	100.00%	100.00%
Other Postretirement Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 1

Equity

12 Months Ended

Dec. 31, 2022

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, 2023, 2022 and 2021 was as follows:


	Years Ended December 31,
	2023	2022	2021
Number of Common Units, beginning of period	3,094.4	3,082.5	2,702.4

Common Units issued in mergers and acquisitions (1)	260.2	—	374.6
Common Units repurchased	—	—	(4.2)
Issuance of Common Units (2)	12.9	11.9	9.7
Number of Common Units, end of period	3,367.5	3,094.4	3,082.5

(1)Common units issued related to our acquisitions of Crestwood and Lotus Midstream in 2023 and of Enable in 2021.

(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, 2023, the Partnership had outstanding 833,486,004 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 2023 or 2022. As of December 31, 2023, $880 million remained available to repurchase under the current program.

Energy Transfer Distribution Reinvestment Program

During the year ended December 31, 2023, distributions of $90 million were reinvested under the distribution reinvestment program. As of December 31, 2023, a total of 4.5 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment program.

Energy Transfer Preferred Units

As of December 31, 2023, Energy Transfer’s outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series B Preferred Units, 18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units, 32,000,000 Series E Preferred Units, 500,000 Series F Preferred Units, 1,484,780 Series G Preferred Units, 900,000 Series H Preferred Units and 41,464,179 Series I 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, 2020	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Preferred units conversion (1)	943		547		440		434		786		504		1,114		—		—		4,768
Units issued for cash	—		—		—		—		—		—		—		889		—		889
Distributions to partners	(30)		(18)		(25)		(25)		(45)		(34)		(79)		(24)		—		(280)
Units issued in Enable acquisition	—		—		—		—		—		—		392		—		—		392
Other, net	—		—		—		—		—		—		—		(3)		—		(3)
Net income	45		27		25		25		45		26		61		31		—		285
Balance, December 31, 2021	958		556		440		434		786		496		1,488		893		—		6,051
Distributions to partners	(59)		(36)		(33)		(34)		(61)		(34)		(106)		(59)		—		(422)
Net income	59		36		33		34		61		34		106		59		—		422
Balance, December 31, 2022	958		556		440		434		786		496		1,488		893		—		6,051
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

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.

Series B Preferred Units

Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, or a successor rate, in each case determined quarterly by our calculation agent, 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 based on the three-month SOFR, plus a tenor spread adjustment of 0.26161%, plus 4.530% per annum. The Series C Preferred Units were redeemed in February 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 Series D Preferred Units were redeemed in February 2024.

Series E Preferred Units

Distributions on the Series E Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2024, at a rate of 7.600% per annum of the stated liquidation preference of $25. On and after May 15, 2024, distributions on the Series E Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, or a successor rate, in each case determined quarterly by our calculation agent, plus a spread of 5.161% per annum. The Series E Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2024 at a redemption price of $25 per Series E Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. The Partnership intends to redeem the Series E Preferred Units in May 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. On December

2, 2021, Energy Transfer issued 384,780 Series G Preferred Units in connection with the Enable acquisition, as discussed in Note 3.

Series H Preferred Units

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

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.

Upcoming Changes in Preferred Unit Distribution Rates

Distributions on the Energy Transfer Series B Preferred Units and Series E Preferred Units are scheduled to begin accruing at a floating rate as follows:


	Beginning of floating rate period	Applicable Spread		Tenor spread adjustment		Floating rate
Series B Preferred Units	February 15, 2028	4.155	%	0.26161	%	Three-month SOFR
Series E Preferred Units	May 15, 2024	5.161	%	0.26161	%	Three-month SOFR

As discussed above, the Partnership expects to redeem the Series E Preferred Units at the beginning of the floating rate period on May 15, 2024.

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, 2023, 2022 and 2021, USAC issued 87,808, 124,255 and 118,399 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. As of December 31, 2023, no warrants are outstanding.

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, 2020

February 8, 2021

February 19, 2021

0.1525

March 31, 2021

May 11, 2021

May 19, 2021

0.1525

June 30, 2021

August 6, 2021

August 19, 2021

0.1525

September 30, 2021

November 5, 2021

November 19, 2021

0.1525

December 31, 2021

February 8, 2022

February 18, 2022

0.1750

March 31, 2022

May 9, 2022

May 19, 2022

0.2000

June 30, 2022

August 8, 2022

August 19, 2022

0.2300

September 30, 2022

November 4, 2022

November 21, 2022

0.2650

December 31, 2022

February 7, 2023

February 21, 2023

0.3050

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

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 (1)	Series B (1)	Series C	Series D	Series E	Series F (1)	Series G (1)	Series H (1)		Series I
March 31, 2021	May 3, 2021	May 17, 2021	$—	$—	$0.4609	$0.4766	$0.4750	$33.7500	$35.63	$—		$—
June 30, 2021	August 2, 2021	August 16, 2021	31.25	33.125	0.4609	0.4766	0.4750	—	—	—		—
September 30, 2021	November 1, 2021	November 15, 2021	—	—	0.4609	0.4766	0.4750	33.7500	35.63	27.08	*	—
December 31, 2021	February 1, 2022	February 15, 2022	31.25	33.125	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

* Represents prorated initial distribution.

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, 2023, Sunoco LP had approximately 84.4 million common units outstanding.


		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Common Unitholders	Holder of IDRs
Minimum Quarterly Distribution	$0.4375	100%	—%
First Target Distribution	$0.4375 to $0.503125	100%	—%
Second Target Distribution	$0.503125 to $0.546875	85%	15%
Third Target Distribution	$0.546875 to $0.656250	75%	25%
Thereafter	Above $0.656250	50%	50%

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

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2020

February 8, 2021

February 19, 2021

0.8255

March 31, 2021

May 11, 2021

May 19, 2021

0.8255

June 30, 2021

August 6, 2021

August 19, 2021

0.8255

September 30, 2021

November 5, 2021

November 19, 2021

0.8255

December 31, 2021

February 8, 2022

February 18, 2022

0.8255

March 31, 2022

May 9, 2022

May 19, 2022

0.8255

June 30, 2022

August 8, 2022

August 19, 2022

0.8255

September 30, 2022

November 4, 2022

November 18, 2022

0.8255

December 31, 2022

February 7, 2023

February 21, 2023

0.8255

March 31, 2023

May 8, 2023

May 22, 2023

0.8420

June 30, 2023

August 14, 2023

August 21, 2023

0.8420

September 30, 2023

October 30, 2023

November 20, 2023

0.8420

December 31, 2023

February 7, 2024

February 20, 2024

0.8420

USAC Cash Distributions

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

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2020

January 25, 2021

February 5, 2021

0.5250

March 31, 2021

April 26, 2021

May 7, 2021

0.5250

June 30, 2021

July 26, 2021

August 6, 2021

0.5250

September 30, 2021

October 25, 2021

November 5, 2021

0.5250

December 31, 2021

January 24, 2022

February 4, 2022

0.5250

March 31, 2022

April 25, 2022

May 6, 2022

0.5250

June 30, 2022

July 25, 2022

August 5, 2022

0.5250

September 30, 2022

October 24, 2022

November 4, 2022

0.5250

December 31, 2022

January 23, 2023

February 3, 2023

0.5250

March 31, 2023

April 24, 2023

May 5, 2023

0.5250

June 30, 2023

July 24, 2023

August 4, 2023

0.5250

September 30, 2023

October 23, 2023

November 3, 2023

0.5250

December 31, 2023

January 22, 2024

February 2, 2024

0.5250

Accumulated Other Comprehensive Income

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


	December 31,
	2023		2022
Available-for-sale securities	$	13	$	9
Foreign currency translation adjustment	(5)		1

Actuarial gain (loss) related to pensions and other postretirement benefits	6		(7)
Investments in unconsolidated affiliates, net	14		13
Total AOCI, net of tax	$	28	$	16

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


	December 31,
	2023		2022
Available-for-sale securities	$	(3)	$	1
Foreign currency translation adjustment	6		6
Actuarial loss relating to pension and other postretirement benefits	—		1
Total	$	3	$	8

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
ASSETS
Cash and cash equivalents	$ 161	$ 257
Accounts receivable, net	9,047	8,466
Inventories	2,478	2,461
Income taxes receivable	67	68
Derivative assets	66	10
Other current assets	513	726
Total current assets	12,433	12,081
Property, plant and equipment	114,932	105,996
Accumulated depreciation and depletion	(29,581)	(25,685)
Property, Plant and Equipment, Net	85,351	80,311
Investments in unconsolidated affiliates	3,097	2,893
Lease right-of-use assets, net	826	819
Other non-current assets, net	1,733	1,558
Intangible assets, net	6,239	5,415
Goodwill	4,019	2,566
Total assets	113,698	105,643
LIABILITIES AND EQUITY
Accounts payable	6,663	6,952
Derivative liabilities	8	23
Operating lease current liabilities	56	45
Accrued and other current liabilities	3,521	3,329
Current maturities of long-term debt	1,008	2
Total current liabilities	11,277	10,368
Long-term debt, less current maturities	51,380	48,260
Non-current derivative liabilities	4	23
Non-current operating lease liabilities	778	798
Deferred income taxes	3,931	3,701
Other non-current liabilities	1,611	1,341
Commitments and contingencies
Redeemable noncontrolling interests	778	493
Limited Partners:
Preferred Unitholders (113,648,967 and 72,184,780 units authorized, issued and outstanding as of December 31, 2023 and 2022, respectively)	6,459	6,051
Common Unitholders (3,367,525,806 and 3,094,445,367 units authorized, issued and outstanding as of December 31, 2023 and 2022, respectively)	30,197	26,960
General Partner	(2)	(2)
Accumulated other comprehensive income	28	16
Total partners’ capital	36,682	33,025
Noncontrolling interests	7,257	7,634
Total equity	43,939	40,659
Total liabilities and equity	113,698	105,643
Related Party
ASSETS
Accounts receivable from related companies	101	93
LIABILITIES AND EQUITY
Accounts payable	$ 21	$ 17

Redeemable Preferred Units (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Jan. 12, 2024	Dec. 31, 2022
Redeemable noncontrolling interests	$ 778		$ 493
Preferred Units, Issued	113,648,967		72,184,780
Preferred Units, Outstanding	113,648,967		72,184,780
USAC [Member]
Redeemable noncontrolling interests	$ 476
Convertible Preferred Stock, Shares Issued upon Conversion	24,985,633
USAC [Member] \| Subsequent Event [Member]
Preferred Units, Issued		40,000
Common Unit, Issued		1,998,850
ET [Member]
Redeemable noncontrolling interests	$ 22
Niobrara
Redeemable noncontrolling interests	$ 280
Preferred Units [Member] \| USAC [Member]
Preferred Units, Issued	500,000		500,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 24.375
Preferred Units, Description	the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and USAC may elect to pay up to 50% of such redemption amount in USAC common units
USAC Preferred Units
Redeemable Noncontrolling Interest, Equity, Carrying Amount			$ 477
Noncontrolling Interest
Redeemable noncontrolling interests			$ 16

Estimates (Property, Plant and Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 114,932	$ 105,996
Less - Accumulated depreciation	(29,581)	(25,685)
Property, plant and equipment, net	$ 85,351	80,311
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	$ 1,529	1,427
Buildings and improvements (1 to 45 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	3,848	3,546
Pipelines and equipment (5 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	88,195	82,353
Right of way (20 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 7,379	6,252
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	$ 2,315	2,405
Product storage and related facilities
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 7,978	7,274
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	$ 3,688	$ 2,739
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

Estimates (Estimated Aggregate Amortization Expense) (Details) $ in Millions	Dec. 31, 2023 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2024	$ 434
2025	423
2026	417
2027	400
2028	$ 397

Reportable Segments Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenue from External Customer [Line Items]
Revenues	$ (78,586)	$ (89,876)	$ (67,417)
Intersegment Eliminations [Member]
Revenue from External Customer [Line Items]
Revenues	(12,308)	(18,941)	(13,423)
Investment in USAC \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(846)	(705)	(633)
Investment in USAC \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(824)	(689)	(621)
Investment in USAC \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(22)	(16)	(12)
All Other \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(1,798)	(3,574)	(3,476)
All Other \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(1,328)	(2,863)	(3,065)
All Other \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(470)	(711)	(411)
Crude Oil Transportation and Services \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(26,536)	(25,982)	(17,446)
Crude Oil Transportation and Services \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(26,534)	(25,980)	(17,442)
Crude Oil Transportation and Services \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(2)	(2)	(4)
NGL and Refined Products Transportation and Services \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(21,903)	(25,657)	(19,961)
NGL and Refined Products Transportation and Services \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(18,413)	(21,414)	(16,989)
NGL and Refined Products Transportation and Services \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(3,490)	(4,243)	(2,972)
Midstream \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(10,406)	(17,101)	(11,316)
Midstream \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(2,911)	(4,114)	(2,620)
Midstream \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(7,495)	(12,987)	(8,696)
Interstate Transportation and Storage \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(2,375)	(2,251)	(1,841)
Interstate Transportation and Storage \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(2,328)	(2,185)	(1,802)
Interstate Transportation and Storage \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(47)	(66)	(39)
Intrastate Transportation and Storage \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(3,962)	(7,818)	(8,571)
Intrastate Transportation and Storage \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(3,222)	(6,954)	(7,307)
Intrastate Transportation and Storage \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	(740)	(864)	(1,264)
Investment in Sunoco LP \| Operating Segments
Revenue from External Customer [Line Items]
Revenues	(23,068)	(25,729)	(17,596)
Investment in Sunoco LP \| Operating Segments \| External Customers [Member]
Revenue from External Customer [Line Items]
Revenues	(23,026)	(25,677)	(17,571)
Investment in Sunoco LP \| Operating Segments \| Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues	$ (42)	$ (52)	$ (25)

Equity Incentive Narrative (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Awards granted	$ 13.78
Unvested awards	39.1	37.7
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	3 years 6 months
Awards granted	10.7
ETE Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	42.9
ET Unit Based Compensation Plans [Member]
Awards granted		$ 11.56	$ 8.46
Fair Value Of Units As Of The Vesting Date	$ 106.0	$ 103.0	$ 52.0
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 279.0
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	$ 37.0	$ 26.0	$ 24.0
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 55.0
ET Cash Restricted Unit Plan [Member]
Unvested awards	6.9
Awards granted	3.2	3.8	3.9
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 3.0

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]
Accounts receivable	$ (171)	$ (863)	$ (3,356)
Accounts receivable from related companies	(5)	23	38
Inventories	35	(361)	(19)
Other current assets	(221)	326	216
Other non-current assets, net	(125)	146	1
Accounts payable	(501)	25	3,834
Accounts payable to related companies	(38)	6	(34)
Accrued and other current liabilities	209	131	238
Other non-current liabilities	(33)	66	117
Derivative assets and liabilities, net	(43)	(349)	(88)
Net change in operating assets and liabilities, net of effects of acquisitions	$ (451)	$ (1,502)	$ 515

Net Income Per Limited Partner Unit

12 Months Ended

Dec. 31, 2023

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,
	2023		2022		2021
Net income	$	5,294	$	5,868	$	6,687
Less: Net income attributable to redeemable noncontrolling interests	60		51		50
Less: Net income attributable to noncontrolling interests	1,299		1,061		1,167
Net income, net of noncontrolling interests	3,935		4,756		5,470
Less: General Partner’s interest in income	3		4		6
Less: Preferred Unitholders’ interest in income	463		422		285
Common Unitholders’ interest in net income	$	3,469	$	4,330	$	5,179
Basic Income per Common Unit:
Weighted average common units	3,161.7		3,086.8		2,734.4
Basic income per common unit	$	1.10	$	1.40	$	1.89

Diluted Income per Common Unit:
Common Unitholders’ interest in net income	$	3,469	$	4,330	$	5,179
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units	(1)		(2)		(2)
Diluted income available to Common Unitholders	$	3,468	$	4,328	$	5,177
Weighted average common units	3,161.7		3,086.8		2,734.4

Dilutive effect of unvested unit awards	15.5		10.2		5.1
Weighted average common units, assuming dilutive effect of unvested unit awards	3,177.2		3,097.0		2,739.5
Diluted income per common unit	$	1.09	$	1.40	$	1.89

Estimates, Significant Accounting Policies and Balance Sheet Detail

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Estimates, Significant Accounting Policies and Balance Sheet Detail

ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Use of Estimates

Regulatory Accounting – Regulatory Assets and Liabilities

Cash, Cash Equivalents and Supplemental Cash Flow Information

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


	Years Ended December 31,
	2023		2022		2021
Accounts receivable	$	(171)	$	(863)	$	(3,356)
Accounts receivable from related companies	(5)		23		38
Inventories	35		(361)		(19)
Other current assets	221		(326)		(216)
Other non-current assets, net	(125)		146		1
Accounts payable	(501)		25		3,834
Accounts payable to related companies	(38)		6		(34)
Accrued and other current liabilities	209		131		238
Other non-current liabilities	(33)		66		117
Derivative assets and liabilities, net	(43)		(349)		(88)
Net change in operating assets and liabilities, net of effects of acquisitions	$	(451)	$	(1,502)	$	515

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


	Years Ended December 31,
	2023		2022		2021
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	$	442	$	575	$	464
Units issued in connection with the Enable acquisition (1)	—		—		3,509
Units issued in connection with the Crestwood acquisition (1)	3,366		—		—
Units issued in connection with the Lotus Midstream acquisition (1)	574		—		—
Lease assets obtained in exchange for new lease liabilities	23		42		18
Acquisition of interest in unconsolidated affiliate	—		—		49






SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	2,298	$	2,167	$	2,188
Cash paid for income taxes (net of refunds)	103		54		41

(1)See Note 3 for additional information.

Accounts Receivable, net

Inventories

The Partnership’s inventories consisted of the following:


	December 31,
	2023		2022
Natural gas, NGLs and refined products	$	1,658	$	1,802
Crude oil	258		246
Spare parts and other	562		413
Total inventories	$	2,478	$	2,461

Other Current Assets

Other current assets consisted of the following:


	December 31,
	2023		2022
Deposits paid to vendors	$	205	$	334
Prepaid expenses and other	308		392
Total other current assets	$	513	$	726

Property, Plant and Equipment, net

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


	December 31,
	2023		2022
Land and improvements	$	1,529	$	1,427
Buildings and improvements (1 to 45 years)	3,848		3,546
Pipelines and equipment (5 to 83 years)	88,195		82,353
Product storage and related facilities (2 to 83 years)	7,978		7,274
Right of way (20 to 83 years)	7,379		6,252
Other (1 to 48 years)	3,688		2,739
Construction work-in-process	2,315		2,405
	114,932		105,996
Less – Accumulated depreciation and depletion	(29,581)		(25,685)
Property, plant and equipment, net	$	85,351	$	80,311

We recognized the following amounts for the periods presented:


	Years Ended December 31,
	2023		2022		2021
Depreciation, depletion and amortization expense	$	3,986	$	3,774	$	3,465
Capitalized interest	77		112		135

Investments in Unconsolidated Affiliates

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,
	2023		2022
Crude pipeline linefill and tank bottoms	$	598	$	489
Regulatory assets	48		55
Pension assets	145		129
Deferred charges	148		140
Restricted funds	121		121
Other	673		624
Total other non-current assets, net	$	1,733	$	1,558

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

Intangible Assets, net

Components and useful lives of intangible assets were as follows:


	December 31, 2023				December 31, 2022
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	9,098	$	(3,196)	$	7,884	$	(2,807)
Patents (10 years)	48		(48)		48		(48)

Trade names (20 years)	66		(44)		66		(41)
Other (5 to 20 years)	12		(11)		12		(13)
Total amortizable intangible assets	9,224		(3,299)		8,010		(2,909)
Non-amortizable intangible assets:
Trademarks	302		—		302		—
Other	12		—		12		—
Total non-amortizable intangible assets	314		—		314		—
Total intangible assets	$	9,538	$	(3,299)	$	8,324	$	(2,909)

Aggregate amortization expense of intangible assets was as follows:


	Years Ended December 31,
	2023		2022		2021
Reported in depreciation, depletion and amortization expense	$	399	$	390	$	352

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


Years Ending December 31:
2024	$	434
2025	423
2026	417
2027	400
2028	397

Goodwill

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

Changes in the carrying amount of goodwill were as follows:


	Intrastate Transportation and Storage		Interstate Transportation and Storage		Midstream		NGL and Refined Products Transportation and Services		Crude Oil Transportation and Services		Investment in Sunoco LP		Investment in USAC		All Other		Total
Balance, December 31, 2021	$	—	$	—	$	—	$	693	$	190	$	1,568	$	—	$	82	$	2,533
Acquired	—		—		—		—		—		33		—		—		33



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

Asset Retirement Obligations

As of December 31, 2023 and 2022, other non-current assets on the Partnership’s consolidated balance sheets included $31 million and $27 million, respectively, of funds that were legally restricted for the purpose of settling AROs.

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:


	December 31,
	2023		2022
Interest payable	$	637	$	559
Customer advances and deposits	240		222
Accrued capital expenditures	442		575
Accrued wages and benefits	406		376
Taxes payable other than income taxes	646		519


Exchanges payable	163		224
Deferred revenue	312		268
Other	675		586
Total accrued and other current liabilities	$	3,521	$	3,329

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

Environmental Remediation

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.

future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2023, no transfers were made between any levels within the fair value hierarchy.


	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 FERC/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	31		20		11
Total assets	$	647	$	622	$	25
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)


	Fair Value Total		Fair Value Measurements at December 31, 2022
			Level 1		Level 2
Assets:
Interest rate derivatives	$	—	$	—	$	—
Commodity derivatives:

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


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


NGLs – Forwards/Swaps	317		317		—
Refined Products – Futures	20		20		—
Crude - Forwards/Swaps	38		38		—
Total commodity derivatives	688		626		62
Other non-current assets	27		18		9
Total assets	$	715	$	644	$	71
Liabilities:
Interest rate derivatives	$	(23)	$	—	$	(23)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(25)		(25)
Swing Swaps IFERC	(12)		(12)		—
Fixed Swaps/Futures	(4)		(4)		—


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


NGLs – Forwards/Swaps	(358)		(358)		—
Refined Products – Futures	(59)		(59)		—
Crude - Forwards/Swaps	(12)		(12)		—

Total commodity derivatives	(526)		(473)		(53)
Total liabilities	$	(549)	$	(473)	$	(76)

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, 2023 was $51.93 billion and $52.39 billion, respectively. As of December 31, 2022, the aggregate fair value and carrying amount of our debt obligations was $45.42 billion and $48.26 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

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

Issuances of Subsidiary Units

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, 2023, 2022 and 2021, the Partnership’s consolidated income statements reflect revenues from related parties of $626 million, $391 million and $410 million, respectively.

Income Taxes

Accounting for Derivative Instruments and Hedging Activities

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

Equity Incentive Compensation

Pensions and Other Postretirement Benefit Plans

Allocation of Income

Equity Tax amounts in components of other comprehensive income (loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Available-for-sale securities	$ (3)	$ 1
Foreign currency translation adjustment	6	6
Actuarial loss relating to pension and other postretirement benefits	0	1
Other Comprehensive Income (Loss), Tax	$ 3	$ 8

- Definition

Amount of tax expense (benefit) allocated to other comprehensive income (loss).

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section 45
-Paragraph 12
-SubTopic 10
-Topic 220
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482790/220-10-45-12

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482765/220-10-50-4

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 830
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481674/830-30-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 830
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481694/830-30-45-17

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 830
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 20
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147481694/830-30-45-20

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(19))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483586/944-220-S99-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482685/740-10-50-10

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 20
-Name Accounting Standards Codification
-Section 45
-Paragraph 11
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482659/740-20-45-11

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(21))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483621/220-10-S99-2

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04(23))
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147483589/942-220-S99-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 20
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org//1943274/2147482659/740-20-45-2

+ Details

Derivative Assets And Liabilities

12 Months Ended

Dec. 31, 2023

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, 2023		December 31, 2022
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	(1,878)	2024-2025	145	2023
Basis Swaps IFERC/NYMEX(1)	(171,185)	2024	(39,563)	2023
Swing Swaps	(900)	2024	—	—
Options – Puts	1,900	2024	—	—
Options - Calls	250	2024	—	—
Power (Megawatt):
Forwards	155,600	2024-2029	—	2023-2029
Futures	(464,897)	2024	(21,384)	2023
Options – Puts	136,000	2024	119,200	2023

Crude (MBbls):
Option - Puts	(15)	2024	—	—
Option - Calls	(20)	2024	—	—
NGL/Refined Products (MBbls):
Option - Puts	121	2024-2026	—	—
Option - Calls	(43)	2024-2026	—	—
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	124,210	2024-2025	42,440	2023-2024
Swing Swaps IFERC	(96,828)	2024-2025	(202,815)	2023-2024
Fixed Swaps/Futures	7,125	2024-2026	(15,758)	2023-2025
Forward Physical Contracts	(1,751)	2024-2026	2,423	2023-2024

NGL (MBbls) – Forwards/Swaps	(13,870)	2024-2027	6,934	2023-2025
Crude (MBbls) – Forwards/Swaps	(2,674)	2024-2025	795	2023-2024
Refined Products (MBbls) – Futures	(4,548)	2024-2025	(3,547)	2023-2024

Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(39,013)	2024	(37,448)	2023
Fixed Swaps/Futures	(39,013)	2024	(37,448)	2023
Hedged Item – Inventory	39,013	2024	37,448	2023

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

Interest Rate Risk

We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding (including USAC’s), none of which were designated as hedges for accounting purposes:

Term

Type

Notional Amount Outstanding

December 31, 2023

December 31, 2022

Energy Transfer

July 2024 (1)

Forward-starting to pay a fixed rate of 3.388% and receive a floating rate based on SOFR

—

400

USAC

December 2025

Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR

700

—

(1)The July 2024 interest rate swaps were terminated and settled in August 2023.

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, 2023		December 31, 2022		December 31, 2023		December 31, 2022
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	51	$	87	$	(6)	$	(7)
	51		87		(6)		(7)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	427		506		(374)		(411)
Commodity derivatives	132		95		(80)		(108)



Interest rate derivatives	6		—		(4)		(23)
	565		601		(458)		(542)
Total derivatives	$	616	$	688	$	(464)	$	(549)

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, 2023		December 31, 2022		December 31, 2023		December 31, 2022
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	6	$	—	$	(4)	$	(23)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	132		95		(80)		(108)
Broker cleared derivative contracts	Other current assets (liabilities)	478		593		(380)		(418)
		616		688		(464)		(549)
Offsetting agreements:

Counterparty netting	Derivative assets (liabilities)	(72)		(85)		72		85
Counterparty netting	Other current assets (liabilities)	(368)		(359)		368		359
Total net derivatives		$	176	$	244	$	(24)	$	(105)

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,
		2023		2022		2021
Derivatives not designated as hedging instruments:

Commodity derivatives – Trading	Cost of products sold	$	7	$	83	$	(6)
Commodity derivatives – Non-trading	Cost of products sold	40		41		(141)

Interest rate derivatives	Gains (losses) on interest rate derivatives	36		293		61

Total		$	83	$	417	$	(86)

Operations And Organization (Narrative) (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Apr. 01, 2021
Incentive Distribution Rights	0.00%
Issued	3,367,525,806	3,094,425,367
Class B Preferred Units [Member] \| Rollup Mergers
Issued			675,625,000
Sunoco LP [Member]
Incentive Distribution Rights	10000.00%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.	28,500,000
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	100.00%

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

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

NON-CASH INVESTING ACTIVITIES: [Abstract]

Cash paid for interest, net of interest capitalized

$ 2,298

$ 2,167

$ 2,188

Cash paid for income taxes (net of refunds)

103

Accrued capital expenditures

442

575

464

Lease assets obtained in exchange for new lease liabilities

Acquisition of interest in unconsolidated affiliate

Enable Acquisition

NON-CASH INVESTING ACTIVITIES: [Abstract]

Units issued in connection with the Enable acquisition (1)

^[1]

3,509

Units issued in connection with the Enable acquisition (1)

^[1]

3,509

Crestwood Acquisition

NON-CASH INVESTING ACTIVITIES: [Abstract]

Units issued in connection with the Enable acquisition (1)

^[1]

3,366

Units issued in connection with the Enable acquisition (1)

^[1]

3,366

Lotus Midstream Acquisition

NON-CASH INVESTING ACTIVITIES: [Abstract]

Units issued in connection with the Enable acquisition (1)

^[1]

574

Units issued in connection with the Enable acquisition (1)

^[1]

$ 574

$ 0

[1]	See Note 3 for additional information.

Equity (Narrative) (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

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

Sep. 30, 2021

Jun. 30, 2021

Mar. 31, 2021

Dec. 31, 2020

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Oct. 27, 2023

Apr. 27, 2022

Dec. 02, 2021

Issuance of Common Units (2)

^[1]

12,900,000

11,900,000

9,700,000

Stock Repurchase Program, Authorized Amount

$ 2,000

Stock Repurchase Program, Remaining Authorized Repurchase Amount

$ 880

Minimum beneficial percentage ownership, other than the Partnership's General Partner and its affiliates, no voting rights, not considered outstanding

20.00%

Limited Partners' Capital Account, Units Outstanding

3,367,525,806

3,094,425,367

3,082,500,000

2,702,400,000

3,367,525,806

3,094,425,367

3,082,500,000

Stock Issued During Period, Value, Dividend Reinvestment Plan

$ 90

Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan

4,500,000

Preferred Units, Issued

113,648,967

72,184,780

113,648,967

72,184,780

Partners' Capital Account, Units, Treasury Units Purchased

4,200,000

Incentive Distribution Rights

0.00%

Issued

3,367,525,806

3,094,425,367

3,367,525,806

3,094,425,367

Series A Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[2]

$ 24.71

$ 24.67

$ 23.89

$ 21.98

$ 31.25

$ 0

$ 31.25

$ 0

$ 31.25

$ 0

^[3]

$ 31.25

$ 0

Units issued for cash

Preferred Stock, Dividend Rate, Percentage

6.25%

Preferred Units, Liquidation Spread, Percent

4.028%

Preferred Stock, Shares Outstanding

950,000

Series A Preferred Units [Member] | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series C Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.6075

0.6489

0.6294

0.4609

Units issued for cash

Preferred Stock, Dividend Rate, Percentage

7.375%

Shares Issued, Price Per Share

$ 25

Preferred Units, Liquidation Spread, Percent

4.53%

Preferred Stock, Shares Outstanding

18,000,000

Series C Preferred Units [Member] | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series D Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.6199

0.6622

0.4766

^[3]

0.4766

Units issued for cash

Preferred Stock, Dividend Rate, Percentage

7.625%

Shares Issued, Price Per Share

$ 25

Preferred Units, Liquidation Spread, Percent

4.738%

Preferred Stock, Shares Outstanding

17,800,000

Series D Preferred Units [Member] | Tenor spread adjustment

Preferred Units, Liquidation Spread, Percent

0.26161%

Series E Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.4750

0.4750

^[3]

0.4750

Units issued for cash

Preferred Stock, Shares Outstanding

32,000,000

Series F Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[2]

$ 0

33.7500

^[3]

33.7500

Units issued for cash

Preferred Stock, Shares Outstanding

500,000

Series G Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[2]

$ 0

35.63

^[3]

35.63

Units issued for cash

Preferred Stock, Shares Outstanding

1,484,780

Series B Preferred Units [Member]

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[2]

$ 33.125

33.125

^[3]

33.125

Units issued for cash

Preferred Stock, Shares Outstanding

550,000

Series H Preferred Units

Distribution Made to Limited Partner, Distributions Paid, Per Unit

^[2]

$ 0

32.50

27.08

^[3]

Units issued for cash

889,000,000

Preferred Stock, Shares Outstanding

900,000

Series I Preferred Units

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.2111

^[3]

$ 0.2111

Units issued for cash

Preferred Stock, Shares Outstanding

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

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.8420

0.8420

0.8255

$ 0.8255

Limited Partners' Capital Account, Units Outstanding

84,400,000

USAC [Member]

Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.

46,100,000

Distribution Made to Limited Partner, Distributions Paid, Per Unit

$ 0.5250

Limited Partners' Capital Account, Units Outstanding

101,000,000

Stock Issued During Period, Shares, Dividend Reinvestment Plan

87,808

124,255

118,399

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

Preferred Units, Liquidation Spread, Percent

4.028%

Series B Preferred Units [Member]

Preferred Stock, Dividend Rate, Percentage

6.625%

Shares Issued, Price Per Share

$ 1,000

Preferred Units, Liquidation Spread, Percent

4.155%

Series E Preferred Units [Member]

Preferred Stock, Dividend Rate, Percentage

7.60%

Shares Issued, Price Per Share

$ 25

Preferred Units, Liquidation Spread, Percent

5.161%

Series F Preferred Units [Member]

Preferred Stock, Dividend Rate, Percentage

6.75%

Shares Issued, Price Per Share

$ 1,000

Preferred Units, Liquidation Spread, Percent

5.134%

Series G Preferred Units [Member]

Preferred Stock, Dividend Rate, Percentage

7.125%

Shares Issued, Price Per Share

$ 1,000

Preferred Units, Liquidation Spread, Percent

5.306%

Series H Preferred Units

Preferred Stock, Dividend Rate, Percentage

6.50%

Shares Issued, Price Per Share

$ 1,000

Preferred Units, Liquidation Spread, Percent

5.694%

Enable | Series G Preferred Units [Member]

Preferred Units, Issued

384,780

ETE Class A Units [Member] | ETE Merger [Member]

Sale of Stock, Number of Shares Issued in Transaction

833,486,004

USAC Issue Tranche 1 | USAC [Member]

Issued

534,308

[1]	Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.
[2]	(1) Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Pursuant to their terms, distributions on the Series A preferred units began to be paid quarterly on February 15, 2023, and distributions on the Series B preferred units will begin to be paid quarterly on February 15, 2028.
[3]	* Represents prorated initial distribution.

Lease Accounting - Remaining term and rate (Details)	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Operating leases	21 years	21 years
Finance leases	12 years	27 years
Operating leases	6.00%	5.00%
Finance leases	5.00%	4.00%

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 5,294	$ 5,868	$ 6,687
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	4,385	4,164	3,817
Deferred Income Tax Expense (Benefit)	203	187	141
Inventory valuation adjustments	114	(5)	(190)
Non-cash compensation expense	130	115	111
Impairment losses and other	12	386	21
(Gains) losses on extinguishments of debt	(2)	0	38
Distributions on unvested awards	68	73	47
Distributions from unconsolidated affiliates	353	232	212
Equity in earnings of unconsolidated affiliates	(383)	(257)	(246)
Other non-cash	32	64	(103)
Net change in operating assets and liabilities, net of effects of acquisitions	(451)	(1,502)	515
Net cash provided by operating activities	9,555	9,051	11,162
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	(111)	(1,141)	(205)
Capital expenditures, excluding allowance for equity funds used during construction	(3,134)	(3,381)	(2,822)
Contributions in aid of construction costs	40	56	43
Contributions to unconsolidated affiliates	(6)	0	(4)
Distributions from unconsolidated affiliates in excess of cumulative earnings	63	62	167
Proceeds from Sale of Equity Method Investments	0	302	0
Proceeds from sales of other assets	38	78	45
Other	3	2	1
Net cash used in investing activities	(4,325)	(4,022)	(2,775)
FINANCING ACTIVITIES:
Proceeds from borrowings	32,130	28,838	21,267
Repayments of debt	(31,416)	(29,681)	(27,318)
Preferred units issued for cash	0	0	889
Distributions to partners	(4,248)	(3,047)	(1,898)
Distributions to noncontrolling interests	(1,691)	(1,547)	(1,487)
Distributions to redeemable noncontrolling interests	59	49	49
Common units repurchased under buyback program	0	0	(31)
Debt issuance costs	(45)	(27)	(14)
Capital contributions from noncontrolling interests	3	405	226
Other, net	0	0	(3)
Net cash used in financing activities	(5,326)	(5,108)	(8,418)
Decrease in cash and cash equivalents	(96)	(79)	(31)
Cash and cash equivalents, beginning of period	257	336	367
Cash and cash equivalents, end of period	161	257	336
Crestwood Acquisition
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	(288)	0	0
Lotus Midstream Acquisition
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	$ (930)	$ 0	$ 0

Derivative Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Asset Derivatives	$ 616	$ 688
Liability Derivatives	(464)	(549)
Designated as Hedging Instrument [Member]
Asset Derivatives	51	87
Liability Derivatives	(6)	(7)
Not Designated as Hedging Instrument [Member]
Asset Derivatives	565	601
Liability Derivatives	(458)	(542)
Broker cleared derivative contracts [Member]
Asset Derivatives	478	593
Liability Derivatives	(380)	(418)
Commodity Derivatives [Member] \| Not Designated as Hedging Instrument [Member]
Asset Derivatives	132	95
Liability Derivatives	(80)	(108)
Commodity Derivatives (Margin Deposits) [Member] \| Designated as Hedging Instrument [Member]
Asset Derivatives	51	87
Liability Derivatives	(6)	(7)
Commodity Derivatives (Margin Deposits) [Member] \| Not Designated as Hedging Instrument [Member]
Asset Derivatives	427	506
Liability Derivatives	(374)	(411)
Interest Rate Derivatives [Member] \| Not Designated as Hedging Instrument [Member]
Asset Derivatives	6	0
Liability Derivatives	$ (4)	$ (23)

Acquisitions and Related Transactions (Tables)

12 Months Ended

Dec. 31, 2023

Enable

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

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


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

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

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

Noncontrolling interests	34

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

Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 13,698	$ 13,093	$ 13,046
Depreciation, depletion and amortization	4,385	4,164	3,817
Interest expense, net of interest capitalized	2,578	2,306	2,267
Impairment losses and other	12	386	21
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments	36	293	61
Non-cash compensation expense	130	115	111
Non-cash compensation expense	3	42	162
(Gains) losses on extinguishments of debt	(2)	0	38
Inventory valuation adjustments	114	(5)	(190)
Impairment of investments in unconsolidated affiliates	691	565	523
Equity in earnings of unconsolidated affiliates	(383)	(257)	(246)
Other, net	(12)	82	57
Income tax expense (benefit) from continuing operations	(303)	(204)	(184)
NET INCOME	5,294	5,868	6,687
Gain (Loss) Related to Litigation Settlement	627	0	0
Intrastate Transportation and Storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	1,111	1,396	3,483
Depreciation, depletion and amortization	214	209	191
Equity in earnings of unconsolidated affiliates	(17)	(17)	(20)
Investment in Sunoco LP
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	964	919	754
Depreciation, depletion and amortization	187	193	177
Investment in USAC
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	512	426	398
Depreciation, depletion and amortization	246	237	239
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	2	177	177
Interstate Transportation and Storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	2,009	1,753	1,515
Depreciation, depletion and amortization	563	513	457
Equity in earnings of unconsolidated affiliates	(260)	(175)	(140)
Midstream
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	2,525	3,210	1,868
Depreciation, depletion and amortization	1,451	1,351	1,190
Equity in earnings of unconsolidated affiliates	(15)	(19)	(24)
NGL and Refined Products Transportation and Services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	3,894	3,025	2,828
Depreciation, depletion and amortization	915	865	778
Equity in earnings of unconsolidated affiliates	(76)	(44)	(51)
Crude Oil Transportation and Services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	2,681	2,187	2,023
Depreciation, depletion and amortization	740	663	588
Equity in earnings of unconsolidated affiliates	$ (11)	$ 2	$ (10)

Acquisitions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition Table) (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
	Dec. 02, 2021	Feb. 28, 2021	Dec. 31, 2023	Dec. 31, 2022
Business Acquisition [Line Items]
Goodwill			$ 1,455	$ 33
Enable
Business Acquisition [Line Items]
Total current assets	$ 593
Property, plant and equipment, net	7,076
Intangible assets, net	440
Goodwill	138
Total consideration	3,519
Total assets acquired	8,326
Total current liabilities	488
Long-term debt, less current maturities	4,267
Other non-current liabilities	18
Total liabilities assumed	4,773
Cash received	61
Noncontrolling interests	34
Other non-current assets	39
Total consideration, net of cash received	3,458	$ 10
Enable \| Enable Five-Year Revolving Credit Facility
Business Acquisition [Line Items]
Line of Credit Facility, Current Borrowing Capacity	35
Enable \| Investments in Unconsolidated Affiliates
Business Acquisition [Line Items]
Investments in unconsolidated affiliates	$ 40
Woodford Express Acquisition
Business Acquisition [Line Items]
Total consideration, net of cash received			$ 485

Derivative Assets And Liabilities (Derivative Amount Of Gain (Loss) Recognized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 83	$ 417	$ (86)
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments	36	293	61
Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 7	83	(6)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Cost of products sold
Non Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 40	$ 41	$ (141)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Cost of products sold

Estimates (Accrued And Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Other Information [Abstract]
Interest payable	$ 637	$ 559
Customer advances and deposits	240	222
Accrued capital expenditures	442	575
Accrued wages and benefits	406	376
Taxes payable other than income taxes	646	519
Exchanges payable	163	224
Deferred Revenue	312	268
Other	675	586
Accrued and other current liabilities	$ 3,521	$ 3,329

Lease Accounting (Notes)

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Lessee, Operating Leases [Text Block]

LEASE ACCOUNTING:

Lessee Accounting

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

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

Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership and lease extensions

are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term.

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

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

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

The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheets as of December 31, 2023 and 2022 were as follows:


	December 31,
	2023		2022
Operating leases:
Lease right-of-use assets, net	$	797	$	808
Operating lease current liabilities	56		45
Accrued and other current liabilities	5		1
Non-current operating lease liabilities	778		798
Finance leases:
Property, plant and equipment, net	$	1	$	1
Lease right-of-use assets, net	29		11

Current maturities of long-term debt	8		2
Long-term debt, less current maturities	19		9
Other non-current liabilities	—		1

The components of lease expense for the years ended December 31, 2023 and 2022 were as follows:


		Year Ended December 31,
	Income Statement Location	2023		2022
Operating lease costs:
Operating lease cost	Cost of goods sold	$	1	$	3
Operating lease cost	Operating expenses	69		63
Operating lease cost	Selling, general and administrative	18		22
Total operating lease costs		88		88
Finance lease costs:
Amortization of lease assets	Depreciation, depletion and amortization	—		—
Interest on lease liabilities	Interest expense, net of capitalized interest	—		—
Total finance lease costs		—		—
Short-term lease cost	Operating expenses	38		33
Variable lease cost	Operating expenses	16		13
Lease costs, gross		142		134
Less: Sublease income	Other revenue	42		40
Lease costs, net		$	100	$	94

The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2023 and 2022 were as follows:


	December 31,
	2023		2022
Weighted-average remaining lease term (years):
Operating leases	21		21
Finance leases	12		27
Weighted-average discount rate (%):
Operating leases	6	%	5	%
Finance leases	5	%	4	%

Cash flows and non-cash activity related to leases for the years ended December 31, 2023 and 2022 were as follows:


	Year Ended December 31,
	2023		2022


Operating cash flows from operating leases	$	(139)	$	(133)



Lease assets obtained in exchange for new finance lease liabilities	18		1
Lease assets obtained in exchange for new operating lease liabilities	5		41

Maturities of lease liabilities as of December 31, 2023 are as follows:


	Operating leases		Finance leases		Total
2024	$	96	$	7	$	103
2025	90		8		98
2026	81		4		85
2027	71		2		73
2028	70		1		71
Thereafter	979		12		991
Total lease payments	1,387		34		1,421
Less: present value discount	553		7		560
Present value of lease liabilities	$	834	$	27	$	861

Lessor Accounting

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

Sunoco LP’s future minimum operating lease payments receivable as of December 31, 2023 are as follows:


	Lease Payments
2024	$	108
2025	99
2026	82
2027	63
2028	38
Thereafter	17
Total undiscounted cash flows	$	407

Estimates (Schedule Of Goodwill) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Goodwill [Roll Forward]
Goodwill	$ 2,566	$ 2,533
Goodwill	1,455	33
Goodwill	4,019	2,566
Goodwill, Other Changes	(2)
Intrastate Transportation and Storage
Goodwill [Roll Forward]
Goodwill	0	0
Goodwill	0	0
Goodwill	0	0
Goodwill, Other Changes	0
Interstate Transportation and Storage
Goodwill [Roll Forward]
Goodwill	0	0
Goodwill	0	0
Goodwill	0	0
Goodwill, Other Changes	0
Midstream
Goodwill [Roll Forward]
Goodwill	0	0
Goodwill	601	0
Goodwill	601	0
Goodwill, Other Changes	0
NGL and Refined Products Transportation and Services
Goodwill [Roll Forward]
Goodwill	693	693
Goodwill	191	0
Goodwill	884	693
Goodwill, Other Changes	0
Crude Oil Transportation and Services
Goodwill [Roll Forward]
Goodwill	190	190
Goodwill	663	0
Goodwill	853	190
Goodwill, Other Changes	0
Investment in Sunoco LP
Goodwill [Roll Forward]
Goodwill	1,601	1,568
Goodwill	0	33
Goodwill	1,599	1,601
Goodwill, Other Changes	(2)
Investment in USAC
Goodwill [Roll Forward]
Goodwill	0	0
Goodwill	0	0
Goodwill	0	0
Goodwill, Other Changes	0
All Other
Goodwill [Roll Forward]
Goodwill	82	82
Goodwill	0	0
Goodwill	82	$ 82
Goodwill, Other Changes	$ 0

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

12 Months Ended

Dec. 31, 2023

Environmental Exit Costs by Cost [Table Text Block]


	December 31,
	2023		2022
Current	$	42	$	54
Non-current	235		228
Total environmental liabilities	$	277	$	282

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,
	2023		2022		2021
ROW expense	$	68	$	64	$	48

Advances to and Investments in Unconsolidated Affiliates Narrative (Details)	Dec. 31, 2023
Citrus [Member]
Interest ownership	50.00%
FGT [Member]
Interest ownership	100.00%
Midcontinent Express Pipeline, LLC [Member]
Interest ownership	50.00%
White Cliffs
Interest ownership	51.00%
Explorer
Interest ownership	15.00%

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

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Debt Instrument [Line Items]

Other Long-term Debt

$ 18

$ 3

Long-term Debt

52,388

48,262

Current maturities of long-term debt

1,008

Long-term debt, less current maturities

51,380

48,260

Five Year Credit Facility

Debt Instrument [Line Items]

Long-term Line of Credit

1,410

Bakken Project [Member]

Debt Instrument [Line Items]

Debt Instrument, Unamortized Discount (Premium), Net

(1)

Deferred Finance Costs, Noncurrent, Net

(4)

(7)

Long-term Debt

1,845

1,842

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

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

3.90% Senior Notes due April 1, 2024

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

Debt Instrument [Line Items]

Senior Notes

$ 850

850

Long-term Debt, Description

4.625% Senior Notes due April 1, 2029

Sunoco LP [Member]

Debt Instrument [Line Items]

Capital Lease Obligations

$ 94

Deferred Finance Costs, Noncurrent, Net

(25)

(23)

Long-term Debt

3,580

3,571

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

Debt Instrument [Line Items]

Senior Notes

$ 600

600

Long-term Debt, Description

6.00% Senior Notes Due April 15, 2027

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

Debt Instrument [Line Items]

Long-term Line of Credit

$ 411

900

Long-term Debt, Description

Sunoco LP Credit Facility due April 7, 2027

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

Debt Instrument [Line Items]

Senior Notes

$ 400

400

Long-term Debt, Description

5.875% Senior Notes Due March 15, 2028

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

Debt Instrument [Line Items]

Senior Notes

$ 800

800

Long-term Debt, Description

4.50% Senior Notes due May 15, 2029

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

Debt Instrument [Line Items]

Senior Notes

$ 800

800

Long-term Debt, Description

4.50% Senior Notes due April 30, 2030

Sunoco LP [Member] | 7.00% Senior Notes Due 2028

Debt Instrument [Line Items]

Senior Notes

$ 500

Long-term Debt, Description

7.00% Senior Notes due September 25, 2028

Transwestern [Member]

Debt Instrument [Line Items]

Long-term Debt

$ 250

250

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

Debt Instrument [Line Items]

Senior Notes

$ 175

175

Long-term Debt, Description

5.66% Senior Notes due December 9, 2024(3)

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

Debt Instrument [Line Items]

Senior Notes

$ 75

Long-term Debt, Description

6.16% Senior Notes due May 24, 2037

USA Compression Partners, LP [Member]

Debt Instrument [Line Items]

Long-term Line of Credit

^[1]

$ 872

646

Deferred Finance Costs, Noncurrent, Net

(11)

(14)

Long-term Debt

$ 2,336

2,107

Long-term Debt, Description

USAC Credit Facility due December 2026(6)

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

Debt Instrument [Line Items]

Senior Notes

$ 725

725

Long-term Debt, Description

6.875% Senior Notes due April 1, 2026

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

Debt Instrument [Line Items]

Senior Notes

$ 750

750

Long-term Debt, Description

6.875% Senior Notes due September 1, 2027

SemGroup [Member]

Debt Instrument [Line Items]

Long-term Debt

$ 0

225

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

Debt Instrument [Line Items]

Senior Notes

^[2]

$ 0

225

Long-term Debt, Description

HFOTCO Tax Exempt Notes due 2050 (5)

ET [Member]

Debt Instrument [Line Items]

Debt Instrument, Unamortized Discount (Premium), Net

$ 128

184

Deferred Finance Costs, Noncurrent, Net

(197)

(181)

Long-term Debt

44,359

40,264

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

Debt Instrument [Line Items]

Senior Notes

^[3],[4]

$ 1,127

1,127

Long-term Debt, Description

5.875% Senior Notes due January 15, 2024(2)(3)

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

Debt Instrument [Line Items]

Senior Notes

$ 956

956

Long-term Debt, Description

5.50% Senior Notes due June 1, 2027

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

Debt Instrument [Line Items]

Senior Notes

^[5]

$ 0

995

Long-term Debt, Description

4.25% Senior Notes due March 15, 2023(1)

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

Debt Instrument [Line Items]

Senior Notes

^[5]

$ 0

277

Long-term Debt, Description

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

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

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

4.05% Senior Notes due March 15, 2025

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

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

4.75% Senior Notes due January 15, 2026

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

Debt Instrument [Line Items]

Senior Notes

$ 267

267

Long-term Debt, Description

8.25% Senior Notes due November 15, 2029

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

Debt Instrument [Line Items]

Senior Notes

$ 500

500

Long-term Debt, Description

4.90% Senior Notes due March 15, 2035

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

Debt Instrument [Line Items]

Senior Notes

$ 400

400

Long-term Debt, Description

6.625% Senior Notes due October 15, 2036

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

Debt Instrument [Line Items]

Senior Notes

$ 500

500

Long-term Debt, Description

5.80% Senior Notes due June 15, 2038

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

Debt Instrument [Line Items]

Senior Notes

$ 550

550

Long-term Debt, Description

7.50% Senior Notes due July 1, 2038

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

Debt Instrument [Line Items]

Senior Notes

$ 700

700

Long-term Debt, Description

6.05% Senior Notes due June 1, 2041

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

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

6.50% Senior Notes due February 1, 2042

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

Debt Instrument [Line Items]

Senior Notes

$ 450

450

Long-term Debt, Description

5.15% Senior Notes due February 1, 2043

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

Debt Instrument [Line Items]

Senior Notes

$ 450

450

Long-term Debt, Description

5.95% Senior Notes due October 1, 2043

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

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

5.15% Senior Notes due March 15, 2045

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

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

6.125% Senior Notes due December 15, 2045

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

Debt Instrument [Line Items]

Senior Notes

$ 900

900

Long-term Debt, Description

5.30% Senior Notes due April 15, 2047

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

Debt Instrument [Line Items]

Senior Notes

$ 1,500

1,500

Long-term Debt, Description

5.40% Senior Notes due October 1, 2047

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

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

6.00% Senior Notes due June 15, 2048

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

Debt Instrument [Line Items]

Senior Notes

$ 1,750

1,750

Long-term Debt, Description

6.25% Senior Notes due April 15, 2049

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

Debt Instrument [Line Items]

Junior Subordinated Notes

$ 600

600

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

Debt Instrument [Line Items]

Subordinated Debt

^[3]

$ 65

Long-term Debt, Description

9.00% Debentures due November 1, 2024(3)

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

Debt Instrument [Line Items]

Senior Notes

^[5]

$ 0

350

Long-term Debt, Description

3.45% Senior Notes due January 15, 2023(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]

$ 500

500

Long-term Debt, Description

4.25% Senior Notes due April 1, 2024(3)

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

Debt Instrument [Line Items]

Senior Notes

^[3]

$ 750

750

Long-term Debt, Description

4.50% Senior Notes due April 15, 2024(3)

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

Debt Instrument [Line Items]

Senior Notes

$ 400

400

Long-term Debt, Description

5.95% Senior Notes due December 1, 2025

ET [Member] | 3.90% Senior Notes due July 15, 2026 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 550

550

Long-term Debt, Description

3.90% Senior Notes due July 15, 2026

ET [Member] | 4.20% Senior Notes due April 2027 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 600

600

Long-term Debt, Description

4.20% Senior Notes due April 15, 2027

ET [Member] | 4.00% Senior Notes due October 1, 2027 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 750

750

Long-term Debt, Description

4.00% Senior Notes due October 1, 2027

ET [Member] | 4.95% Senior Notes due 2028 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

4.95% Senior Notes due June 15, 2028

ET [Member] | 5.25% Senior Notes due 2029 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 1,500

1,500

Long-term Debt, Description

5.25% Senior Notes due April 15, 2029

ET [Member] | Senior Note 6.10%, due February 15, 2042 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 300

300

Long-term Debt, Description

6.10% Senior Notes due February 15, 2042

ET [Member] | 5.30% Senior Notes due April 1, 2044 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 700

700

Long-term Debt, Description

5.30% Senior Notes due April 1, 2044

ET [Member] | 5.35% Senior Notes due May 15, 2045 [Member]

Debt Instrument [Line Items]

Senior Notes

$ 800

800

Long-term Debt, Description

5.35% Senior Notes due May 15, 2045

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

Debt Instrument [Line Items]

Senior Notes

$ 66

Long-term Debt, Description

7.00% Senior Notes due July 15, 2029

ET [Member] | 4.5% Senior Notes due November 1, 2023 [Member]

Debt Instrument [Line Items]

Senior Notes

^[5]

$ 0

600

Long-term Debt, Description

4.50% Senior Notes due November 1, 2023(1)

ET [Member] | 4.9% Senior Notes due February 1, 2024 [Member]

Debt Instrument [Line Items]

Senior Notes

^[3],[4]

$ 350

350

Long-term Debt, Description

4.90% Senior Notes due February 1, 2024(2)(3)

ET [Member] | 3.6% Senior Notes due February 1, 2023 [Member]

Debt Instrument [Line Items]

Senior Notes

^[5]

$ 0

800

Long-term Debt, Description

3.60% Senior Notes due February 1, 2023(1)

ET [Member] | 4.20% Senior Notes due 2023 [Member]

Debt Instrument [Line Items]

Senior Notes

^[5]

$ 0

500

Long-term Debt, Description

4.20% Senior Notes due September 15, 2023(1)

ET [Member] | 2.9% Senior Notes due May 15, 2025

Debt Instrument [Line Items]

Senior Notes

$ 1,000

1,000

Long-term Debt, Description

2.90% Senior Notes due May 15, 2025

ET [Member] | 3.75 Senior Notes due May 15, 2030

Debt Instrument [Line Items]

Senior Notes

$ 1,500

1,500

Long-term Debt, Description

3.75% Senior Note due May 15, 2030

ET [Member] | 5.00% Senior Notes due May 15, 2050

Debt Instrument [Line Items]

Senior Notes

$ 2,000

2,000

Long-term Debt, Description

5.00% Senior Notes due May 15, 2050

ET [Member] | Five Year Credit Facility

Debt Instrument [Line Items]

Long-term Line of Credit

$ 1,412

793

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]

$ 600

600

Long-term Debt, Description

3.90% Senior Notes due May 15, 2024(3)

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] | 4.25% Senior Notes due March 15, 2023

Debt Instrument [Line Items]

Senior Notes

^[5]

$ 0

Long-term Debt, Description

4.25% Senior Notes due March 15, 2023(1)

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

Debt Instrument [Line Items]

Senior Notes

^[3],[4]

$ 23

Long-term Debt, Description

5.875% Senior Notes due January 15, 2024(2)(3)

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

Debt Instrument [Line Items]

Senior Notes

$ 44

Long-term Debt, Description

5.50% Senior Notes due June 1, 2027

ET [Member] | 5.55% Senior Notes due February 15, 2028

Debt Instrument [Line Items]

Senior Notes

$ 1,000

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

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],[4]

$ 82

Long-term Debt, Description

7.60% Senior Notes due February 1, 2024(2)(3)

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

^[6]

$ 500

Long-term Debt, Description

5.75% Senior Notes due April 1, 2025(4)

ET [Member] | 6.05% Senior Notes due December 1, 2026

Debt Instrument [Line Items]

Senior Notes

$ 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

^[6]

$ 600

Long-term Debt, Description

6.05% Senior Notes due May 1, 2027(4)

ET [Member] | 6.10% Senior Notes due December 1, 2028

Debt Instrument [Line Items]

Senior Notes

$ 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

^[6]

$ 700

Long-term Debt, Description

6.00% Senior Notes due February 1, 2029(4)

ET [Member] | 8.0% Senior Notes due April 1, 2029

Debt Instrument [Line Items]

Senior Notes

^[6]

$ 450

Long-term Debt, Description

8.00% Senior Notes due April 1, 2029(4)

ET [Member] | 6.40% Senior Notes due December 1, 2030

Debt Instrument [Line Items]

Senior Notes

$ 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

^[6]

$ 600

Long-term Debt, Description

7.38% Senior Notes due April 1, 2031(4)

ET [Member] | 4.05% Senior Notes due June 1, 2033

Debt Instrument [Line Items]

Senior Notes

^[2]

$ 225

Long-term Debt, Description

4.05% Tax-Exempt Bonds due June 1, 2033(5)

ET [Member] | 6.55% Senior Notes due December 1, 2033

Debt Instrument [Line Items]

Senior Notes

$ 1,500

$ 0

Long-term Debt, Description

6.55% Senior Notes due December 1,2033

[1]	The USAC Credit Facility matures in December 2026, except that if any portion of the 6.875% Senior Notes due 2026 are outstanding on December 31, 2025, the USAC Credit Facility will mature on December 31, 2025.
[2]	In May 2023, the Partnership refinanced all of the $225 million outstanding principal amount of HFOTCO tax-exempt bonds with new 10-year tax-exempt bonds. The new bonds, which were issued through the Harris County Industrial Development Corporation and are obligations of Energy Transfer, accrue interest at a fixed rate of 4.05% and are mandatorily redeemable in 2033. Upon redemption, these tax-exempt bonds may be remarketed on different terms through final maturity of November 1, 2050.
[3]	As of December 31, 2023, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.
[4]	These notes were redeemed subsequent to December 31, 2023
[5]	These notes were redeemed in 2023.
[6]	These notes, totaling $2.85 billion aggregate principal amount, were assumed by the Partnership in connection with the closing of the Crestwood acquisition in November 2023.

Equity Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2023

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,
	2023		2022		2021
Sunoco LP	$	53.37	$	43.54	$	37.72
USAC	23.13		18.31		14.92

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, 2022	37.7	$	9.62

Awards granted	10.7	13.78
Awards vested	(7.7)	9.22
Awards forfeited	(1.6)	9.52
Unvested awards as of December 31, 2023	39.1	$	10.84

Subsidiaries [Member]

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

The following table summarizes the activity of the Subsidiary Unit Awards:


	Sunoco LP			USAC
	Number of Units	Weighted Average Grant-Date Fair Value Per Unit		Number of Units	Weighted Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 2022	1.8	$	34.29	2.1	$	14.21
Awards granted	0.4	53.37		0.5	23.13
Awards vested	(0.6)	28.35		(0.6)	13.29
Awards forfeited	—	34.64		(0.1)	17.50
Unvested awards as of December 31, 2023	1.6	$	41.08	1.9	$	17.08

Lease Accounting - Lessor (Details) $ in Millions	Dec. 31, 2023 USD ($)
Thereafter	$ 979
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year
Sunoco LP [Member]
2024	$ 108
2025	99
2026	82
2027	63
2028	38
Thereafter	17
Total undiscounted cash flows	$ 407
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2024
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2025
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2026
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2027
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year	2028

Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2023
USAC Credit Facility, due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain:•a minimum EBITDA to interest coverage ratio;•a ratio of total secured indebtedness to EBITDA within a specified range; and •a maximum funded debt to EBITDA ratio.
Five Year Credit Facility \| ET [Member]
Debt Instrument [Line Items]
Leverage Ratio Maximum	5.00
Maximum Leverage Ratio Permitted	5.50
Supplementary Leverage Ratio	0.0331
Five Year Credit Facility \| Minimum [Member] \| ET [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.125%
Five Year Credit Facility \| Minimum [Member] \| ET [Member] \| Eurodollar [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.125%
Five Year Credit Facility \| Minimum [Member] \| ET [Member] \| Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.125%
Five Year Credit Facility \| Maximum [Member] \| ET [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%
Five Year Credit Facility \| Maximum [Member] \| ET [Member] \| Eurodollar [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%
Five Year Credit Facility \| Maximum [Member] \| ET [Member] \| Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Sunoco LP Credit Facility
Debt Instrument [Line Items]
Debt Instrument, Covenant Description	Sunoco LP’s Credit Facility requires Sunoco LP to maintain a specified net leverage ratio and interest coverage ratio.

Equity (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 13	$ 9
Foreign currency translation adjustment	(5)	1
Actuarial gain (loss) related to pensions and other postretirement benefits	6	(7)
Investments in unconsolidated affiliates, net	14	13
Total AOCI, net of tax	$ 28	$ 16

Retirement Benefits (Fair Value of Plan Assets) (Details) - USD ($)
$ in Millions

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Estimates (Components Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Gross Carrying Amount	$ 9,538	$ 8,324
Accumulated Amortization	(3,299)	(2,909)
Customer relationships, contracts and agreements (3 to 46 years)
Gross Carrying Amount	9,098	7,884
Accumulated Amortization	(3,196)	(2,807)
Patents (10 years)
Gross Carrying Amount	48	48
Accumulated Amortization	(48)	(48)
Trade names (20 years)
Gross Carrying Amount	66	66
Accumulated Amortization	(44)	(41)
Other (5 to 20 years)
Gross Carrying Amount	12	12
Accumulated Amortization	(11)	(13)
Total Amortizable Intangible Assets [Member]
Gross Carrying Amount	9,224	8,010
Accumulated Amortization	(3,299)	(2,909)
Trademarks [Member]
Gross Carrying Amount	302	302
Accumulated Amortization	0	0
Other
Gross Carrying Amount	12	12
Accumulated Amortization	0	0
Non-amortizable intangible assets [Member]
Gross Carrying Amount	314	314
Accumulated Amortization	$ 0	$ 0

Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) - USD ($) $ in Millions			3 Months Ended	12 Months Ended
	Nov. 03, 2023	Apr. 01, 2022	Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Impairment losses and other				$ 12	$ 386	$ 21
Asset Retirement Obligation			$ 410	410	362
Costs Incurred, Asset Retirement Obligation Incurred				10	4	12
Asset Retirement Obligation, Legally Restricted Assets, Fair Value			31	31	27
Long-term Debt, Fair Value			51,930	51,930	45,420
Goodwill				1,455	33
Goodwill			4,019	4,019	2,566	2,533
Long-term Debt			$ 52,388	52,388	48,262
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net				0
Inventory Write-down				114	5	190
Revenues				78,586	89,876	67,417
Related Party
Revenues				$ 626	391	410
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
Reporting units for which the estimated FV exceeds the carrying value by less than 20%
Goodwill			$ 368	$ 368
Midstream
Goodwill				601	0
Goodwill			601	601	0	0
All Other
Goodwill				0	0
Goodwill			82	82	82	82
Investment in Sunoco LP
Goodwill				0	33
Goodwill			1,599	1,599	1,601	1,568
Retail Marketing [Member]
Excise Taxes Collected				274	285	332
Interstate Transportation and Storage
Goodwill				0	0
Goodwill			0	0	0	0
Investment in USAC
Goodwill				0	0
Goodwill			0	0	0	0
Crude Oil Transportation and Services
Goodwill				663	0
Goodwill			853	853	190	190
Intrastate Transportation and Storage
Goodwill				0	0
Goodwill			0	0	0	0
Sunoco LP [Member]
Goodwill		$ 20
Long-term Debt			3,580	3,580	3,571
Inventory, LIFO Reserve			230	230	116
USAC [Member]
Impairment losses and other				12	$ 1	$ 5
Sunoco LP [Member]
Goodwill				$ 33
Crestwood Acquisition
Goodwill	$ 1,455		$ 1,460