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What changed in Energy Transfer LP's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of Energy Transfer LP's 2023 and 2024 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2024 report.

+731 added−680 removedSource: 10-K (2025-02-14) vs 10-K (2024-02-16)

Top changes in Energy Transfer LP's 2024 10-K

731 paragraphs added · 680 removed · 526 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

158 edited+45 added−39 removed346 unchanged
Biggest changeDuring the moratorium imposed by the Biden administration on the approvals of LNG export authorizations by the DOE, Lake Charles LNG Export intends to continue to engage with existing and prospective LNG offtake customers and potential equity investors in the project. 17 Table of Contents Index to Financial Statements Midstream The following details our assets in the midstream segment: Description of Assets Net Gas Processing Capacity (MMcf/d) South Texas 2,430 Ark-La-Tex 922 North Central Texas 700 Permian Basin 3,428 Midcontinent 2,925 Williston Basin 430 Powder River Basin 345 Eastern 200 The following information describes our principal midstream assets: South Texas: • Our South Texas assets, which include the Southeast Texas System and the Eagle Ford System, are an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and the Eagle Ford Shale.
Biggest changeMidstream The following details our assets in the midstream segment: Description of Assets Net Gas Processing Capacity (MMcf/d) South Texas 2,530 Ark-La-Tex 922 North Central Texas 700 Permian Basin 4,945 Midcontinent 2,865 Williston Basin 400 Powder River Basin 345 Eastern 200 The following information describes our principal midstream assets: South Texas: • Our South Texas assets, which include the Southeast Texas System and the Eagle Ford System, are an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and the Eagle Ford Shale. 18 Table of Contents Index to Financial Statements The assets in our Southeast Texas System include a large natural gas gathering system that covers thirteen counties between Austin and Houston, Texas and connects to the Katy Hub through the ETC Katy Pipeline and is also connected to the Oasis Pipeline.
SESH has interconnections with third party natural gas pipelines and provides access to major Southeast and Northeast markets and 16 Table of Contents Index to Financial Statements transports directly to generating facilities in Mississippi and Alabama and to interconnecting pipelines that supply companies generating electricity for the Florida power market. • Gulf Run Pipeline is a large diameter pipeline that runs from the heart of the Haynesville Shale in East Texas and northern Louisiana to the Carthage and Perryville natural gas hubs and other key markets along the Gulf Coast.
SESH has 16 Table of Contents Index to Financial Statements interconnections with third-party natural gas pipelines and provides access to major Southeast and Northeast markets and transports directly to generating facilities in Mississippi and Alabama and to interconnecting pipelines that supply companies generating electricity for the Florida power market. • Gulf Run Pipeline is a large diameter pipeline that runs from the heart of the Haynesville Shale in East Texas and northern Louisiana to the Carthage and Perryville natural gas hubs and other key markets along the Gulf Coast.
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”). Liquefaction Project Lake Charles LNG Export, our wholly owned subsidiary, is developing a natural gas liquefaction project at the site of our Lake Charles LNG import terminal and regasification facility.
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”). Lake Charles LNG Export, our wholly owned subsidiary, is developing a natural gas liquefaction project at the site of our Lake Charles LNG import terminal and regasification facility.
This facility has five deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels, and seven barge docks that can accommodate 23 barges simultaneously, three inbound crude oil pipelines, two outbound crude oil pipelines connecting to three refineries, and numerous rail and truck loading spots. 27 Table of Contents Index to Financial Statements • Cushing, OK.
This facility has five deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels, and seven barge docks that can accommodate 23 barges simultaneously, three inbound 27 Table of Contents Index to Financial Statements crude oil pipelines, two outbound crude oil pipelines connecting to three refineries, and numerous rail and truck loading spots. • Cushing, OK.
Lake Charles LNG Export applied for an extension of the deadline to commence exports under the Non-FTA Authorization to December 2025 and the DOE approved such extension request in October 2020.
Lake Charles LNG Export applied for an extension of the deadline to commence exports under the Non-FTA Authorization to December 2025 and the DOE approved such extension request in October 2020.
Lake Charles LNG Export applied for a second extension of the deadline to commence exports and in April 2023 the DOE denied this request in connection with a new DOE policy related to extension requests.
Lake Charles LNG Export applied for a second extension of the deadline to commence exports and in April 2023 the DOE denied this request in connection with a new DOE policy related to extension requests.
In light of this new policy, in August 2023, Lake Charles LNG Export applied for a new Non-FTA Authorization which, if approved, would provide for a new deadline to commence exports to Non-FTA countries, which deadline would be seven years from the date of such approval.
In light of this new policy, in August 2023, Lake Charles LNG Export applied for a new Non-FTA Authorization which, if approved, would provide for a new deadline to commence exports to Non-FTA countries, which deadline would be seven years from the date of such approval.
In January 2024, the Biden administration announced a moratorium on the approval of LNG export authorizations by the DOE and instructed the DOE to conduct studies related to the cumulative impact of LNG exports on domestic natural gas prices, climate change and other matters.
In January 2024, the Biden Administration announced a moratorium on the approval of LNG export authorizations by the DOE and instructed the DOE to conduct studies related to the cumulative impact of LNG exports on domestic natural gas prices, climate change and other matters.
To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to prevent, minimize or remediate contamination of the environment.
Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to prevent, minimize or remediate contamination of the environment.
In Oklahoma, we operate Oklahoma Intrastate Transmission, which delivers natural gas from various shale plays in the Anadarko and Arkoma basins, as further described in “Asset Overview.” We also own a 70% interest in Red Bluff Express Pipeline, which owns a pipeline in the Delaware Basin, and 16% membership interests in Comanche Trail Pipeline and Trans-Pecos Pipeline, which own pipelines delivering natural gas from the Waha Hub to the United States/Mexico border.
In Oklahoma, we operate Enable Oklahoma Intrastate Transmission, which delivers natural gas from various shale plays in the Anadarko and Arkoma basins, as further described in “Asset Overview.” We also own a 70% interest in Red Bluff Express Pipeline, which owns a pipeline in the Delaware Basin, and 16% membership interests in Comanche Trail Pipeline and Trans-Pecos Pipeline, which own pipelines delivering natural gas from the Waha Hub to the United States/Mexico border.
Interstate Transportation and Storage The following details our pipelines in the interstate transportation and storage segment: Description of Assets Ownership Interest Miles of Natural Gas Pipeline Pipeline Throughput Capacity (Bcf/d) Working Storage Capacity (Bcf) Florida Gas Transmission (“FGT”) 50 % 5,380 4.0 — Transwestern Pipeline 100 % 2,590 2.1 — Panhandle Eastern Pipe Line (1) 100 % 6,300 2.8 73.0 Trunkline 100 % 2,190 0.9 13.0 Tiger 100 % 200 2.4 — Fayetteville Express Pipeline 50 % 185 2.0 — Sea Robin Pipeline 100 % 765 2.0 — Stingray Pipeline 100 % 335 0.4 — Rover Pipeline 32.6 % 720 3.4 — Midcontinent Express Pipeline 50 % 510 1.8 — 15 Table of Contents Index to Financial Statements Enable Gas Transmission (“EGT”) 100 % 5,700 4.8 29.3 Mississippi River Transmission (“MRT”) 100 % 1,675 1.7 48.9 Southeast Supply Header (“SESH”) 50 % 290 1.1 — Gulf Run Pipeline 100 % 335 3.0 — (1) Storage capacity figure includes storage leased from Southwest Gas and third-party companies.
Interstate Transportation and Storage The following details our pipelines in the interstate transportation and storage segment: Description of Assets Ownership Interest Miles of Natural Gas Pipeline Pipeline Throughput Capacity (Bcf/d) Working Storage Capacity (Bcf) Florida Gas Transmission (“FGT”) 50 % 5,380 4.1 — Transwestern Pipeline 100 % 2,590 2.1 — Panhandle Eastern Pipe Line (1) 100 % 6,300 2.8 57.0 Trunkline 100 % 2,190 0.9 13.0 Tiger 100 % 200 2.4 — Fayetteville Express Pipeline 50 % 185 2.0 — Sea Robin Pipeline 100 % 765 2.0 — Stingray Pipeline 100 % 335 0.4 — Rover Pipeline 32.6 % 720 3.4 — 15 Table of Contents Index to Financial Statements Midcontinent Express Pipeline 50 % 510 1.8 — Enable Gas Transmission (“EGT”) 100 % 5,700 4.8 29.3 Mississippi River Transmission (“MRT”) 100 % 1,675 1.7 48.9 Southeast Supply Header (“SESH”) 50 % 290 1.1 — Gulf Run Pipeline 100 % 335 3.0 — (1) Storage capacity figure includes storage leased from Southwest Gas and third-party companies.
Fayetteville Express Pipeline is owned by a 50/50 joint venture with Kinder Morgan, Inc. • Sea Robin Pipeline’s system consists of two offshore Louisiana natural gas supply pipelines extending 120 miles into the Gulf of Mexico. • Stingray Pipeline is an interstate natural gas pipeline system with assets located in the western Gulf of Mexico and Johnson Bayou, Louisiana. • Rover Pipeline is a large diameter pipeline which transports natural gas from processing plants in West Virginia, eastern Ohio and western Pennsylvania for delivery to other pipeline interconnects in Ohio and Michigan, where the gas is delivered for distribution to markets across the United States and to Ontario, Canada. • Midcontinent Express Pipeline originates near Bennington, Oklahoma and traverses northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline system in Butler, Alabama.
Fayetteville Express Pipeline is owned by a 50/50 joint venture with Kinder Morgan, Inc. • Sea Robin Pipeline’s system consists of two offshore Louisiana natural gas supply pipelines extending 120 miles into the Gulf of America. • Stingray Pipeline is an interstate natural gas pipeline system with assets located in the western Gulf of America and Johnson Bayou, Louisiana. • Rover Pipeline is a large diameter pipeline which transports natural gas from processing plants in West Virginia, eastern Ohio and western Pennsylvania for delivery to other pipeline interconnects in Ohio and Michigan, where the gas is delivered for distribution to markets across the United States and to Ontario, Canada. • Midcontinent Express Pipeline originates near Bennington, Oklahoma and traverses northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline system in Butler, Alabama.
Our midstream segment focuses on the gathering, compression, treating, blending and processing of natural gas, and our operations are currently concentrated in major producing basins and shales in Texas, New Mexico, West Virginia, Pennsylvania, Ohio, Oklahoma, Arkansas, Kansas, Louisiana, Montana, North Dakota and Wyoming.
Our midstream segment focuses on the gathering, compression, treating, blending and processing of natural gas, and our operations are currently concentrated in major producing basins and shales in Texas, New Mexico, West Virginia, Pennsylvania, Ohio, Oklahoma, Arkansas, Kansas, Louisiana, North Dakota and Wyoming.
Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. Clean Water Act.
However, compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. Clean Water Act.
On behalf of ORS, we operate its Ohio Utica River System, which consists of 47 miles of 36-inch, 13 miles of 30-inch and 3 miles of 24-inch gathering trunklines, and which delivers up to 3.6 Bcf/d to Rockies Express Pipeline, Texas Eastern Transmission, Leach Xpress, Rover and DEO TPL-18. 20 Table of Contents Index to Financial Statements NGL and Refined Products Transportation and Services The following details the assets in our NGL and refined products transportation and services segment: Description of Assets Miles of Liquids Pipeline NGL Fractionation / Processing Capacity (MBbls/d) Working Storage Capacity (MBbls) Liquids Pipelines: Gulf Coast NGL Express 900 — — West Texas Gateway 510 — — Other Permian Basin NGL 1,600 — — Mariner East 680 — — Mariner West 450 — — Mont Belvieu to Nederland 270 — — White Cliffs (1) 540 — — Other NGL 750 — — Liquids Fractionation and Storage Facilities: Mont Belvieu NGL Complex — 1,150 60,000 Spindletop — — 8,000 Crestwood — — 10,000 ET Geismar Olefins (2) — 35 — Hattiesburg — — 5,200 Cedar Bayou — — 1,600 21 Table of Contents Index to Financial Statements NGL Terminals: Nederland — — 1,900 Orbit Gulf Coast — — 1,200 Marcus Hook — — 6,000 Inkster — — 860 Refined Products Pipelines: Eastern region 1,580 — — Midcontinent region 480 — — Southwest region 590 — — Inland 610 — — J.C.
On behalf of ORS, we operate its Ohio Utica River System, which consists of 47 miles of 36-inch, 13 miles of 30-inch and 3 miles of 24-inch gathering trunklines, and which delivers up to 3.6 Bcf/d to Rockies Express Pipeline, Texas Eastern Transmission, Leach Xpress, Rover and DEO TPL-18. 20 Table of Contents Index to Financial Statements NGL and Refined Products Transportation and Services The following details the assets in our NGL and refined products transportation and services segment: Description of Assets Miles of Liquids Pipeline NGL Fractionation / Processing Capacity (MBbls/d) Working Storage Capacity (MBbls) Liquids Pipelines: Gulf Coast NGL Express 900 — — West Texas Gateway 510 — — Other Permian Basin NGL 1,600 — — Mariner East 680 — — Mariner West 450 — — Mont Belvieu to Nederland 270 — — White Cliffs (1) 540 — — Other NGL 750 — — Liquids Fractionation and Storage Facilities: Mont Belvieu NGL Complex — 1,150 62,000 Spindletop — — 8,000 Crestwood assets — — 10,000 ET Geismar Olefins (2) — 35 — Hattiesburg — — 5,200 Cedar Bayou — — 1,600 21 Table of Contents Index to Financial Statements NGL Terminals: Nederland — — 3,100 Marcus Hook — — 6,000 Inkster — — 860 Refined Products Pipelines: Eastern region 1,580 — — Midcontinent region 480 — — Southwest region 590 — — Inland 610 — — J.C.
The ETC Katy Pipeline expansions include the 36-inch East Texas extension to connect our Reed compressor station in Freestone County to our Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub and the 42-inch Southeast Bossier pipeline connecting our Cleburne to Carthage pipeline to the HPL System. • RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. • OIT is a 2,200-mile pipeline system that provides natural gas transportation and storage services to customers in Oklahoma.
The ETC Katy Pipeline expansions include the 36-inch East Texas extension to connect our Reed compressor station in Freestone County to our Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub and the 42-inch Southeast Bossier pipeline connecting our Cleburne to Carthage pipeline to the HPL System. • RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. • EOIT is a 2,200-mile pipeline system that provides natural gas transportation and storage services to customers in Oklahoma.
OIT also has two underground natural gas storage facilities in Oklahoma, which operate at a combined capacity of 24 Bcf with a peak withdrawal rate of 0.60 Bcf/d. 14 Table of Contents Index to Financial Statements • Comanche Trail Pipeline is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico border near San Elizario, Texas.
EOIT also has two underground natural gas storage facilities in Oklahoma, which operate at a combined capacity of 24 Bcf with a peak withdrawal rate of 0.60 Bcf/d. 14 Table of Contents Index to Financial Statements • Comanche Trail Pipeline is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico border near San Elizario, Texas.
Some examples of our teams’ efforts include: • in our natural gas compression business, the use of our proprietary dual-drive technology, which offers the ability to switch compression drivers between an electric motor and a natural gas engine, allowed us to reduce our emissions of nitrogen oxide, carbon monoxide, CO2 and VOCs; • the installation of approximately 12,000 low-emission pneumatic devices throughout our pipeline systems has allowed us to safely and efficiently adjust and control our operations and reduce methane emissions; • the voluntary installation of thermal oxidizers, which destroy VOCs and convert methane to CO2 (a less carbon-intense GHG), thereby reducing VOC and methane emissions by 98% or more at many of our more than 50 natural gas processing and sweetening plants; • the implementation of an innovative liquids management process throughout much of our natural gas gathering pipeline system has allowed us to minimize flash emissions and methane emissions; • the use of optical gas imaging cameras at our more than 2,200 gas gathering and processing facilities as part of our leak detection and repair program allow us to reduce emissions, improve safety, reduce costs, prevent product loss, and maintain equipment integrity; • the use of in-line inspection tools, or smart pigs, allow us to detect corrosion, cracks or other defects along our pipeline systems thereby protecting the environment and the safety of our communities, employees and landowners; and 43 Table of Contents Index to Financial Statements • the use of other methods, including pipeline blowdown direct injection, liquids pipeline system optimization, crude oil truck unloading and direct injection, all of which help to reduce emissions and the release of methane into the atmosphere across our operations.
Some examples of our teams’ efforts include: • in our natural gas compression business, the use of our proprietary dual-drive technology, which offers the ability to switch compression drivers between an electric motor and a natural gas engine, allowed us to reduce our emissions of nitrogen oxide, carbon monoxide, CO2 and VOCs; • the installation of approximately 12,000 low-emission pneumatic devices throughout our pipeline systems has allowed us to safely and efficiently adjust and control our operations and reduce methane emissions; • the voluntary installation of thermal oxidizers, which destroy VOCs and convert methane to CO2 (a less carbon-intense GHG), thereby reducing VOC and methane emissions by 98% or more at many of our more than 50 natural gas processing and sweetening plants; • the implementation of an innovative liquids management process throughout much of our natural gas gathering pipeline system has allowed us to minimize flash emissions and methane emissions; • the use of optical gas imaging cameras at our more than 2,200 gas gathering and processing facilities as part of our leak detection and repair program allow us to reduce emissions, improve safety, reduce costs, prevent product loss, and maintain equipment integrity; • the use of in-line inspection tools, or smart pigs, allow us to detect corrosion, cracks or other defects along our pipeline systems thereby protecting the environment and the safety of our communities, employees and landowners; and • the use of other methods, including pipeline blowdown direct injection, liquids pipeline system optimization, crude oil truck unloading and direct injection, all of which help to reduce emissions and the release of methane into the atmosphere across our operations.
The map below and the maps included within the segment asset descriptions include certain non-wholly owned joint ventures and exclude corporate and field offices and certain assets that are less significant to the Partnership on a consolidated basis. 12 Table of Contents Index to Financial Statements Intrastate Transportation and Storage The following details our pipelines and storage facilities in the intrastate transportation and storage segment: Description of Assets Ownership Interest Miles of Natural Gas Pipeline Pipeline Throughput Capacity (Bcf/d) Working Storage Capacity (Bcf) ET Fuel System (1) 100 % 3,150 5.2 11.2 Oasis Pipeline (1) 100 % 750 2.0 — Houston Pipeline (“HPL”) System 100 % 3,920 5.3 52.5 ETC Katy Pipeline 100 % 460 2.9 — Regency Intrastate Gas System (“RIGS”) 100 % 450 2.1 — Oklahoma Intrastate Transmission (“OIT”) (1) 100 % 2,200 2.4 24.0 Comanche Trail Pipeline 16 % 195 1.1 — Trans-Pecos Pipeline 16 % 140 1.4 — Red Bluff Express Pipeline 70 % 120 1.4 — (1) Includes bi-directional capabilities 13 Table of Contents Index to Financial Statements The following information describes our principal intrastate transportation and storage assets: • The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipelines and related natural gas storage facilities.
The map below and the maps included within the segment asset descriptions include certain non-wholly owned joint ventures and exclude corporate and field offices and certain assets that are less significant to the Partnership on a consolidated basis. 12 Table of Contents Index to Financial Statements Intrastate Transportation and Storage The following details our pipelines and storage facilities in the intrastate transportation and storage segment: Description of Assets Ownership Interest Miles of Natural Gas Pipeline Pipeline Throughput Capacity (Bcf/d) Working Storage Capacity (Bcf) ET Fuel System (1) 100 % 3,270 5.2 11.2 Oasis Pipeline (1) 100 % 750 2.0 — Houston Pipeline (“HPL”) System 100 % 3,920 5.3 52.5 ETC Katy Pipeline 100 % 460 2.9 — Regency Intrastate Gas System (“RIGS”) 100 % 450 2.1 — Enable Oklahoma Intrastate Transmission (“EOIT”) (1) 100 % 2,200 2.4 24.0 Comanche Trail Pipeline 16 % 195 1.1 — Trans-Pecos Pipeline 16 % 140 1.4 — Red Bluff Express Pipeline 70 % 120 1.4 — (1) Includes bi-directional capabilities 13 Table of Contents Index to Financial Statements The following information describes our principal intrastate transportation and storage assets: • The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipelines and related natural gas storage facilities.
The following information describes our principal NGL and refined products transportation and services assets: • Gulf Coast NGL Express is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipelines, with throughput capacity of approximately 900 MBbls/d, that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale and from East Texas to our Mont Belvieu NGL Complex. • West Texas Gateway transports mixed NGLs produced in the Permian Basin and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput capacity of approximately 240 MBbls/d. • The Mariner East Pipeline System, consisting of Mariner East 2 and Mariner East 2x, has an aggregate capacity of 350 to 375 MBbls/d and transports NGLs from the Marcellus and Utica shales in western Pennsylvania, West Virginia and eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Terminal on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. • The Mariner West Pipeline provides transportation of ethane from the Marcellus Shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border and has a throughput capacity of approximately 50 MBbls/d. • The Mont Belvieu to Nederland Pipeline System consists of four pipelines, which deliver export-grade propane, butane, ethane and natural gasoline from our Mont Belvieu NGL Complex to our Nederland Terminal, having a total throughput capacity of approximately 730 MBbls/d.
The following information describes our principal NGL and refined products transportation and services assets: • Gulf Coast NGL Express (formerly known as Lone Star Express) is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipelines, with throughput capacity of approximately 900 MBbls/d, that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale and from East Texas to our Mont Belvieu NGL Complex. • West Texas Gateway transports mixed NGLs produced in the Permian Basin and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput capacity of approximately 240 MBbls/d. • The Mariner East Pipeline System, consisting of Mariner East 2 and Mariner East 2x, has an aggregate capacity of 350 to 375 MBbls/d and transports NGLs from the Marcellus and Utica shales in western Pennsylvania, West Virginia and eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Terminal on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. • The Mariner West Pipeline provides transportation of ethane from the Marcellus Shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border and has a throughput capacity of approximately 50 MBbls/d. • The Mont Belvieu to Nederland Pipeline System consists of four pipelines, which deliver export-grade propane, butane, ethane and natural gasoline from our Mont Belvieu NGL Complex to our Nederland Terminal, having a total throughput capacity of approximately 730 MBbls/d.
Our operations may be impacted to the extent these tribal governments are found to have and choose to act upon such jurisdiction over lands where we operate. For example, in 2020, the Supreme Court ruled in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished.
Our operations may be impacted to the extent these tribal governments are found to have and choose to act upon such jurisdiction over lands where we operate. For example, in 2020, the U.S. Supreme Court ruled in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished.
The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Beaumont and other cities located along the Gulf Coast of Texas.
The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of America, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Beaumont and other cities located along the Gulf Coast of Texas.
During the year ended December 31, 2023, none of our customers individually accounted for more than 10% of our consolidated revenues. Regulation Regulation of Interstate Natural Gas Pipelines. The FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the NGA, the FERC generally regulates the transportation of natural gas in interstate commerce.
During the year ended December 31, 2024, none of our customers individually accounted for more than 10% of our consolidated revenues. Regulation Regulation of Interstate Natural Gas Pipelines. The FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the NGA, the FERC generally regulates the transportation of natural gas in interstate commerce.
In addition to providing storage capacity, our NGL terminalling services also support our liquids blending activities, including the use of our patented butane blending technology. Refined products operations provide transportation and terminalling services through the use of approximately 3,760 miles of refined products pipelines and 37 active refined products marketing terminals.
In addition to providing storage capacity, our NGL terminalling services also support our liquids blending activities, including the use of our patented butane blending technology. Refined products operations provide transportation and terminalling services through the use of approximately 3,760 miles of refined products pipelines and 35 active refined products marketing terminals.
Our crude oil terminalling services operate with an aggregate storage capacity of approximately 65 MMBbls, including approximately 30 MMBbls at our Gulf Coast terminal in Nederland, Texas, approximately 18.2 MMBbls at our Gulf Coast terminal on the Houston Ship Channel and approximately 9.5 MMBbls at our Cushing Terminal in Cushing, Oklahoma, among others.
Our crude oil terminalling services operate with an aggregate storage capacity of approximately 73 MMBbls, including approximately 30 MMBbls at our Gulf Coast terminal in Nederland, Texas, approximately 18.2 MMBbls at our Gulf Coast terminal on the Houston Ship Channel and approximately 9.5 MMBbls at our Cushing Terminal in Cushing, Oklahoma, among others.
Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval.
Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected that are determined to be in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval.
OIT delivers natural gas from the Anadarko and Arkoma basins, including the SCOOP, STACK, Cana Woodford, Granite Wash, Cleveland, Tonkawa and Mississippi Lime Shale plays in western Oklahoma to utilities and industrial end-users connected to OIT and to interstate and intrastate pipelines interconnected with OIT.
EOIT delivers natural gas from the Anadarko and Arkoma basins, including the SCOOP, STACK, Cana Woodford, Granite Wash, Cleveland, Tonkawa and Mississippi Lime Shale plays in western Oklahoma to utilities and industrial end-users connected to EOIT and to interstate and intrastate pipelines interconnected with EOIT.
The primary activities in which we are engaged, which are located in the United States, are as follows: • natural gas operations, including the following: • natural gas midstream and intrastate transportation and storage; • interstate natural gas transportation and storage; and • crude oil, NGL and refined products transportation, terminalling and acquisition and marketing activities as well as NGL storage and fractionation services.
The primary activities in which we are engaged, which are located in the United States, are as follows: • natural gas operations, including the following: ◦ natural gas midstream and intrastate transportation and storage; ◦ interstate natural gas transportation and storage; and • crude oil, NGL and refined products transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services and LNG regasification.
The amount of cash that our subsidiaries distribute to us is based on earnings from their respective business activities and the amount of available cash. Energy Transfer’s primary cash requirements are for distributions to its partners, general and administrative expenses and debt service requirements.
The amount of cash that our subsidiaries distribute to us is based on earnings from their respective business activities and the amount of available cash. Energy Transfer’s primary cash requirements are for distributions to its partners, capital expenditures, general and administrative expenses and debt service requirements.
These processing facilities have an aggregate capacity of 430 MMcf/d. The Arrow and Rough Rider systems are in the core of the Bakken Shale primarily in McKenzie and Dunn Counties, North Dakota, with the Arrow system primarily located on the Fort Berthold Indian Reservation.
These processing facilities have an aggregate capacity of 400 MMcf/d. The Arrow and Rough Rider systems are in the core of the Bakken Shale primarily in McKenzie and Dunn Counties, North Dakota, with the Arrow system primarily located on the Fort Berthold Indian Reservation.
The project will benefit from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. During 2022, Lake Charles LNG Export executed six LNG off-take agreements, for an aggregate of nearly 8 million tonnes per annum, including a 20-year LNG agreement with Shell NA LNG LLC.
The project will benefit from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. During 2022, Lake Charles LNG Export executed six LNG offtake agreements, for an aggregate of nearly 8 million tonnes per annum, including a 20-year LNG agreement with Shell NA LNG LLC.
Midstream Segment The midstream industry consists of natural gas gathering, compression, treating, processing, storage and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells and the proximity of storage facilities to production areas and end-use markets.
Midstream Segment The midstream industry consists of natural gas gathering, compression, treating, dehydration and processing, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells and the proximity of storage facilities to production areas and end-use markets.
In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties.
In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required 39 Table of Contents Index to Financial Statements remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties.
We expect our subsidiaries to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, Energy Transfer may issue debt or equity securities from time to time as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes. 6 Table of Contents Index to Financial Statements The following chart summarizes our organizational structure as of February 9, 2024.
We expect our subsidiaries to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, Energy Transfer may issue debt or equity securities from time to time as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes. 6 Table of Contents Index to Financial Statements The following chart summarizes our organizational structure as of February 7, 2025.
Panhandle contracts for over 73 Bcf of natural gas storage. • Trunkline’s transmission system consists of one large diameter mainline pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan.
Panhandle contracts for approximately 56 Bcf of natural gas storage. • Trunkline’s transmission system consists of one large diameter mainline pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan.
Interstate Transportation and Storage Segment Interstate natural gas transportation pipelines receive natural gas from supply sources including other transportation pipelines, storage facilities and gathering systems, and deliver the natural gas to industrial end-users and other pipelines.
Interstate Transportation and St orage Segment Interstate natural gas transportation pipelines receive natural gas from supply sources including other transportation pipelines, storage facilities and gathering systems, and deliver the natural gas to industrial end-users and other pipelines.
In July 2016, Lake Charles LNG Export also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”) subject to commencement of exports no later than December 2020.
In July 2016, Lake Charles LNG Export also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas subject to commencement of exports no later than December 2020.
The percentage of electrical energy we purchase on a given day originating from solar and wind sources is approaching 20%. Since 2019, we have entered into dedicated solar contracts to purchase 148 megawatts of solar power to support the operations of our assets. We also operate approximately 18,000 solar panel-powered metering stations across the United States.
The percentage of electrical energy we purchase on a given day originating from solar and wind sources is approaching 20%. Since 2019, we have entered into dedicated solar contracts to purchase 148 megawatts of solar power to support the operations of our assets. We also operate approximately 37,100 solar panel-powered metering stations across the United States.
The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack. • The Eastern region refined products pipelines consist of 6-inch to 16-inch diameter refined product pipelines in eastern, central and north central Pennsylvania, 8-inch refined products pipeline in western New York and various diameter refined products pipelines in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline). • The Midcontinent region refined products pipelines primarily consist of 3-inch to 12-inch refined products pipelines in Ohio and 6-inch and 8-inch refined products pipeline in Michigan. • The Southwest region refined products pipelines are located in East Texas and consist primarily of 8-inch and 12-inch diameter refined products pipeline. • The Inland refined products pipeline consists of 12-, 10-, 8- and 6-inch diameter pipelines in the western, northwestern, and northeastern regions of Ohio. • The J.C.
The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack. • The Eastern region refined products pipelines consist of 6-inch to 16-inch diameter refined product pipelines in eastern, central and north central Pennsylvania, 8-inch refined products pipeline in western New York and various diameter refined products pipelines in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline). • The Midcontinent region refined products pipelines primarily consist of 3-inch to 12-inch refined products pipelines in Ohio and 6-inch and 8-inch refined products pipeline in Michigan. • The Southwest region refined products pipelines are located in East Texas and consist primarily of 8-inch and 12-inch diameter refined products pipeline. 23 Table of Contents Index to Financial Statements • The Inland refined products pipeline consists of 12-, 10-, 8- and 6-inch diameter pipelines in the western, northwestern, and northeastern regions of Ohio. • The J.C.
We are committed to operating our business in a manner that honors and respects all people and the communities in which we do business.
Ethics and Values . We are committed to operating our business in a manner that honors and respects all people and the communities in which we do business.
These laws and regulations require environmental assessment and remediation efforts at many of ETC Sunoco’s facilities and at formerly owned or third-party sites. Accruals for these environmental remediation activities amounted to $213 million and $219 million at December 31, 2023 and 2022, respectively, which is included in the total accruals above.
These laws and regulations require environmental assessment and remediation efforts at many of ETC Sunoco’s facilities and at formerly owned or third-party sites. Accruals for these environmental remediation activities amounted to $197 million and $213 million at December 31, 2024 and 2023, respectively, which is included in the total accruals above.
The following details our assets in the crude oil transportation and services segment: Crude Oil Pipelines Our crude oil pipelines (through wholly owned subsidiaries or joint venture interests) consist of approximately 14,500 miles of crude oil trunk pipelines as well as crude oil and produced water gathering pipelines throughout the Southwest, Midcontinent and Midwest United States.
The following details our assets in the crude oil transportation and services segment: Crude Oil Pipelines Our crude oil pipelines (through wholly owned subsidiaries or joint venture interests) consist of approximately 17,950 miles of crude oil trunk pipelines as well as crude oil and produced water gathering pipelines throughout the Southwest, Midcontinent and Midwest United States.
As of December 31, 2023, we owned or controlled approximately 730 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities.
As of December 31, 2024, we owned or controlled approximately 729 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities.
As of December 31, 2023, the captive insurance company held $140 million of cash and investments. The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable.
As of December 31, 2024, the captive insurance company held $122 million of cash and investments. The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable.
Additionally, the EPA has adopted rules under authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration 41 Table of Contents Index to Financial Statements (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions.
Additionally, the EPA has adopted rules under authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions.
To the extent that these actions are pursued by PHMSA, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current PSM and RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.
To the extent that these actions are pursued by PHMSA, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current PSM and RMP requirements, 37 Table of Contents Index to Financial Statements which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.
Through our midstream segment, we own and operate (through wholly owned subsidiaries or joint venture interests) natural gas gathering pipelines, natural gas processing plants, natural gas treating facilities and natural gas conditioning facilities with an aggregate processing capacity of approximately 11.4 Bcf/d.
Through our midstream segment, we own and operate (through wholly owned subsidiaries or joint venture interests) natural gas gathering pipelines, natural gas processing plants, natural gas treating facilities and natural gas conditioning facilities with an aggregate processing capacity of approximately 12.9 Bcf/d.
The rule imposes safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for 36 Table of Contents Index to Financial Statements inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures.
The rule imposes safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures.
These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level to date.
These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level to date. However, Canada has implemented a federal carbon pricing regime.
Through our crude oil transportation and services segment, we own and operate (through wholly owned subsidiaries or joint venture interests) approximately 14,500 miles of crude oil trunk and gathering pipelines in the Southwest, Midcontinent and Midwest United States.
Through our crude oil transportation and services segment, we own and operate (through wholly owned subsidiaries or joint venture interests) approximately 17,950 miles of crude oil trunk and gathering pipelines in the Southwest, Midcontinent and Midwest United States.
OIT is a web-like configuration with multidirectional flow capabilities between numerous receipt points and delivery points.
EOIT is a web-like configuration with multidirectional flow capabilities between numerous receipt points and delivery points.
In December 2020, FERC issued an order setting the indexed rate at PPI-FG plus 0.78% during the five-year period commencing July 1, 2021 and ending June 30, 2026. The FERC received requests for rehearing of its December 17, 2020 order 34 Table of Contents Index to Financial Statements and on January 20, 2022, granted rehearing and modified the oil index.
In December 2020, FERC issued an order setting the indexed rate at PPI-FG plus 0.78% during the five-year period commencing July 1, 2021 and ending June 30, 2026. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index.
As a result of these laws and regulations, our construction and operation costs include capital, operating and maintenance cost items necessary to maintain or upgrade our equipment and facilities. 37 Table of Contents Index to Financial Statements We have implemented procedures designed to ensure that governmental environmental approvals for both existing operations and those under construction are updated as circumstances require.
As a result of these laws and regulations, our construction and operation costs include capital, operating and maintenance cost items necessary to maintain or upgrade our equipment and facilities. We have implemented procedures designed to ensure that governmental environmental approvals for both existing operations and those under construction are updated as circumstances require.
For example, nothing in the EPAct amendments to the NGA were intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals or those of a state acting under federal law. 35 Table of Contents Index to Financial Statements Several other material governmental and regulatory approvals and permits are required throughout the life of our LNG terminal.
For example, nothing in the EPAct amendments to the NGA were intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals or those of a state acting under federal law. Several other material governmental and regulatory approvals and permits are required throughout the life of our LNG terminal.
Nolan Terminal, a joint venture between a wholly owned subsidiary of the Partnership and a wholly owned subsidiary of Sunoco LP, provides diesel fuel storage in Midland, Texas. • This segment also includes the following joint ventures: a 15% membership interest in Explorer, a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur and Houston, Texas and extends to Chicago, Illinois; a 31% membership interest in the Wolverine Pipe Line Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; a 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington. 24 Table of Contents Index to Financial Statements Crude Oil Transportation and Services The following details our pipelines and terminals in its crude oil transportation and services operations: Description of Assets Ownership Interest Miles of Crude Pipeline Working Storage Capacity (MBbls) Dakota Access Pipeline 36.40 % 1,170 — Energy Transfer Crude Oil Pipeline 36.40 % 745 — Bayou Bridge Pipeline 60 % 210 — West Texas Gulf Pipeline 100.0 % 584 Permian Express Pipelines 87.7 % 1,004 — Wattenberg Oil Trunkline 100 % 75 360 White Cliffs Pipeline (1) 51 % 530 100 Maurepas Pipeline 51 % 35 — Mid Valley Pipeline 100 % 1,040 — Cushing Pipeline 100 % 745 — Wink to Webster Pipeline 5 % 642 — Other, crude gathering and water gathering and disposal 100 % 7,700 — Nederland Terminal 100 % — 30,000 Midland terminals 100 % — 3,000 Marcus Hook Terminal 100 % — 1,000 Houston Terminal 100 % — 18,200 Cushing Terminal 100 % — 9,500 Patoka Terminal 87.7 % — 1,900 25 Table of Contents Index to Financial Statements Price River Terminal 55 % — 200 Colt Hub 100 % 20 1,200 (1) The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
Nolan Terminal, a joint venture between a wholly owned subsidiary of the Partnership and a wholly owned subsidiary of Sunoco LP, provides diesel fuel storage in Midland, Texas. • This segment also includes the following joint ventures: a 15% membership interest in Explorer, a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur and Houston, Texas and extends to Chicago, Illinois; a 31% membership interest in the Wolverine Pipe Line Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; a 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington. 24 Table of Contents Index to Financial Statements Crude Oil Transportation and Services The following details our pipelines and terminals in our crude oil transportation and services operations: Description of Assets Ownership Interest Miles of Crude Pipeline Working Storage Capacity (MBbls) Dakota Access Pipeline 36.4 % 1,170 — Energy Transfer Crude Oil Pipeline 36.4 % 745 — Bayou Bridge Pipeline 60 % 210 — West Texas Gulf Pipeline 100.0 % 584 Permian Express Pipelines 87.7 % 1,004 — ET-S Permian (1) 100.0 % 5,000 11,000 Wattenberg Oil Trunkline 100 % 75 360 White Cliffs Pipeline (2) 54.3 % 530 100 Maurepas Pipeline 51 % 35 — Mid Valley Pipeline 100 % 1,040 — Cushing Pipeline 100 % 745 — Wink to Webster Pipeline 5 % 642 — Other, crude gathering and water gathering and disposal 100 % 6,150 — Nederland Terminal 100 % — 30,000 Marcus Hook Terminal 100 % — 1,000 Houston Terminal 100 % — 18,200 Cushing Terminal 100 % — 9,500 Patoka Terminal 87.7 % — 1,900 25 Table of Contents Index to Financial Statements Price River Terminal 55 % — 200 Colt Hub 100 % 20 1,200 (1) A joint venture between Energy Transfer and Sunoco LP formed in 2024.
Existing tariff rates may be challenged by complaint or on the FERC’s own motion, and if found unjust and unreasonable, may be altered on a prospective basis from no earlier than the date of the complaint or initiation of a proceeding by the FERC. The FERC must also approve all rate changes.
Existing tariff rates may be challenged by complaint or on the FERC’s own motion, and if found unjust and unreasonable in a FERC order, may be altered on a prospective basis from no earlier than the date of such FERC order. The FERC must also approve all rate changes.
Crude Oil Acquisition and Marketing Our crude oil acquisition and marketing operations are conducted using our assets, which include approximately 378 crude oil transport trucks, 350 trailers, approximately 176 crude oil truck unloading facilities as well as third-party truck, rail, pipeline and marine assets.
Crude Oil Acquisition and Marketing Our crude oil acquisition and marketing operations are conducted using our assets, which include approximately 380 crude oil transport trucks, 350 trailers and 242 crude oil truck unloading facilities as well as third-party truck, rail, pipeline and marine assets.
Nolan Pipeline, a joint venture between a wholly owned subsidiary of the Partnership and a wholly owned subsidiary of Sunoco LP, transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and has a throughput capacity of approximately 36 MBbls/d. 23 Table of Contents Index to Financial Statements • We have 37 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines.
Nolan Pipeline, a joint venture between a wholly owned subsidiary of the Partnership and a wholly owned subsidiary of Sunoco LP, transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and has a throughput capacity of approximately 36 MBbls/d. • We have 35 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines.
Institutional lenders who provide financing for fossil fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources such as wind and solar photovoltaic, making those sources more attractive for investment, and some of them may elect not to provide funding for fossil fuel energy companies.
Institutional lenders who provide financing for fossil fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources such as wind and solar photovoltaic, making those sources more attractive for investment, and some of them may elect not to provide funding for fossil fuel energy 42 Table of Contents Index to Financial Statements companies.
This facility is connected to our Mariner East Pipeline System, which provides for the transportation of ethane and liquefied petroleum gas (“LPG”) products from western Pennsylvania, West Virginia and eastern Ohio to our Marcus Hook Terminal where these component products can be exported, processed or locally distributed; • NGL fractionation facilities at our Mont Belvieu NGL Complex with an aggregate capacity of 1.15 MMBbls/d; • NGL storage facilities at our Mont Belvieu NGL Complex with a working storage capacity of approximately 60 MMBbls; and • other NGL storage assets with an aggregate storage capacity of approximately 35 MMBbls, including LPG storage assets acquired in connection with the Crestwood acquisition in 2023.
This facility is connected to our Mariner East Pipeline System, which provides for the transportation of ethane and liquefied petroleum gas (“LPG”) products from western Pennsylvania, West Virginia and eastern Ohio to our Marcus Hook Terminal where these component products can be exported, processed or locally distributed; • NGL fractionation facilities at our Mont Belvieu NGL Complex with an aggregate capacity of 1.15 MMBbls/d; • NGL storage facilities at our Mont Belvieu NGL Complex with a working storage capacity of approximately 62 MMBbls; and • other NGL storage assets with an aggregate storage capacity of approximately 35 MMBbls.
We intend to increase the percentage of our business conducted with third parties under fee-based arrangements in order to provide for stable, consistent cash flows over long contract periods while reducing exposure to changes in commodity prices. Enhance profitability of existing assets .
We intend to increase the percentage of our business conducted with third parties under fee-based arrangements in order to provide for stable, consistent cash flows over long contract periods while reducing exposure to changes in commodity prices. 29 Table of Contents Index to Financial Statements Enhance profitability of existing assets .
In addition, the rates, terms and conditions 32 Table of Contents Index to Financial Statements of service for shipments of NGLs on our pipelines are subject to regulation by the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (the “EPAct of 1992”) if the NGLs are transported in interstate or foreign commerce whether by our pipelines or other means of transportation.
In addition, the rates, terms and conditions of service for shipments of NGLs on our pipelines are subject to regulation by the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (the “EPAct of 1992”) if the NGLs are transported in interstate or foreign commerce whether by our pipelines or other means of transportation.
Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheet reflected $277 million in environmental accruals as of December 31, 2023.
Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheet reflected $278 million in environmental accruals as of December 31, 2024.
We voluntarily publish additional information on those initiatives; however, much of that separately published information is excluded from this annual report on Form 10-K if it is not material in the context of the consolidated Partnership and/or if it is not required by the instructions to Form 10-K.
We voluntarily publish additional information on those initiatives; however, much of that separately published information is 43 Table of Contents Index to Financial Statements excluded from this annual report on Form 10-K if it is not material in the context of the consolidated Partnership and/or if it is not required by the instructions to Form 10-K.
As of December 31, 2023 and 2022, accruals of $277 million and $282 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities for estimated environmental liabilities.
As of December 31, 2024 and 2023, accruals of $278 million and $277 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities for estimated environmental liabilities.
Changes such as these examples in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense and, in the case of our oil and natural gas exploration and production customers, could result in increased operating costs for those customers and a corresponding decrease in demand for our processing, transportation and storage services.
Changes such as these examples in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance 38 Table of Contents Index to Financial Statements expense and, in the case of our oil and natural gas exploration and production customers, could result in increased operating costs for those customers and a corresponding decrease in demand for our processing, transportation and storage services.
The Midcontinent Systems include 17 natural gas processing facilities (Mocane, Beaver, Wheeler I, 19 Table of Contents Index to Financial Statements Sunray, Spearman, Rose Valley, Hopeton, Bradley, McClure, Wheeler II, South Canadian, Clinton, Roger Mills, Canute, Cox City, Wetumka and Grady) with an aggregate capacity of approximately 2.9 Bcf/d. • We operate our Midcontinent Systems at low pressures to maximize the total throughput volumes from the connected wells.
The Midcontinent Systems include 16 natural gas processing facilities (Mocane, Beaver, Wheeler I, Sunray, Spearman, Rose Valley, Hopeton, Bradley, McClure, Wheeler II, South Canadian, Clinton, Roger Mills, Canute, Cox City and Grady) with an aggregate capacity of approximately 2.9 Bcf/d. • We operate our Midcontinent Systems at low pressures to maximize the total throughput volumes from the connected wells.
On January 26, 2024, President Biden announced a temporary pause on pending decisions on new exports of LNG to countries that the United States does not have free trade agreements with, pending DOE review of the underlying analyses for authorizations.
On January 26, 2024, President Biden 41 Table of Contents Index to Financial Statements announced a temporary pause on pending decisions on new exports of LNG to countries that the United States does not have free trade agreements with, pending DOE review of the underlying analyses for authorizations.
In January 2023, the EPA and the USACE published a final rule that would restore water protections that were in place prior to 2015. However, the January 2023 rule was challenged and is currently enjoined in 27 states. Separately, in May 2023, the U.S. Supreme Court released its opinion in Sackett v.
In January 2023, the EPA and the USACE published a final rule that would restore water 40 Table of Contents Index to Financial Statements protections that were in place prior to 2015. However, the January 2023 rule was challenged and is currently enjoined in 27 states. Separately, in May 2023, the U.S. Supreme Court released its opinion in Sackett v.
The o-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 100 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d. • The Hattiesburg storage facility is an integrated liquids storage facility with approximately 5 MMBbls of salt dome capacity, providing 100% fee-based cash flows. • The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from fixed fee storage contracts, throughput fees and revenue from blending butane into refined gasoline. • The Nederland Terminal, in addition to crude oil activities, also provides approximately 1.9 MMBbls of storage and distribution services for NGLs delivered from our Mont Belvieu NGL Complex via our Mont Belvieu to Nederland Pipeline System, where such products can be exported via ship. • The Orbit Gulf Coast joint venture consists of a 70-mile, 20-inch ethane pipeline with a throughput capacity of approximately 200 MBbls/d which delivers from our Mont Belvieu NGL Complex to our Nederland Terminal.
The o-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 100 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d. • The Hattiesburg storage facility is an integrated liquids storage facility with approximately 5 MMBbls of salt dome capacity, providing 100% fee-based cash flows. • The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from fixed fee storage contracts, throughput fees and revenue from blending butane into refined gasoline. • The Nederland Terminal, in addition to crude oil activities, also provides approximately 3.1 MMBbls of storage and distribution services for NGLs delivered from our Mont Belvieu NGL Complex via our Mont Belvieu to Nederland Pipeline System, where such products can be exported via ship.
This statute also permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are typically not suspended for the maximum allowable period.
This statute also permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are typically not suspended 33 Table of Contents Index to Financial Statements for the maximum allowable period.
In June 2015, the EPA and the United States Corps of Engineers (“USACE”) published a final rule attempting to clarify the federal jurisdictional reach over “waters of the United States” (“WOTUS”), but legal challenges to this rule followed.
In June 2015, the EPA and the USACE published a final rule attempting to clarify the federal jurisdictional reach over “waters of the United States” (“WOTUS”), but legal challenges to this rule followed.
Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distributes it throughout the United States, including Hawaii and Puerto Rico, to: • 75 company-operated retail stores; • 476 independently operated commission agent locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators; • 6,828 retail stores operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; and • approximately 1,600 other commercial customers, including unbranded retail stores, other fuel distributors, school districts and municipalities and other industrial customers.
Investment in Sunoco LP Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distributes it throughout the United States, including Hawaii and Puerto Rico, to: • 76 company-operated retail stores; • 252 independently operated commission agent locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators; • 6,965 retail stores operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; and • approximately 2,000 other commercial customers, including unbranded retail stores, other fuel distributors, school districts and municipalities and other industrial customers.
The principal competitive factors affecting our retail marketing operations include gasoline and diesel acquisition costs, site location, product price, selection and quality, site appearance and cleanliness, hours of operation, store safety, customer loyalty and brand recognition.
It also varies with gasoline and convenience store offerings. The principal competitive factors affecting our retail marketing operations include gasoline and diesel acquisition costs, site location, product price, selection and quality, site appearance and cleanliness, hours of operation, store safety, customer loyalty and brand recognition.
The EPAct of 2005 amended Section 3 of the NGA to establish or clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless specifically provided otherwise in the EPAct of 2005 amendments to the NGA.
The EPAct of 2005 amended Section 3 of the NGA to establish or clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless specifically provided otherwise in the EPAct of 35 Table of Contents Index to Financial Statements 2005 amendments to the NGA.
Natural gas companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ tariffs offer a cost-based recourse rate to a prospective shipper as an alternative to the negotiated rate.
Natural gas companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ 31 Table of Contents Index to Financial Statements tariffs offer a cost-based recourse rate to a prospective shipper as an alternative to the negotiated rate.
The Colt Hub is located in the heart of the Williston Basin in Williams County, North Dakota. Acquired in 2023 as part of the Crestwood acquisition, the Colt Hub has approximately 1.2 MMBbls of crude oil storage capacity and 160 MBbls/d of rail loading capacity.
The Colt Hub is located in the heart of the Williston Basin in Williams County, North Dakota. The Colt Hub has approximately 1.2 MMBbls of crude oil storage capacity and 160 MBbls/d of rail loading capacity.
USAC is not directly exposed to commodity price risk because it does not take title to the natural gas or crude oil involved in its services and because the natural gas used as fuel by its compression units is supplied by its customers without cost to USAC. 11 Table of Contents Index to Financial Statements USAC’s assets and operations are all located and conducted in the United States.
USAC is not directly exposed to commodity price risk because it does not take title to the natural gas or crude oil 11 Table of Contents Index to Financial Statements involved in its services and because the natural gas used as fuel by its compression units is supplied by its customers without cost to USAC.
Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines. Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The recognition of additional losses, if and when they were to occur, would likely extend over many years, but management can provide no assurance that it would be 39 Table of Contents Index to Financial Statements over many years.
The recognition of additional losses, if and when they were to occur, would likely extend over many years, but management can provide no assurance that it would be over many years.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeAny of these actions could result in fewer visits to convenience stores or independently operated commission agents and dealer locations, a reduction in demand from their wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit margins, any of which could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.
Biggest changeAny of these or similar actions could result in fewer visits to Sunoco LP’s convenience stores or independently operated commission agents and dealer locations, a reduction in demand from Sunoco LP’s wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit margins, any of which could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution to our unitholders. • a recession, high interest rates, inflation or other adverse economic conditions that result in lower spending by consumers on gasoline, diesel and travel; • events that negatively impact global economic activity, travel and demand generally; • higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline; • an increase in aggregate automotive engine fuel economy; • new government and regulatory actions or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles; • the increased use of and public demand for use of alternative fuel sources or electric vehicles; • an increase in the market price of crude oil that increases refined product prices, which may reduce demand for refined products and increase demand for alternative products; and • adverse weather events resulting in decreased corn acres planted, which may reduce demand for anhydrous ammonia.
The FERC must approve or accept all rate filings for us to be allowed to charge such rates. The FERC may review existing tariff rates on its own initiative or upon receipt of a complaint filed by a third party.
The FERC must approve or accept all rate filings for us to be allowed to charge such tariff rates. The FERC may review existing tariff rates on its own initiative or upon receipt of a complaint filed by a third-party.
Historically, we have been able to satisfy the more stringent nitrogen oxide emission reduction requirements that 71 Table of Contents Index to Financial Statements affect our compressor units in ozone non-attainment areas at reasonable cost, but there is no assurance that we will not incur material costs in the future to meet the new, more stringent ozone standard.
Historically, we have been able to satisfy the 71 Table of Contents Index to Financial Statements more stringent nitrogen oxide emission reduction requirements that affect our compressor units in ozone non-attainment areas at reasonable cost, but there is no assurance that we will not incur material costs in the future to meet the new, more stringent ozone standard.
This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner; • provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests; • generally provides that affiliated transactions and resolutions of conflicts of interest not approved by a conflicts committee of the board of directors of our general partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us; 87 Table of Contents Index to Financial Statements • provides that unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty; • provides that our general partner may resolve any conflicts of interest involving us and our general partner and its affiliates, and any resolution of a conflict of interest by our general partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and will not constitute a breach of the Partnership Agreement; • provides that our general partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such resolution by appointing a conflicts committee of the general partner’s board of directors composed of two or more independent directors to consider such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed “fair and reasonable” to us; and • provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner; • provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests; • generally provides that affiliated transactions and resolutions of conflicts of interest not approved by a conflicts committee of the board of directors of our general partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the 88 Table of Contents Index to Financial Statements totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us; • provides that unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty; • provides that our general partner may resolve any conflicts of interest involving us and our general partner and its affiliates, and any resolution of a conflict of interest by our general partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and will not constitute a breach of the Partnership Agreement; • provides that our general partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such resolution by appointing a conflicts committee of the general partner’s board of directors composed of two or more independent directors to consider such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed “fair and reasonable” to us; and • provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
Breaches of our information technology infrastructure or physical assets, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, data loss or corruption, misdirected wire transfers, an inability to maintain our books and records or an inability to prevent environmental damage, any or all of which could, in turn, have a material adverse effect on our operations, financial position and results of operations.
Breaches of our information and operational technology infrastructure or physical assets, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, data loss or corruption, misdirected wire transfers, an inability to maintain our books and records or an inability to prevent environmental damage, any or all of which could, in turn, have a material adverse effect on our operations, financial position and results of operations.
Laws such as the Bipartisan Infrastructure Act and the IRA 2022 allocate funds to the development of electric vehicle infrastructure and provide incentives for consumers and manufacturers related to their use or development of electric vehicles, and the adoption rate of electric vehicles in the U.S. has continued to accelerate, with projections for the future rate of adoption in some reports more than doubling in recent years.
Additionally, laws such as the Bipartisan Infrastructure Act and the IRA 2022 allocate funds to the development of electric vehicle infrastructure and provide incentives for consumers and manufacturers related to their use or development of electric vehicles, and the adoption rate of electric vehicles in the U.S. has continued to accelerate, with projections for the future rate of adoption in some reports more than doubling in recent years.
Our General Partner . Our stakeholders could be impacted by risks related to our general partner, including: • transfer of control of our general partner to a third party without unitholder consent; • the rights of the majority owner of our general partner that protect him against dilution; and • substantial cost reimbursements due to our general partner.
Our General Partner . Our stakeholders could be impacted by risks related to our general partner, including: • transfer of control of our general partner to a third-party without unitholder consent; • the rights of the majority owner of our general partner that protect him against dilution; and • substantial cost reimbursements due to our general partner. Our Subsidiaries .
Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. Such ESG matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. Such ESG-related matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
Our information technology and infrastructure, physical assets and data, may be vulnerable to unauthorized access, computer viruses, malicious attacks and other events (e.g., distributed denial of service attacks, ransomware attacks) that are beyond our control.
Our information and operational technology and infrastructure, physical assets and data, may be vulnerable to unauthorized access, computer viruses, malicious attacks and other events (e.g., distributed denial of service attacks, ransomware attacks) that are beyond our control.
Unitholders face unique tax issues from owning our units that may result in adverse tax consequences to them; and • the treatment of Energy Transfer Preferred Units is uncertain and distributions on Energy Transfer Preferred Units (other than Series I Preferred Units) may not be eligible for the 20% deduction for qualified publicly traded partnership income. 48 Table of Contents Index to Financial Statements Risk Factor Discussion The following discussion provides additional information regarding each of our risk factors listed above.
Unitholders face unique tax issues from owning our units that may result in adverse tax consequences to them; and • the treatment of Energy Transfer Preferred Units is uncertain and distributions on Energy Transfer Preferred Units (other than Series I Preferred Units) may not be eligible for the 20% deduction for qualified publicly traded partnership income. 47 Table of Contents Index to Financial Statements Risk Factor Discussion The following discussion provides additional information regarding each of our risk factors listed above.
Such vertical integration, increases in vertical integration or use of alternative technologies could result in decreased demand for USAC’s compression services, which may have a material adverse effect on its business, results of operations, financial condition and reduce its cash available for distribution. 85 Table of Contents Index to Financial Statements A significant portion of USAC’s services are provided to customers on a month-to-month basis, and USAC cannot be sure that such customers will continue to utilize its services.
Such vertical integration, increases in vertical integration or use of alternative technologies could result in decreased demand for USAC’s compression services, which may have a material adverse effect on its business, results of operations, financial condition and reduce its cash available for distribution. 86 Table of Contents Index to Financial Statements A significant portion of USAC’s services are provided to customers on a month-to-month basis, and USAC cannot be sure that such customers will continue to utilize its services.
The NYSE does not require a publicly traded partnership like us to comply with certain corporate governance requirements. Our common units, Series E Preferred Units and Series I Preferred Units are listed on the NYSE.
The NYSE does not require a publicly traded partnership like us to comply with certain corporate governance requirements. Our common units and Series I Preferred Units are listed on the NYSE.
Accordingly, we cannot guarantee that our subsidiaries, including Sunoco LP and USAC, will have sufficient available cash to pay a specific level of cash distributions to their respective partners. 49 Table of Contents Index to Financial Statements Furthermore, Unitholders should be aware that the amount of cash that our subsidiaries have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items.
Accordingly, we cannot guarantee that our subsidiaries, including Sunoco LP and USAC, will have sufficient available cash to pay a specific level of cash distributions to their respective partners. 48 Table of Contents Index to Financial Statements Furthermore, Unitholders should be aware that the amount of cash that our subsidiaries have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items.
We and certain of our service providers have, from time to time, been subject to cyber attacks and security incidents. The frequency and magnitude of cyber attacks is increasing and attackers are becoming more sophisticated.
We and certain of our service providers have, from time to time, been subject to cyber attacks and security incidents. The frequency and magnitude of cyber attacks globally is increasing and attackers are becoming more sophisticated.
Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the following: • increased regulation of hydraulic fracturing or produced water disposal; • legal or regulatory actions related to the Dakota Access Pipeline; 47 Table of Contents Index to Financial Statements • laws, regulations and policies governing the rates, terms and conditions of our services; • failure to recover the full amount of increases in the costs of our pipeline operations; • imposition of regulation on assets not previously subject to regulation; • costs and liabilities resulting from performance of pipeline integrity programs and related repairs; • new or more stringent pipeline safety controls or enforcement of legal requirements; • costs and liabilities associated with environmental and worker health and safety laws and regulations; • climate change legislation or regulations restricting emissions of GHGs, limiting oil and gas leases on federal lands, discouraging oil and gas development or otherwise increasing our or our customers’ costs; • increased attention to environmental, social, and governance (“ESG”) matters and conservation measures; • regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder; • deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and related developments; and • laws and regulations governing the specifications of products that we store and transport.
Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the following: • increased regulation of hydraulic fracturing or produced water disposal; • legal or regulatory actions related to the Dakota Access Pipeline; • laws, regulations and policies governing the rates, terms and conditions of our services; • failure to recover the full amount of increases in the costs of our pipeline operations; • imposition of regulation on assets not previously subject to regulation; • costs and liabilities resulting from performance of pipeline integrity programs and related repairs; • new or more stringent pipeline safety controls or enforcement of legal requirements; • costs and liabilities associated with environmental and worker health and safety laws and regulations; • climate change legislation or regulations restricting emissions of GHGs, limiting oil and gas leases on federal lands, discouraging oil and gas development or otherwise increasing our or our customers’ costs; • increased attention to environmental, social, and governance (“ESG”) matters and conservation measures; • regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder; • deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and related developments; and • laws and regulations governing the specifications of products that we store and transport.
The FERC issued a Notice of Inquiry (“NOI”) on April 19, 2018 (“2018 NOI”) initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities (“1999 Policy Statement”), issued in 1999, that is used to determine whether to grant certificates for new pipeline projects.
The FERC issued a Notice of Inquiry (“NOI”) on April 19, 2018 initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities (“1999 Policy Statement”), issued in 1999, that is used to determine whether to grant certificates for new pipeline projects.
The security and integrity of our information technology infrastructure and physical assets are critical to our business and our ability to perform day-to-day operations and deliver services.
The security and integrity of our information and operational technology infrastructure and physical assets are critical to our business and our ability to perform day-to-day operations and deliver services.
Increasing congestion in the Port of Houston, which is currently the busiest port in the U.S. by waterborne tonnage and which has increased volumes in each of the last two years, could cause our customers or potential customers to divert their business to smaller ports in the Gulf of Mexico, which could result in lower utilization of our facilities.
Increasing congestion in the Port of Houston, which is currently the busiest port in the U.S. by waterborne tonnage and which has increased volumes in each of the last two years, could cause our customers or potential customers to divert their business to smaller ports in the Gulf of America, which could result in lower utilization of our facilities.
The IRA 2022 imposes a methane emissions charge on sources required to report their GHG emissions to the EPA, which started in calendar year 2024 at $900 per ton of methane, increases to $1,200 in 2025, and will be set at $1,500 for 2026 and each year after.
The IRA 2022 imposes a methane emissions charge on sources required to report their GHG emissions to the EPA, which started in calendar year 2024 at $900 per ton of methane, increased to $1,200 in 2025, and will be set at $1,500 for 2026 and each year after.
Our business could be negatively impacted by inflationary pressures which may decrease our operating margins and increase working capital investments required to operate our business. The U.S. inflation rate steadily rose in 2021 and into 2022 before eventually declining throughout 2023.
Our business could be negatively impacted by inflationary pressures which may decrease our operating margins and increase working capital investments required to operate our business. The U.S. inflation rate steadily rose in 2021 and into 2022 before eventually declining modestly throughout 2023 and 2024.
Although we expect that much of the income we earn will be eligible for the 20% deduction for qualified publicly traded partnership income for taxable years beginning after December 31, 2025, the Treasury Regulations provide that income attributable to a guaranteed payment for the use of capital is not eligible for the 20% deduction for qualified business income.
Although we expect that much of the income we earn will be eligible for the 20% deduction for qualified publicly traded partnership income for taxable years beginning before December 31, 2025, the Treasury Regulations provide that income attributable to a guaranteed payment for the use of capital is not eligible for the 20% deduction for qualified business income.
The methane emissions charge started in calendar year 2024 at $900 per ton of methane, increases to $1,200 in 2025, and will be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022.
The methane emissions charge started in calendar year 2024 at $900 per ton of methane, increased to $1,200 in 2025, and will be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022.
Also, despite these aspirational goals, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
Also, despite any aspirational goals, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
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.
Panhandle filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023.
Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval.
Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected that are determined to be in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval.
The difficulties of integrating past and future acquisitions with our business include, among other things: • operating a larger combined organization in new geographic areas and new lines of business; • hiring, training or retaining qualified personnel to manage and operate our growing business and assets; • integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees; • diversion of management’s attention from our existing business; • assimilation of acquired assets and operations, including additional regulatory programs; • loss of customers or key employees; 62 Table of Contents Index to Financial Statements • maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and • integrating new technology systems for financial reporting.
The difficulties of integrating past and future acquisitions with our business include, among other things: • operating a larger combined organization in new geographic areas and new lines of business; • hiring, training or retaining qualified personnel to manage and operate our growing business and assets; • integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees; • diversion of management’s attention from our existing business; • assimilation of acquired assets and operations, including additional regulatory programs; • loss of customers or key employees; • maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and • integrating new technology systems for financial reporting.
Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the following: • failure to make acquisitions on economically acceptable terms, or to successfully integrate acquired assets; • failure to secure debt and equity financing for capital projects on acceptable terms, including as a result of recent increases in cost of capital resulting from changes in monetary policy by the Federal Reserve and/or changes in financial institutions’ policies or practices concerning businesses linked to fossil fuels; • any increased costs or reduced demand for crude oil and natural gas as a result of the Inflation Reduction Act of 2022 (“IRA 2022”) or otherwise; • failure to construct new pipelines or to do so efficiently; • failure to execute our growth strategy due to increased competition within any of our core businesses; and • failure to attract and retain qualified employees; and • failure of the liquefaction project to secure long-term contractual arrangements or necessary approvals.
Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the following: • failure to make acquisitions on economically acceptable terms, or to successfully integrate acquired assets; • failure to secure debt and equity financing for capital projects on acceptable terms, including as a result of recent increases in cost of capital resulting from changes in monetary policy by the Federal Reserve and/or changes in financial institutions’ policies or practices concerning businesses linked to fossil fuels; • any increased costs or reduced demand for crude oil and natural gas as a result of the Inflation Reduction Act of 2022 (“IRA 2022”) or otherwise; • failure to construct new pipelines or to do so efficiently; • failure to execute our growth strategy due to increased competition within any of our core businesses; • failure to attract and retain qualified employees; and • failure of the liquefaction project to secure long-term contractual arrangements or necessary approvals. 46 Table of Contents Index to Financial Statements Regulatory Matters .
We may be required to invest significant additional resources to comply with evolving cybersecurity and data privacy laws or regulations and to modify and enhance our information security and controls, and to investigate and remediate any security vulnerabilities.
We may be required to invest significant additional resources to comply with evolving cybersecurity and data privacy laws and regulations and to modify and enhance our information and operational security and controls, and to investigate and remediate any security vulnerabilities.
In September 2023, the DOI published a proposed final offshore leasing program for 2024 – 2029, which was then approved by the Secretary of the Interior and authorized three Gulf of Mexico leasing sales.
In September 2023, the DOI published a proposed final offshore leasing program for 2024 – 2029, which was then approved by the Secretary of the Interior and authorized three Gulf of America leasing sales.
Sunoco LP’s fuel storage terminals are subject to operational and business risks which may adversely affect their financial condition, results of operations, cash flows and ability to make distributions to its unitholders.
Sunoco LP’s pipelines and fuel storage terminals are subject to operational and business risks which may adversely affect its financial condition, results of operations, cash flows and ability to make distributions to its unitholders.
In addition, the Colorado Energy and Carbon Management Commission (formerly the Colorado Oil and Gas Conservation Commission) adopted new rules to cover a variety of matters related to public health, safety, welfare, wildlife, and environmental resources, and is considering draft rules regarding the cumulative impacts of oil and gas projects; most significantly, these rule changes establish more stringent setbacks (2,000-foot, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions.
In addition, the Colorado Energy and Carbon Management Commission (formerly the Colorado Oil and Gas Conservation Commission) adopted new rules to cover a variety of matters related to public health, safety, welfare, wildlife, and environmental resources, and has issued new rules regarding the cumulative impacts of oil and gas projects; most significantly, these rule changes establish more stringent setbacks (2,000-foot, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions.
Additionally, in December 2023, the EPA issued a final rule that established OOOOb new source and OOOOc first-time existing source standards of performance for GHG and VOC emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities, Owners or operators of affected emission units or processes will have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called “green well” completion requirements.
Additionally, in 72 Table of Contents Index to Financial Statements December 2023, the EPA issued a final rule that established OOOOb new source and OOOOc first-time existing source standards of performance for GHG and VOC emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities, Owners or operators of affected emission units or processes will have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called “green well” completion requirements.
In addition, the actual amount of cash we and our subsidiaries, including Sunoco LP and USAC, will have available for distribution will also depend on other factors, such as: • the level of capital expenditures we and our subsidiaries make; • the level of costs related to litigation and regulatory compliance matters; • the cost of acquisitions, if any; • the levels of any margin calls that result from changes in commodity prices; • our and our subsidiaries’ debt service requirements; 77 Table of Contents Index to Financial Statements • fluctuations in our and our subsidiaries’ working capital needs; • our and our subsidiaries’ ability to borrow under our revolving credit facility; • our and our subsidiaries’ ability to access capital markets; • restrictions on distributions contained in our and our subsidiaries’ debt agreements; and • the amount of cash reserves established by our general partner in its discretion for the proper conduct of our business.
In addition, the actual amount of cash we and our subsidiaries, including Sunoco LP and USAC, will have available for distribution will also depend on other factors, such as: • the level of capital expenditures we and our subsidiaries make; • the level of costs related to litigation and regulatory compliance matters; • the cost of acquisitions, if any; • the levels of any margin calls that result from changes in commodity prices; • our and our subsidiaries’ debt service requirements; • fluctuations in our and our subsidiaries’ working capital needs; • our and our subsidiaries’ ability to borrow under our revolving credit facility; • our and our subsidiaries’ ability to access capital markets; • restrictions on distributions contained in our and our subsidiaries’ debt agreements; and • the amount of cash reserves established by our general partner in its discretion for the proper conduct of our business.
On March 24, 2022, the FERC issued an order designating the 2022 Policy Statements as draft policy statements, and requested further comments. The FERC stated that it will not apply the now draft 2022 Policy Statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics.
On March 24, 2022, the FERC issued an order designating the 2022 Certificate Policy Statement and the GHG Policy Statement as draft policy statements, and requested further comments. The FERC stated that it will not apply the now draft policy statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures will be based on expectations and assumptions.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures will be based on expectations, assumptions and hypothetical scenarios.
The FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC has recently exercised this authority with respect to several other pipeline companies.
The FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC has recently exercised this authority with respect to several pipeline companies, including Panhandle.
On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certificate of New Interstate Natural Gas Facilities and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“2022 Policy Statements”), to be effective that same day.
On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certificate of New Interstate Natural Gas Facilities (“2022 Certificate Policy Statement”) and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“GHG Policy Statement), to be effective that same day.
Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations.
Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations.
We do not expect that any change in these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the United States. Rate regulation or market conditions may not allow us to recover the full amount of increases in the costs of our crude oil, NGL and refined products pipeline operations.
We do not expect that any change in this policy statement would affect us in a materially different manner than any other natural gas pipeline company operating in the United States. Rate regulation or market conditions may not allow us to recover the full amount of increases in the costs of our crude oil, NGL and refined products pipeline operations.
Sunoco LP does not own all of the land on which its retail service stations are located. Sunoco LP has rental agreements for approximately 33% of the company, commission agent or dealer operated retail service stations where Sunoco LP currently controls the real estate. Sunoco LP also has rental agreements for certain logistics facilities.
Sunoco LP does not own all of the land on which its retail service stations are located. Sunoco LP has rental agreements for approximately 38% of Sunoco LP, commission agent or dealer operated retail service stations where Sunoco LP currently controls the real estate. Sunoco LP also has rental agreements for certain logistics facilities.
Sunoco LP’s fuel storage terminals are subject to operational and business risks, the most significant of which include the following: • the inability to renew a ground lease for certain of their fuel storage terminals on similar terms or at all; • the dependence on third parties to supply their fuel storage terminals; • outages at their fuel storage terminals or interrupted operations due to weather-related or other natural causes; • the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations; • the volatility in the prices of the products stored at their fuel storage terminals and the resulting fluctuations in demand for storage services; • the effects of a sustained recession or other adverse economic conditions; • the possibility of federal and/or state regulations that may discourage their customers from storing gasoline, diesel fuel, ethanol and jet fuel at their fuel storage terminals or reduce the demand by consumers for petroleum products; • competition from other fuel storage terminals that are able to supply their customers with comparable storage capacity at lower prices; and • climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for our storage services.
Sunoco LP’s pipelines and fuel storage terminals are subject to operational and business risks, the most significant of which include the following: • the inability to renew a ground lease for certain of its pipelines or fuel storage terminals on similar terms or at all; • the dependence on third parties to supply its fuel storage terminals; • outages at its pipelines or fuel storage terminals or interrupted operations due to weather-related or other natural causes; • the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations; • the volatility in the prices of the products transported on its pipelines or stored at its fuel storage terminals and the resulting fluctuations in demand for storage services; • the effects of a sustained recession or other adverse economic conditions; • the possibility of federal and/or state regulations that may discourage its customers from transporting or storing gasoline, diesel fuel, ethanol and jet fuel at its fuel storage terminals or reduce the demand by consumers for petroleum products; • competition from other pipelines and fuel storage terminals that are able to provide its customers with comparable transportation service or storage capacity at lower prices; and • climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for its transportation and storage services.
Our results of operations and financial condition could be impacted by many risks that are beyond our control, including the following: • fluctuations in the demand for and price of natural gas, NGLs, crude oil and refined products; • an impairment of goodwill and intangible assets; • an interruption of supply of crude oil to our facilities; • the loss of any key producers or customers; • failure to retain or replace existing customers or volumes due to declining demand or increased competition; • unfavorable changes in natural gas price spreads between two or more physical locations; • production declines over time, which we may not be able to replace with production from newly drilled wells; • competition for water resources or limitations on water usage for hydraulic fracturing; • our customers’ ability to use our pipelines and third-party pipelines over which we have no control; • the inability to access or continue to access lands owned by third parties; • the overall forward market for crude oil and other products we store; • a natural disaster, catastrophe, terrorist attack or other similar event; • extreme weather events that may be more severe or frequent than historically experienced and that may be attributable to changes in climate due to the adverse effects of an industrialized economy; • union disputes and strikes or work stoppages by unionized employees; • cybersecurity breaches and other disruptions or failures of our information systems; • failure to establish or maintain adequate corporate governance; • product liability claims and litigation, or increased insurance costs including as a result of increased risks due to the potential adverse effects of changes in climate; • actions taken by certain of our joint ventures that we do not control; • increasing levels of congestion in the Houston Ship Channel; • the costs of providing pension and other postretirement health care benefits and related funding requirements; • mergers among customers and competitors; • fraudulent activity or misuse of proprietary data involving our outsourcing partners; and • losses resulting from the use of derivative financial instruments.
Our results of operations and financial condition could be impacted by many risks that are beyond our control, including the following: • fluctuations in the demand for and price of natural gas, NGLs, crude oil and refined products; • general economic, financial and political conditions, including the impact of tariffs, to the extent enacted; • the imposition or increase of tariffs on steel or other raw materials, or changes in trade agreements or trade relations; • an impairment of goodwill and intangible assets; • an interruption of supply of crude oil to our facilities; • the loss of any key producers or customers; • failure to retain or replace existing customers or volumes due to declining demand or increased competition; • unfavorable changes in natural gas price spreads between two or more physical locations; • production declines over time, which we may not be able to replace with production from newly drilled wells; • competition for water resources or limitations on water usage for hydraulic fracturing; • our customers’ ability to use our pipelines and third-party pipelines over which we have no control; • the inability to access or continue to access lands owned by third parties; • the overall forward market for crude oil and other products we store; • a natural disaster, catastrophe, terrorist attack or other similar event; • extreme weather events that may be more severe or frequent than historically experienced and that may be attributable to changes in climate due to the adverse effects of an industrialized economy; • union disputes and strikes or work stoppages by unionized employees; • cybersecurity breaches and other disruptions or failures of our information systems; • failure to establish or maintain adequate corporate governance; • product liability claims and litigation, or increased insurance costs including as a result of increased risks due to the potential adverse effects of changes in climate; • actions taken by certain of our joint ventures that we do not control; • increasing levels of congestion in the Houston Ship Channel; • the costs of providing pension and other postretirement health care benefits and related funding requirements; • mergers among customers and competitors; • fraudulent activity or misuse of proprietary data involving our outsourcing partners; and • losses resulting from the use of derivative financial instruments.
We may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others: • we are unable to identify pipeline construction opportunities with favorable projected financial returns; • we are unable to obtain necessary governmental approvals and contracts with qualified contractors and vendors on acceptable terms; • we are unable to raise financing for our identified pipeline construction opportunities; or • we are unable to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.
We may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others: • we are unable to identify pipeline construction opportunities with favorable projected financial returns; • we are unable to obtain necessary governmental approvals and contracts with qualified contractors and vendors on acceptable terms; 60 Table of Contents Index to Financial Statements • we are unable to raise financing for our identified pipeline construction opportunities; or • we are unable to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.
The resolution of these conflicts may not always be in our best interest. 86 Table of Contents Index to Financial Statements For example, conflicts of interest with Sunoco LP and USAC may arise in the following situations: • the allocation of shared overhead expenses to Sunoco LP, USAC and us; • the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Sunoco LP and USAC, on the other hand; • the determination of the amount of cash to be distributed to Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future conduct of Sunoco LP’s and USAC’s businesses; • the determination whether to make borrowings under Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective partners; • the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of Sunoco LP and USAC is made available for Sunoco LP and USAC to pursue; and • any decision we make in the future to engage in business activities independent of Sunoco LP and USAC.
The resolution of these conflicts may not always be in our best interest. 87 Table of Contents Index to Financial Statements For example, conflicts of interest with Sunoco LP and USAC may arise in the following situations: • the allocation of shared overhead expenses to Sunoco LP, USAC and us; • the management of the ET-S Permian joint venture; • the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Sunoco LP and USAC, on the other hand; • the determination of the amount of cash to be distributed to Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future conduct of Sunoco LP’s and USAC’s businesses; • the determination whether to make borrowings under Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective partners; • the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of Sunoco LP and USAC is made available for Sunoco LP and USAC to pursue; and • any decision we make in the future to engage in business activities independent of Sunoco LP and USAC.
As a result, Unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2023, the directors and executive officers of our general partner owned approximately 10% of our Common Units.
As a result, Unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2024, the directors and executive officers of our general partner owned approximately 7% of our Common Units.
As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.
As a result, numerous proposals have been made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.
As of December 31, 2023, approximately 10% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that we will not experience a work stoppage in the future as a result of labor disagreements.
As of December 31, 2024, approximately 9% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that we will not experience a work stoppage in the future as a result of labor disagreements.
If the FERC were to initiate a proceeding against us and find that our rates were not just and reasonable or were unduly discriminatory, the maximum rates we are permitted to charge may be reduced and the reduction could have an adverse effect on our revenues and results of operations.
If the FERC were to initiate additional proceedings against us and find that our rates were not just and reasonable or were unduly discriminatory, the maximum rates we are permitted to charge may be reduced and the reduction could have an adverse effect on our revenues and results of operations.
A significant decrease in demand for motor fuel, including increased consumer preference for alternative motor fuels, improvements in fuel efficiency or a material shift toward electric or other alternative-power vehicles, in the areas Sunoco LP serves would reduce their ability to make distributions to its unitholders.
A significant decrease in demand for motor fuel, crude oil or refined products, including increased consumer preference for alternative motor fuels, improvements in fuel efficiency or a material shift toward electric or other alternative-power vehicles, in the areas Sunoco LP serves would reduce their ability to make distributions to its unitholders.
For the year ended December 31, 2023, approximately 22% of USAC’s compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize its services following expiration of the primary term of their contracts. These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice.
For the year ended December 31, 2024, approximately 14% of USAC’s compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize its services following expiration of the primary term of their contracts. These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice.
The final publication or implementation of this rule, as well as any new rules, regulations, or legal initiatives, could delay or disrupt our customers’ operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding and costs, limit activities in certain areas, or cause our customers’ to incur penalties, or shut-in production or lease cancellation.
Rules such as this, as well as any new rules, regulations, or legal initiatives, could delay or disrupt our customers’ operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding and costs, limit activities in certain areas, or cause our customers’ to incur penalties, or shut-in production or lease cancellation.
Cyber attacks, 55 Table of Contents Index to Financial Statements including, but not limited to, malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data, are evolving.
Cyber attacks, including, but not limited to, malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data, are evolving.
The issuance of additional Common Units or other equity securities by us will have the following effects: • our Unitholders’ current proportionate ownership interest in us will decrease; • the amount of cash available for distribution on each Common Unit or partnership security may decrease; • the ratio of taxable income to distributions may increase; • the relative voting strength of each previously outstanding Common Unit and/or Preferred Unit may be diminished; and • the market price of our Common Units and/or Preferred Units may decline.
The issuance of additional Common Units or other equity securities by us will have the following effects: • our Unitholders’ current proportionate ownership interest in us will decrease; • the amount of cash available for distribution on each Common Unit or partnership security may decrease; • the ratio of taxable income to distributions may increase; 76 Table of Contents Index to Financial Statements • the relative voting strength of each previously outstanding Common Unit and/or Preferred Unit may be diminished; and • the market price of our Common Units and/or Preferred Units may decline.
Unitholders could have unlimited liability for obligations of the Partnership if a court or government agency determined that (i) we were conducting business in a state, but had not complied with that particular state’s partnership statute; or (ii) a Unitholder’s right to act with other Unitholders to remove or 79 Table of Contents Index to Financial Statements replace our general partner, to approve some amendments to our Partnership Agreement or to take other actions under the Partnership Agreement constituted “control” of our business.
Unitholders could have unlimited liability for obligations of the Partnership if a court or government agency determined that (i) we were conducting business in a state, but had not complied with that particular state’s partnership statute; or (ii) a Unitholder’s right to act with other Unitholders to remove or replace our general partner, to approve some amendments to our Partnership Agreement or to take other actions under the Partnership Agreement constituted “control” of our business.
We are unable to predict what, if any, changes may be proposed as a result of the 2022 Policy Statements that might affect our natural gas pipeline or LNG facility projects, or when such new policies, if any, might become effective.
We are unable to predict what, if any, changes may be proposed as a result of the 2022 Certificate Policy Statement that might affect our natural gas pipeline or LNG facility projects, or when such new policy, if any, might become effective.
Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices.
Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our 56 Table of Contents Index to Financial Statements exposure to commodity prices.
If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted. Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers.
If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted. 62 Table of Contents Index to Financial Statements Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers.
Any such access, disclosure or loss could result in legal claims or proceedings, significant litigation costs, regulatory investigations and enforcement, penalties and fines, increased costs for system remediation and compliance requirements, disruption of our operations, damage to our reputation, or loss of confidence in our products and services, any or all of which could have a material adverse effect on our business and results.
Any such access, disclosure or loss could result in legal claims or 55 Table of Contents Index to Financial Statements proceedings, significant litigation costs, regulatory investigations and enforcement, penalties and fines, increased costs for system remediation and compliance requirements, disruption of our operations, damage to our reputation, or loss of confidence in our products and services, any or all of which could have a material adverse effect on our business and results.
Our Partnership Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. 88 Table of Contents Index to Financial Statements federal, state, local or foreign income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.
Our Partnership Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local or foreign income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.
In addition, the RFS regulations are highly complex and evolving, and the RINs market is subject to significant price volatility as a result. In December 2022, the EPA released a proposed rule under the RFS for renewable fuel volumes for the years 2023-2025 that further increases targets for the production of renewable fuels.
In addition, the RFS regulations are highly complex and evolving, and the RINs market is subject to significant price volatility as a result. In June 2023, the EPA released a final rule under the RFS for renewable fuel volumes for the years 2023-2025 that further increases targets for the production of renewable fuels.
For example, in 2023, the DOI proposed a rule to modernize the fiscal terms of the leasing program, increase costs associated with such leases and add new criteria for the DOI to consider when deciding whether to lease nominated lands.
For example, in 2024, the DOI finalized a rule to modernize the fiscal terms of the leasing program, increase costs associated with such leases and add new criteria for the DOI to consider when deciding whether to lease nominated lands.
Some of these costs fluctuate 61 Table of Contents Index to Financial Statements based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.
Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.
In the same January 26 order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline be shut down and emptied of oil because of the lack of findings sufficient to satisfy the legal requirements for injunctive relief, including a finding of irreparable harm to the Tribes in the absence of an injunction.
In the same January 26 64 Table of Contents Index to Financial Statements order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline be shut down and emptied of oil because of the lack of findings sufficient to satisfy the legal requirements for injunctive relief, including a finding of irreparable harm to the Tribes in the absence of an injunction.
In 2022, the recommendations in this report resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate, and in 2023, the DOI proposed a rule to modernize the fiscal terms of the leasing program.
In 2022, the recommendations in this report resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate, and in 2024, the DOI finalized a rule to modernize the fiscal terms of the leasing program.
Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in 75 Table of Contents Index to Financial Statements decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts.
Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts.
If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our Unitholders might be substantially reduced. Unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our Unitholders might be substantially reduced. 90 Table of Contents Index to Financial Statements Unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
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. For further information, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this annual report.
Comments to the Draft EIS were due on December 13, 2023. The USACE anticipates that a Final EIS will be issued in December 2025 and a Record of Decision will be issued in early 2026. For further information, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this annual report.
For the year ended December 31, 2023, sales of refined motor fuels accounted for approximately 98% of Sunoco LP’s total revenues and 69% of gross profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and Sunoco LP’s ability to make distributions to its unitholders, including Energy Transfer.
For the year ended December 31, 2024, sales of refined motor fuels accounted for approximately 95% of Sunoco LP’s total revenues and 47% of gross profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and Sunoco LP’s ability to make distributions to its unitholders, including Energy Transfer.
Approximately $3.29 billion of our consolidated debt as of December 31, 2023 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates.
Approximately $4.33 billion of our consolidated debt as of December 31, 2024 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates.
In May 2022, the FERC granted a second extension of time until and including December 16, 2028 to complete construction of the liquefaction facilities modifications and place the facilities into service. The export of LNG produced by any liquefaction facility in the United States requires export authorization from the DOE.
In May 2022, the FERC granted a second extension of time until and including December 16, 2028 to complete construction of the liquefaction facilities modifications and place the facilities into service. 61 Table of Contents Index to Financial Statements The export of LNG produced by any liquefaction facility in the United States requires export authorization from the DOE.
In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the 76 Table of Contents Index to Financial Statements construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.
In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.
Regulations under the Clean Water Act, Oil Pollution Act of 1990, as amended (“OPA”), and state laws impose regulatory burdens on terminal operations. Spill prevention control and countermeasure requirements of federal and state laws require containment to mitigate or prevent contamination of waters in the event of a refined product overflow, rupture, or leak from above-ground pipelines and storage tanks.
Regulations under the Clean Water Act, the OPA, and state laws impose regulatory burdens on terminal operations. Spill prevention control and countermeasure requirements of federal and state laws require containment to mitigate or prevent contamination of waters in the event of a refined product overflow, rupture, or leak from above-ground pipelines and storage tanks.
In addition, our Partnership Agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to Unitholders.
In addition, our Partnership Agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners.
For more information, see our regulatory disclosure titled “Indigenous Protections.” Our ability to secure extensions of existing agreements, permits and licenses is essential to our continuing business operations, and securing additional rights-of-way will be critical to our ability to pursue expansion projects.
For more information, see our regulatory disclosure titled “Indigenous 53 Table of Contents Index to Financial Statements Protections.” Our ability to secure extensions of existing agreements, permits and licenses is essential to our continuing business operations, and securing additional rights-of-way will be critical to our ability to pursue expansion projects.
Should the FERC determine not to authorize rates equal to or greater than our costs of service, our cash flow would be negatively affected. 68 Table of Contents Index to Financial Statements Our midstream and intrastate gas and oil transportation pipelines and our intrastate gas storage operations are subject to state regulation.
Should the FERC determine not to authorize rates equal to or greater than our costs of service, our cash flow would be negatively affected. Our midstream and intrastate gas and oil transportation pipelines and our intrastate gas storage operations are subject to state regulation.
Energy Transfer indirectly owns all of the IDRs of Sunoco LP. These IDRs entitle the holder to receive increasing percentages of total cash distributions made by Sunoco LP as such entity reaches established target cash distribution levels as specified in its 80 Table of Contents Index to Financial Statements partnership agreement.
Energy Transfer indirectly owns all of the IDRs of Sunoco LP. These IDRs entitle the holder to receive increasing percentages of total cash distributions made by Sunoco LP as such entity reaches established target cash distribution levels as specified in its partnership agreement.
Our Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. 89 Table of Contents Index to Financial Statements Tax gain or loss on disposition of our units could be more or less than expected.
Our Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. Tax gain or loss on disposition of our units could be more or less than expected.
In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions.
In June 2016, the EPA published NSPS, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions.
For example, in the Consolidated Appropriations Bill for Fiscal Year 2021, Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemaking, To that end, PHMSA issued the three final rules discussed above, significantly expanding reporting and safety requirements of operators of gas gathering pipelines, imposing safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators, and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures.
Upon reauthorization of PHMSA, Congress directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemaking, To that end, PHMSA issued the three final rules discussed above, significantly expanding reporting and safety requirements of operators of gas gathering pipelines, imposing safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators, and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures.
The IRA 2022 amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and 60 Table of Contents Index to Financial Statements natural gas production categories.
The IRA 2022 amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production categories.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeIn an effort to mitigate these risks, before contracting with certain technology service providers, when possible, we conduct due diligence to evaluate their cybersecurity capabilities. Additionally, we endeavor to include cybersecurity requirements in our contracts with these providers and endeavor to require them to adhere to security standards and protocols.
Biggest changeEmployees are required to use multifactor authentication and keep their passwords confidential, among other measures. We recognize that third-party service providers may introduce cybersecurity risks. In an effort to mitigate these risks, before contracting with certain technology service providers, when possible, we conduct due diligence to evaluate their cybersecurity capabilities.
Risk Factors— Cybersecurity attacks, data breaches and other disruptions affecting us, our service providers, could materially and adversely affect our business, operations, reputation, and financial results; and —Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.” Board of Directors’ Oversight and Management’s Role Our Chief Information Officer oversees the Partnership’s functions of IT, cybersecurity, infrastructure and IT governance (including the Partnership’s IT team) and has more than 35 years of experience leading business technology functions.
Risk Factors— Cybersecurity attacks, data breaches and other disruptions affecting us, or our service providers, could materially and adversely affect our business, operations, reputation, and financial results; and —Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.” Board of Directors’ Oversight and Management’s Role Our Chief Information Officer oversees the Partnership’s functions of IT, cybersecurity, infrastructure and IT governance (including the Partnership’s IT team) and has more than 35 years of experience leading business technology functions.
Coast Guard (USCG), we seek to follow industry cybersecurity standards and protect our infrastructure against cyber attacks from domestic and international threats. We seek to use a defense-in-depth approach for cybersecurity management, layers of technology, policies and training at all levels of the enterprise designed to keep the Partnership’s assets secure and operational.
Coast Guard (USCG), we seek to follow industry cybersecurity standards and protect our infrastructure against cyber attacks from domestic and international threats. 94 Table of Contents Index to Financial Statements We seek to use a defense-in-depth approach for cybersecurity management, layers of technology, policies and training at all levels of the enterprise designed to keep the Partnership’s assets secure and operational.
The members of this team have over 50 years of combined experience in the field of IT, including 20 years dedicated to cybersecurity, and hold various certifications, including Global Industrial Cyber Security Professional (GICSP), Certified Information Systems Security Professional (CISSP) and Certified Ethical Hacker (CEH) certifications.
The members of this team have over 50 years of combined experience in the field of IT, including 20 years dedicated to cybersecurity, and hold 95 Table of Contents Index to Financial Statements various certifications, including Global Industrial Cyber Security Professional (GICSP), Certified Information Systems Security Professional (CISSP) and Certified Ethical Hacker (CEH) certifications.
Impact of Risks from Cybersecurity Threats As of the date of this Annual Report on Form 10-K, though the Partnership and our service providers have experienced certain cybersecurity incidents, we are not aware of any previous cybersecurity threats that have materially affected the Partnership, either financially or operationally.
As of the date of this Annual Report on Form 10-K, though the Partnership and our service providers have experienced certain cybersecurity incidents, we are not aware of any cybersecurity threats that have materially affected, or are reasonably likely to materially affect, the Partnership, either financially or operationally.
All employees who have access to our systems are required to undergo annual cybersecurity training and, each year, our employees must review and acknowledge our cybersecurity policies. Further, our IT team is trained to understand how to manage, use and protect personally identifiable information.
All employees who have access to our systems are required to undergo annual cybersecurity training and, each year, our employees must review and acknowledge our cybersecurity policies. Further, our IT team is trained to understand how to manage, use and protect personally identifiable information. User access controls have been implemented to limit unauthorized access to sensitive information and critical systems.
Management also updates the Audit Committee as new risks are identified and the steps taken to mitigate such risks.
Management also updates the Audit Committee as new risks are identified and regarding the steps taken to mitigate such risks. The Audit Committee reviews periodic reporting and updates regarding our cybersecurity risk management.
Further, we also endeavor to engage with any third-party service providers with access to personally identifiable employee information to evaluate their security controls. Finally, the Partnership maintains cybersecurity insurance coverage.
Additionally, we endeavor to include cybersecurity requirements in our contracts with these providers and endeavor to require them to adhere to security standards and protocols. Further, we also endeavor to engage with any third-party service providers with access to personally identifiable employee information to evaluate their security controls. Finally, the Partnership maintains cybersecurity insurance coverage.
Removed
User access controls have been implemented to limit unauthorized access to sensitive 93 Table of Contents Index to Financial Statements information and critical systems. Employees are required to use multifactor authentication and keep their passwords confidential, among other measures. We recognize that third-party service providers may introduce cybersecurity risks.
Added
Impact of Risks from Cybersecurity Threats The energy industry’s increasing dependence on information technology and operational technology to support critical functions, such as energy distribution and management activities, has heightened its vulnerability to cybersecurity incidents. Consequently, the global surge in cybersecurity incidents, whether caused by intentional attacks or accidental events, presents a significant challenge to our sector.
Added
As cybersecurity threats grow in complexity and scale, preventing, detecting, mitigating and remediating these incidents remains a continuous and increasingly demanding task for the industry. Compliance with evolving cybersecurity reporting requirements, such as those mandated by FERC, presents significant challenges. These regulations necessitate timely and detailed reporting of cyber incidents, demanding substantial resources and robust internal processes to ensure adherence.
Added
Failure to comply could result in legal penalties, increased regulatory scrutiny and reputational damage. Moreover, the dynamic nature of these requirements may lead to overlapping or inconsistent obligations, further complicating compliance efforts. Monitoring these developments and integrating them into our cybersecurity and compliance frameworks is essential to mitigate potential risks.

Item 2. Properties

Properties — owned and leased real estate

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Biggest changeIn addition, we believe that 94 Table of Contents Index to Financial Statements we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.
Biggest changeIn addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeOn June 29, 2022, near Henderson, Tennessee, a Mid Valley mowing contractor struck an exposed section of the 22-inch diameter Hornsby to Denver line segment while mowing. The brush cutter mowing implement cut open the pipeline and released an estimated 4,345 barrels of crude oil into the surrounding area.
Biggest changeOnce discovery has been completed, Transwestern will be able to provide an assessment of the potential outcome or range of potential liability, if any. Trial has been set for August 2025. On June 29, 2022, near Henderson, Tennessee, a Mid Valley mowing contractor struck an exposed section of the 22-inch diameter Hornsby to Denver line segment while mowing.
While we believe that even if any one or more of the following environmental proceedings were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report environmental governmental proceedings if we reasonably believe that such proceedings reasonably could result in monetary sanctions in excess of $0.3 million.
While we believe that even if any one or more of the following environmental proceedings were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report environmental governmental proceedings if we reasonably believe that such proceedings reasonably could result in monetary sanctions in excess of $1 million (previously $0.3 million).
ITEM 3. LEGAL PROCEEDINGS For information regarding legal proceedings, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report on Form 10-K for the year ended December 31, 2023.
ITEM 3. LEGAL PROCEEDINGS For information regarding legal proceedings, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report on Form 10-K for the year ended December 31, 2024.
Additional environmental work was completed in late August 2023 along the pipeline right-of-way to address a small oil seep which required soil removal and site restoration. The TN DEC was notified and a follow-up report will be submitted to the agency documenting completion.
Additional environmental work was completed in late August 2023 along the pipeline right-of-way to address a small oil seep which required soil removal and site restoration. The TDEC was notified and a follow-up report will be submitted to the agency documenting completion.
Enforcement Staff has provided Rover with a notice pursuant to Section 1b.19 of the FERC’s regulations that Enforcement Staff intends to recommend that the FERC pursue an enforcement action against Rover and the Partnership. The company disagrees with Enforcement Staff’s findings and intends to vigorously defend against any potential penalty.
Rover and the Partnership are cooperating with the investigation. Enforcement Staff has provided Rover with a notice pursuant to Section 1b.19 of the FERC’s regulations that Enforcement Staff intends to recommend that the FERC pursue an enforcement action against Rover and the Partnership. The Partnership disagrees with Enforcement Staff’s findings and intends to vigorously defend against any potential penalty.
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.
An adverse determination with respect to one or more of the MTBE cases could 96 Table of Contents Index to Financial Statements 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.
The release purportedly occurred in October 2014 on a nature preserve located in Hamilton County, Ohio, near Cincinnati, Ohio. After discovery and notification of the release, SPLP conducted substantial emergency response, remedial work and primary restoration in three phases and the primary restoration has been acknowledged to be complete. Operation and maintenance (O&M) activities will continue for several years.
The release purportedly occurred in October 2014 on a nature preserve located in Hamilton County, Ohio, near Cincinnati, Ohio. After discovery and notification of the release, SPLP conducted substantial emergency response, remedial work and primary restoration in three phases and the primary restoration has been acknowledged to be complete.
Corrective action was being completed pursuant to the Tennessee DEC’s Division of Remediation - Voluntary Action Program (“VAP”) and on May 23, 2023, Mid Valley received a No Further Action letter from the Tennessee Department of Environment and Conservation (“TN DEC”) for the corrective action work related to the incident.
Corrective action was completed pursuant to the Tennessee Department of Environment and Conservation's ("TDEC") Division of Remediation -Voluntary Action Program ("VAP") and on May 23, 2023, Mid Valley received a No Further Action letter from the TDEC for the corrective action work related to the incident.
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.
At a June 2, 2022, status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions 97 Table of Contents Index to Financial Statements to dismiss the Fourth Amended Complaint. On August 1, 2022, Rover and the other remaining defendant each filed their respective motions.
The NOPV related to a PHMSA Accident Investigation Division investigation of a pigging incident which occurred on March 26, 2020 at the Partnership’s Borcher Station in Kansas and resulted in a fatality.
The NOPV related to a PHMSA Accident Investigation Division investigation of a pigging incident which occurred on March 26, 2020 at the Partnership’s Borcher Station in Kansas and resulted in a fatality. The Partnership challenged PHMSA’s alleged violations and related civil penalties and compliance order actions contained in the NOPV.
On June 26, 2023, Plaintiffs Michael and Cecilia Weinman (collectively, “Plaintiffs”) filed suit in Chester County, Tennessee, against Mid Valley, Energy Transfer Crude Marketing LLC, Energy Transfer Crude Oil Company, LLC, Energy Transfer Employee Management LLC, Energy Transfer Marketing & Terminals L.P., Energy Transfer LP, (collectively, the “Energy Transfer Defendants”) and other unnamed defendants asserting claims for negligence, trespass, and other tort claims and alleging damage to their property stemming from the crude oil release.
No injuries resulted from the incident. On June 26, 2023, Plaintiffs Michael and Cecilia Weinman ("Plaintiffs") filed suit in Chester County, Tennessee, against Mid Valley and other Energy Transfer defendants asserting claims for negligence, trespass, and other tort claims and alleging damage to their property stemming from the crude oil release.
At this time, we cannot determine the likelihood of any liability in this 97 Table of Contents Index to Financial Statements matter; however, Sunoco intends to defend and dispute the allegations of the lawsuit, including but not limited to the joint and several liability determination sought.
At this time, we cannot determine the likelihood of any liability in this matter; however, Sunoco intends to defend and dispute the allegations of the lawsuit, including but not limited to the joint and several liability determination sought. This lawsuit is included among the matters described in our discussion of our other environmental remediation matters.
The FERC and District Court proceedings remain stayed pending resolution of the case pending before the United States Supreme Court. 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.
The FERC and District Court proceedings remain stayed at this time. Energy Transfer and Rover intend to vigorously defend this claim. 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.
On August 8, 2023, Plaintiffs filed a notice of voluntary dismissal of their lawsuit without prejudice. On November 29, 2023, the United States Coast Guard issued the final invoice for all federal expenses related to the incident response in the amount of $90,000. The expenses have been validated and sent for payment.
On or about September 13, 2024, Plaintiffs filed a notice of voluntary dismissal of their latest lawsuit without prejudice. 98 Table of Contents Index to Financial Statements On November 29, 2023, the United States Coast Guard issued the final invoice for all federal expenses related to the incident response in the amount of $90,000.
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 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. On November 13, 2023, the FERC appealed the District Court order to the United States Court of Appeals for the Fifth Circuit.
On August 31, 2023, the United States Department of Justice filed suit in the District Court for the Southern District of Texas (Corpus Christi Division) captioned as United States v. Energy Transfer (R&M), LLC et al.
The Partnership is also in the process of evaluating any other legal options that may be available to it for challenging the agency action. On August 31, 2023, the United States Department of Justice filed suit in the District Court for the Southern District of Texas (Corpus Christi Division) captioned as United States v. Energy Transfer (R&M), LLC et al.
Approximately 3,343 barrels of crude oil were 96 Table of Contents Index to Financial Statements recovered during initial remediation activities with the remaining volume contained within the materials removed and disposed of in accordance with applicable environmental laws and regulations.
The brush cutter mowing implement cut open the pipeline and released an estimated 4,345 barrels of crude oil into the surrounding area. Approximately 3,343 barrels of crude oil were recovered during initial remediation activities with the remaining volume contained within the materials removed and disposed of in accordance with applicable environmental laws and regulations.
By order issued on October 20, 2023, the trial judge dismissed the Ohio EPA’s Fourth Amended Petition. 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.
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 Petition. On November 17, 2023, the State of Ohio appealed the trial judge’s decision to Ohio’s Fifth District Court of Appeals.
On October 13, 2023, Mid Valley received a Notice of Proposed Safety Order (NOPSO) from PHMSA related to this incident and other historical incidents on the Mid Valley system. Several actions over the next six months are requested in the NOPSO and a response is due within 30 days. No other government agency action has occurred.
On October 13, 2023, Mid Valley received a Notice of Proposed Safety Order ("NOPSO") from PHMSA related to this incident and other historical incidents on the Mid Valley pipeline system. No other government agency action has occurred. Groundwater monitoring wells were abandoned on June 12, 2023, which concluded environmental related activities associated with the incident site.
Hector Balderas, Attorney General filed a complaint against ETO, Transwestern, Kinder Morgan, Inc., El Paso Natural Gas LLC and Northwest Pipeline, LLC in Cause No.
Operation and maintenance (O&M) activities will continue for several years. On February 3, 2022, the State of New Mexico, ex rel. Hector Balderas, Attorney General filed a complaint against ETO, Transwestern, Kinder Morgan, Inc., El Paso Natural Gas L.L.C. and Northwest Pipeline, LLC in Cause No.
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 95 Table of Contents Index to Financial Statements appeal, which the Fifth Circuit granted on December 12, 2023.
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. The Supreme Court issued a decision in that case on June 27, 2024.
The Energy Transfer Defendants cannot predict the ultimate outcome of this litigation or the amount of time and expense that will be required to resolve it. On October 13, 2023, Mid Valley received a Notice of Proposed Safety Order (“NOPSO”) from the PHMSA related to various historical accidents and complaints reported to PHMSA on the Mid Valley system.
The expenses have been validated and sent for payment. The Energy Transfer Defendants cannot predict the ultimate outcome of this litigation or the amount of time and expense that will be required to resolve it.
Removed
The DOJ, on behalf of United States Department of Interior Fish and Wildlife, and the Ohio Attorney General, on behalf of the Ohio EPA, along with technical representatives from those agencies have resolved in principal the natural resource damage assessment claims related to state endangered species and compensatory restoration. On February 3, 2022, the State of New Mexico, ex rel.
Added
The State filed its initial brief on January 8, 2024 and Energy Transfer’s and Rover’s responsive brief was filed February 20, 2024. The State filed a reply brief on February 26, 2024. Oral argument on the appeal was held on August 27, 2024. On October 1, 2024, Ohio’s Fifth District Court of Appeals affirmed the trial judge’s decision.
Removed
The complaint alleges discharge or release of PCBs into the natural environment from compressor stations in connection with the operation of the Transwestern Pipeline. Given the early stage of this proceeding, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any.
Added
The State of Ohio sought permission to appeal this decision from the Ohio State Supreme Court. Energy Transfer and Rover have opposed such permission. On January 28, 2025, the Ohio State Supreme Court declined to hear the State’s appeal.
Removed
Groundwater monitoring wells were abandoned on June 12, 2023, which concluded environmental related activities associated with the incident site. No injuries resulted from the incident.
Added
The State of Ohio could seek reconsideration of this Order with the Ohio Supreme Court or attempt to seek review from the U.S. Supreme Court. Energy Transfer and Rover intend to vigorously defend this claim.
Removed
The Partnership challenged PHMSA’s alleged violations and related civil penalties and compliance order actions contained in the NOPV, and requested an administrative hearing, which is set for April 24, 2024 before a PHMSA Presiding Official.
Added
In September of 2024, after a public comment period, the United States District Court for the Southern District of Ohio (Western Division) entered a Consent Decree whereby SPLP and Mid Valley resolved both the civil penalty as well as alleged natural resource damages (NRD) brought jointly by the DOJ, on behalf of United States Department of Interior Fish and Wildlife, and the Ohio Attorney General, on behalf of the Ohio EPA.
Removed
This lawsuit is included among the matters described in our discussion of our other environmental remediation matters. Please see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Added
The complaint alleges discharge or release of PCBs into the natural environment from compressor stations in connection with the operation of Transwestern. The parties completed document discovery and depositions of factual witnesses in December 2024 and will begin taking expert depositions in March 2025.
Added
On August 8, 2023, Plaintiffs filed a notice of voluntary dismissal of their lawsuit without prejudice. On or about August 7, 2024, Plaintiffs refiled their suit with slight modifications and removing their negligence per se claim in Chester County, Tennessee. On or about August 27, 2024, the first two Energy Transfer defendants were served.
Added
On October 13, 2023, Mid Valley received a NOPSO from the PHMSA related to various historical accidents and complaints reported to PHMSA on the Mid Valley system.
Added
After an administrative hearing, which was held on April 24, 2024 before a PHMSA Presiding Official, the PHMSA Southwest Region recommended to remain relatively firm on the NOPV, with only a slightly reduced civil penalty of approximately $2,455,312. The Partnership has challenged the PHMSA recommendation and is also currently challenging certain procedural events which occurred following the administrative hearing.
Added
Please see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” On February 13, 2025, SPLP received a Notice of Proposed Safety Order (“NOPSO”) from the PHMSA related to a release of jet fuel on the Twin Oaks Discharge pipeline system in Bucks County, Pennsylvania.
Added
The NOPSO made certain preliminary findings and proposes that SPLP take certain measures with respect to the system to ensure safety. SPLP plans to submit a written response within the 30-day response period. It is too early to predict the outcome, timeline, or costs associated with this administrative action.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeEnergy Transfer Preferred Units As of December 31, 2023, the Partnership had the following series of preferred units outstanding: Series of Preferred Units Units Issued and Outstanding Liquidation Preference per Unit Date Issued (1) Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units 950,000 $ 1,000 April 2021 Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units 550,000 1,000 April 2021 Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units 18,000,000 25 April 2021 Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units 17,800,000 25 April 2021 Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units 32,000,000 25 April 2021 Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units 500,000 1,000 April 2021 Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units 1,484,780 1,000 April 2021 and December 2021 (2) Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units 900,000 1,000 June 2021 Series I Fixed Rate Perpetual Preferred Units 41,464,179 9.1273 November 2023 (3) (1) In connection with the Rollup Mergers on April 1, 2021, as discussed in Note 1 to our consolidated financial statements included in “Item 8.
Biggest changeEnergy Transfer Preferred Units As of December 31, 2024, the Partnership had the following series of preferred units outstanding: Series of Preferred Units Units Issued and Outstanding Liquidation Preference per Unit Date Issued Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units 550,000 $ 1,000 April 2021 Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units 500,000 1,000 April 2021 Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units 1,484,780 1,000 April 2021 and December 2021 (1) Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units 900,000 1,000 June 2021 Series I Fixed Rate Perpetual Preferred Units 41,464,179 9.1273 November 2023 (2) (1) In connection with the Enable acquisition in December 2021, Energy Transfer issued 384,780 additional Series G Preferred Units.
Common units represent limited partner interests in us that entitle the holders to the rights and privileges specified in Energy Transfer’s Partnership Agreement. As of December 31, 2023, limited partners own an aggregate 99.9% limited partner interest in us. Our General Partner owns an aggregate 0.1% general partner interest in us.
Common units represent limited partner interests in us that entitle the holders to the rights and privileges specified in Energy Transfer’s Partnership Agreement. As of December 31, 2024, limited partners own an aggregate 99.9% limited partner interest in us. Our General Partner owns an aggregate 0.1% general partner interest in us.
The total reflected above includes these additional Series G Preferred Units, as well as the 1,100,000 Series G Preferred Units originally issued in the Rollup Mergers. (3) The Series I Preferred Units were issued in connection with the Crestwood acquisition in November 2023.
The total reflected above includes these additional Series G Preferred Units, as well as the 1,100,000 Series G Preferred Units originally issued in the Rollup Mergers. (2) The Series I Preferred Units were issued in connection with the Crestwood acquisition in November 2023.
ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Description of Units As of February 9, 2024, there were 11,242 holders of record of our common units, which number does not separately account for individual participants in securities positions listings.
ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Description of Units As of February 7, 2025, there were 10,402 holders of record of our common units, which number does not separately account for individual participants in securities positions listings.
The common units are entitled to distributions of Available Cash as described in “Cash Distribution Policy.” Energy Transfer Class A Units As of February 9, 2024, the Partnership had outstanding 833,543,364 Class A units (“Energy Transfer Class A Units”) representing limited partner interests in the Partnership to the General Partner.
The common units are entitled to distributions of Available Cash as described in “Cash Distribution Policy.” Energy Transfer Class A Units As of February 7, 2025, the Partnership had outstanding 849,249,512 Class A units (“Energy Transfer Class A Units”) representing limited partner interests in the Partnership to the General Partner.
Energy Transfer will distribute all of its “Available Cash” to its Unitholders and its General Partner within 50 days following the end of each fiscal quarter. Definition of Available Cash.
Financial Statements and Supplementary Data." 100 Table of Contents Index to Financial Statements Cash Distribution Policy General. Energy Transfer will distribute all of its “Available Cash” to its Unitholders and its General Partner within 50 days following the end of each fiscal quarter. Definition of Available Cash.
Additional information for each series of outstanding preferred units, including information on distributions and redemption, is available in Note 8 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." Cash Distribution Policy General.
The Partnership redeemed all of the Series A Preferred Units, Series C Preferred Units, Series D Preferred Units and Series E Preferred Units during 2024. Additional information for each series of outstanding preferred units, including information on distributions and redemption, is available in Note 8 to our consolidated financial statements included in "Item 8.
Removed
Financial Statements and Supplementary Data,” all of ETO’s previously outstanding preferred units were converted to Energy Transfer Preferred Units with identical distribution and redemption rights. 99 Table of Contents Index to Financial Statements (2) In connection with the Enable acquisition in December 2021, Energy Transfer issued 384,780 additional Series G Preferred Units.
Removed
In February 2024, the Partnership redeemed all of the Series C Preferred Units and Series D Preferred Units. The Partnership expects to redeem all of the Series E Preferred Units in May 2024.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

135 edited+54 added−40 removed115 unchanged
Biggest changeFor the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following: • an increase of $427 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $275 million increase from recently acquired assets, a $157 million increase from higher volumes on our Bakken Pipeline, a $71 million increase from higher volumes on our Texas crude pipeline system, a $31 million increase from our Nederland and Houston crude terminals due to higher throughput and exports and a $17 million increase from our Midcontinent gathering systems, partially offset by a $135 million decrease from our crude oil acquisition and marketing business due primarily to less favorable pricing and higher affiliate fees from higher volumes transported; • a decrease of $104 million in selling, general and administrative expenses primarily due to a charge related to a legal matter in the prior period; and • an increase of $15 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired and higher volumes on our White Cliffs crude pipeline; partially offset by 113 Table of Contents Index to Financial Statements • an increase of $54 million in operating expenses primarily due to a $66 million increase from recently acquired assets, a $13 million increase in volume-driven expenses and an $8 million increase in employee-related expenses, partially offset by a $4 million decrease in measurement expenses, a $5 million decrease in ad valorem taxes and a $20 million decrease in maintenance project expenses.
Biggest changeFor the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impact of the following: • an increase of $670 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $541 million increase from recently acquired assets and assets contributed upon the recent formation of the ET-S Permian joint venture, a $122 million increase in transportation revenues from existing assets and a $7 million increase in our crude oil acquisition and marketing business from more favorable market conditions; and • an increase of $9 million in Adjusted EBITDA related to unconsolidated affiliates due to recently acquired assets and higher volumes on our White Cliffs crude pipeline; partially offset by • an increase of $153 million in operating expenses primarily due to a $106 million increase from recently acquired assets and assets contributed upon the recent formation of the ET-S Permian joint venture, a $15 million increase in outside services, an $11 million increase in ad valorem taxes, a $10 million increase in employee expenses and various increases in volume-driven expenses; and • an increase of $29 million in selling, general and administrative expenses primarily due to a $27 million increase from recently acquired assets and assets contributed upon the recent formation of the ET-S Permian joint venture, as well as higher employee costs. 114 Table of Contents Index to Financial Statements Investment in Sunoco LP Years Ended December 31, 2024 2023 Change Revenues $ 22,693 $ 23,068 $ (375) Cost of products sold 20,595 21,703 (1,108) Segment margin 2,098 1,365 733 Unrealized (gains) losses on commodity risk management activities 12 (21) 33 Operating expenses, excluding non-cash compensation expense (611) (420) (191) Selling, general and administrative, excluding non-cash compensation expense (266) (113) (153) Adjusted EBITDA related to unconsolidated affiliates 101 10 91 Inventory valuation adjustments 86 114 (28) Other, net 37 29 8 Segment Adjusted EBITDA $ 1,457 $ 964 $ 493 The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
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.
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.
Financial Statements and Supplementary Data.” Inventory Valuation Adjustments. Inventory valuation adjustments represent changes in lower of cost or market using the last-in, first-out method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period.
Financial Statements and Supplementary Data.” Inventory Valuation Adjustments (Sunoco LP). Inventory valuation adjustments represent changes in lower of cost or market using the last-in, first-out method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period.
Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report.
Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risks and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report.
Among the key risk factors that may have a direct bearing on our results of operations and financial condition are: • the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition; • the actual amount of cash distributions by our subsidiaries to us; • the volumes transported on our subsidiaries’ pipelines and gathering systems; • the level of throughput in our subsidiaries’ processing and treating facilities; • the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services; • the prices and market demand for, and the relationship between, natural gas and NGLs; • energy prices generally; • impacts of world health events; • the possibility of cyber and malware attacks; • the prices of natural gas and NGLs compared to the price of alternative and competing fuels; • the general level of petroleum product demand and the availability and price of NGL supplies; • the level of domestic oil, natural gas and NGL production; • the availability of imported oil, natural gas and NGLs; • actions taken by foreign oil and gas producing nations; • the political and economic stability of petroleum producing nations; • the effect of weather conditions on demand for oil, natural gas and NGLs; • availability of local, intrastate and interstate transportation systems; • the continued ability to find and contract for new sources of natural gas supply; • availability and marketing of competitive fuels; • the impact of energy conservation efforts; • energy efficiencies and technological trends; 128 Table of Contents Index to Financial Statements • governmental regulation and taxation; • changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines; • hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs; • competition from other midstream companies and interstate pipeline companies; • loss of key personnel; • loss of key natural gas producers or the providers of fractionation services; • reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities; • the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments; • the nonpayment or nonperformance by our subsidiaries’ customers; • risks related to the development of new infrastructure projects or other growth projects, including failure to make sufficient progress to justify continued development, delays in obtaining customers, increased costs of financing and regulatory, environmental, political and legal uncertainties that may affect the timing and cost of these projects; • risks associated with the construction of new pipelines, treating and processing facilities or other facilities, or additions to our subsidiaries’ existing pipelines and their facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors; • the availability and cost of capital and our subsidiaries’ ability to access certain capital sources; • a deterioration of the credit and capital markets; • risks associated with the assets and operations of entities in which our subsidiaries own a noncontrolling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence; • the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses; • changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; • the costs and effects of legal and administrative proceedings; and • risks associated with a potential failure to successfully combine our business with that of Crestwood.
Among the key risk factors that may have a direct bearing on our results of operations and financial condition are: • the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition; • the actual amount of cash distributions by our subsidiaries to us; • the volumes transported on our subsidiaries’ pipelines and gathering systems; • the level of throughput in our subsidiaries’ processing and treating facilities; • the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services; • the prices and market demand for, and the relationship between, natural gas and NGLs; • energy prices generally; • impacts of world health events; • the possibility of cyber and malware attacks; • the prices of natural gas and NGLs compared to the price of alternative and competing fuels; • the general level of petroleum product demand and the availability and price of NGL supplies; • the level of domestic oil, natural gas and NGL production; • the availability of imported oil, natural gas and NGLs; 129 Table of Contents Index to Financial Statements • actions taken by foreign oil and gas producing nations; • the political and economic stability of petroleum producing nations; • the effect of weather conditions on demand for oil, natural gas and NGLs; • availability of local, intrastate and interstate transportation systems; • the continued ability to find and contract for new sources of natural gas supply; • availability and marketing of competitive fuels; • the impact of energy conservation efforts; • energy efficiencies and technological trends; • governmental regulation, taxation and tariffs; • changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines; • hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs; • competition from other midstream companies and interstate pipeline companies; • loss of key personnel; • loss of key natural gas producers or the providers of fractionation services; • reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities; • the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments; • the nonpayment or nonperformance by our subsidiaries’ customers; • risks related to the development of new infrastructure projects or other growth projects, including failure to make sufficient progress to justify continued development, delays in obtaining customers, increased costs of financing and regulatory, environmental, political and legal uncertainties that may affect the timing and cost of these projects; • risks associated with the construction of new pipelines, treating and processing facilities or other facilities, or additions to our subsidiaries’ existing pipelines and their facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors; • the availability and cost of capital and our subsidiaries’ ability to access certain capital sources; • a deterioration of the credit and capital markets; • risks associated with the assets and operations of entities in which our subsidiaries own a noncontrolling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence; • the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses; • changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; • the costs and effects of legal and administrative proceedings; and • risks associated with a potential failure to successfully combine our business with those of companies we have acquired or may acquire in the future.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Tabular dollar and unit amounts, except per unit data, are in millions) Energy Transfer LP is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ET.” The following discussion of our consolidated financial condition and results of operations for the years ended December 31, 2023 and 2022 should be read in conjunction with our consolidated financial statements and accompanying notes thereto included in “Item 8.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Tabular dollar and unit amounts, except per unit data, are in millions) Energy Transfer LP is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ET.” The following discussion of our consolidated financial condition and results of operations for the years ended December 31, 2024 and 2023 should be read in conjunction with our consolidated financial statements and accompanying notes thereto included in “Item 8.
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.
Panhandle filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023.
These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure. 108 Table of Contents Index to Financial Statements • Non-cash compensation expense .
These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included 109 Table of Contents Index to Financial Statements in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure. • Non-cash compensation expense .
The amount of cash that our subsidiaries distribute to us is based on earnings from their respective business activities and the amount of available cash. Energy Transfer’s primary cash requirements are for distributions to its partners, general and administrative expenses and debt service requirements.
The amount of cash that our subsidiaries distribute to us is based on earnings from their respective business activities and the amount of available cash. Energy Transfer’s primary cash requirements are for distributions to its partners, capital expenditures, general and administrative expenses and debt service requirements.
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.
The Partnership used the net proceeds to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility (defined below), to redeem its outstanding Series C Preferred Units and Series D Preferred Units and for general partnership purposes. The Partnership also used the proceeds to redeem its Series E Preferred Units in May 2024.
Pipeline Certification The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects.
Pipeline Certification The FERC issued a Notice of Inquiry (“NOI”) on April 19, 2018, thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects.
Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the year ended December 31, 2023 represent the actual results in all material respects.
Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the year ended December 31, 2024 represent the actual results in all material respects.
Trends and Outlook Overall, we believe the Partnership’s outlook is strong, as it has a stable business that has demonstrated its ability to manage through various market cycles. We expect future growth to be supported by production improvements, improved market conditions, and increased utilization of our existing assets, as well as strong domestic and international demand for our products.
Trends and Outlook Overall, we continue to believe the Partnership’s outlook is strong, as it has a stable business that has demonstrated its ability to manage through various market cycles. We expect future growth to be supported by production improvements and increased utilization of our existing assets, as well as continued strong domestic and international demand for our products.
Discussion and analysis of matters pertaining to the year ended December 31, 2021 and year-to-year comparisons between the years ended December 31, 2022 and 2021 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2022 that was filed with the SEC on February 17, 2023.
Discussion and analysis of matters pertaining to the year ended December 31, 2022 and year-to-year comparisons between the years ended December 31, 2023 and 2022 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2023 that was filed with the SEC on February 16, 2024.
Financial Statements and Supplementary Data.” 115 Table of Contents Index to Financial Statements We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions.
Financial Statements and Supplementary Data.” We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions.
As of December 31, 2023 and 2022, accruals of $285 million and $200 million, respectively, were reflected in our consolidated balance sheets related to these contingent obligations. For more information on our litigation and contingencies, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this annual report. Environmental Remediation Activities.
As of December 31, 2024 and 2023, accruals of $281 million and $285 million, respectively, were reflected in our consolidated balance sheets related to these contingent obligations. For more information on our litigation and contingencies, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this annual report. Environmental Remediation Activities.
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; 120 Table of Contents Index to Financial Statements • 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 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.
Distributions to partners increased between the periods as a result of increases in the number of common units outstanding or increases in the distribution rate. Following is a summary of financing activities by period: Year Ended December 31, 2023 Cash used in financing activities was $5.33 billion in 2023.
Distributions to partners increased between the periods as a result of increases in the number of common units outstanding or increases in the distribution rate. Following is a summary of financing activities by period: Year Ended December 31, 2024 Cash used in financing activities was $5.45 billion in 2024.
We are unable to predict what, if any, changes may be proposed as a result of the 2022 Policy Statements that might affect our natural gas pipeline or LNG facility projects, or when such new policies, if any, might become effective.
We are unable to predict what, if any, changes may be proposed as a result of the 2022 Certificate Policy Statement that might affect our natural gas pipeline or LNG facility projects, or when such new policy, if any, might become effective.
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.
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.” 124 Table of Contents Index to Financial Statements 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.
Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheets reflected $277 million and $282 million in environmental accruals as of December 31, 2023 and 2022, respectively.
Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheets reflected $278 million and $277 million in environmental accruals as of December 31, 2024 and 2023, respectively.
On March 24, 2022, the FERC issued an order designating the 2022 Policy Statements as draft policy statements, and requested further comments. The FERC will not apply the now draft 2022 Policy Statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics.
On March 24, 2022, the FERC issued an order designating the 2022 Certificate Policy Statement and the GHG Policy Statement as draft policy statements, and requested further comments. The FERC stated that it will not apply the now draft policy statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics.
The 103 Table of Contents Index to Financial Statements indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years. On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%.
The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years. On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%.
Our Leverage Ratio was 3.31 to 1.00 at December 31, 2023, as calculated in accordance with the credit agreement.
Our Leverage Ratio was 3.12 to 1.00 at December 31, 2024, as calculated in accordance with the credit agreement.
Air Quality Standards The EPA recently finalized its Good Neighbor Plan (the “Plan”) which seeks to reduce nitrogen oxide pollution from power plants and other industrial facilities from 23 upwind states which the EPA determined is contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and interfering with maintenance of the 2015 ozone NAAQS in downwind states.
Air Quality Standards In 2023, the United States Environmental Protection Agency (“EPA”) finalized its Good Neighbor Plan (the “Plan”) which seeks to reduce nitrogen oxide pollution from power plants and other industrial facilities from 23 upwind states which the EPA determined is contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and interfering with maintenance of the 2015 ozone NAAQS in downwind states.
We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally expect to funds growth capital expenditures with proceeds of borrowings under our credit facilities, along with cash from operations. Sunoco LP expects to invest at least $200 million in growth capital expenditures and approximately $70 million in maintenance capital expenditures in 2024.
We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally expect to funds growth capital expenditures with proceeds of borrowings under our credit facilities, along with cash from operations. Sunoco LP expects to invest at least $400 million in growth capital expenditures and approximately $150 million in maintenance capital expenditures in 2025.
We do not expect that any change in these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the United States. Interstate Common Carrier Regulation Liquids pipelines transporting in interstate commerce are regulated by FERC as common carriers under the Interstate Commerce Act (“ICA”).
We do not expect that any change in this policy statement would affect us in a materially different manner than any other natural gas pipeline company operating in the United States. Interstate Common Carrier Regulation Liquids pipelines transporting in interstate commerce are regulated by FERC as common carriers under the ICA.
The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material.
The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to 128 Table of Contents Index to Financial Statements adverse developments with respect to any individual site is not expected to be material.
The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, but also other pipeline costs that will continue to affect FERC’s determination of just and reasonable cost-of-service rates.
The FERC’s establishment of a just and reasonable rate is based on many 103 Table of Contents Index to Financial Statements components, including ROE and tax-related components, but also other pipeline costs that will continue to affect FERC’s determination of just and reasonable cost-of-service rates.
We expect to satisfy our working capital needs through cash generated by our operations. As of December 31, 2023, we had cash and cash equivalents of $161 million and availability under our revolving credit facility of $3.56 billion. The Partnership’s material contractual obligations include long-term debt service, payments under operating leases and purchase commitments.
We expect to satisfy our working capital needs through cash generated by our operations. As of December 31, 2024, we had cash and cash equivalents of $312 million and availability under our revolving credit facility of $2.21 billion. The Partnership’s material contractual obligations include long-term debt service, payments under operating leases and purchase commitments.
In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are master limited partnerships. Energy Transfer derives cash flows from distributions related to its investment in its subsidiaries, including Sunoco LP and USAC.
In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are master limited partnerships. 101 Table of Contents Index to Financial Statements Energy Transfer derives cash flows from distributions related to its investment in its subsidiaries, including Sunoco LP and USAC.
The Partnership’s results of operations have not been significantly impacted by changes in the estimated useful lives of our long-lived assets during the periods presented, and we do not anticipate any such significant changes in the future.
Changes in the estimated useful lives of the assets could have a material effect on our results of operation. The Partnership’s results of operations have not been significantly impacted by changes in the estimated useful lives of our long-lived assets during the periods presented, and we do not anticipate any such significant changes in the future.
We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.
We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise. 130 Table of Contents Index to Financial Statements
The increase in transportation volumes and the commissioning of our eighth fractionator in August 2023 also led to higher fractionated volumes at our Mont Belvieu, Texas fractionation facility. Segment Margin .
The increase in transportation volumes and the commissioning of our eighth fractionator in August 2023 also led to higher fractionated volumes at our Mont Belvieu NGL Complex. Segment Margin .
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%.
As of December 31, 2024, USAC had $827 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $783 million was available to be drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2024 was 6.98%.
On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certification of New Interstate Natural Gas Facilities and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“2022 Policy Statements”), to be effective that same day.
On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certification of New Interstate Natural Gas Facilities (“2022 Certificate Policy Statement”) and (2) a Policy Statement on the Consideration of 104 Table of Contents Index to Financial Statements Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“GHG Policy Statement”), to be effective that same day.
In 2023, we had a net increase in our debt level of $714 million. During 2023, we paid distributions of $4.25 billion to our partners, we paid distributions of $1.69 billion to noncontrolling interests, and we paid distributions of $59 million to our redeemable noncontrolling interests. In addition, we received capital contributions of $3 million in cash from noncontrolling interests.
In 2023, we had a net increase in our debt level of $714 million. During 2023, we paid distributions of $4.25 billion to our partners, we paid distributions of $1.69 billion to noncontrolling interests and we paid distributions of $59 million to our redeemable noncontrolling interests.
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% 123 Table of Contents Index to Financial Statements 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 The total amount of distributions to the Partnership from Sunoco LP for the periods presented below is as follows: Years Ended December 31, 2023 2022 Distributions from Sunoco LP Limited Partner interests $ 96 $ 94 General Partner interest and IDRs 77 72 Total distributions from Sunoco LP $ 173 $ 166 USAC Cash Distributions Energy Transfer owns approximately 46.1 million USAC common units.
Marginal Percentage Interest in Distributions Total Quarterly Distribution Target Amount Common Unitholders Holder of IDRs Minimum Quarterly Distribution $0.4375 100% —% First Target Distribution $0.4375 to $0.503125 100% —% Second Target Distribution $0.503125 to $0.546875 85% 15% Third Target Distribution $0.546875 to $0.656250 75% 25% Thereafter Above $0.656250 50% 50% Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows: Quarter Ended Payment Date Rate December 31, 2022 February 21, 2023 $ 0.8255 March 31, 2023 May 22, 2023 0.8420 June 30, 2023 August 21, 2023 0.8420 September 30, 2023 November 20, 2023 0.8420 December 31, 2023 February 20, 2024 0.8420 March 31, 2024 May 20, 2024 0.8756 June 30, 2024 August 19, 2024 0.8756 September 30, 2024 November 19, 2024 0.8756 December 31, 2024 February 19, 2025 0.8865 The total amount of distributions to the Partnership from Sunoco LP for the periods presented below is as follows: Years Ended December 31, 2024 2023 Distributions from Sunoco LP Limited Partner interests $ 100 $ 96 General Partner interest and IDRs 145 77 Total distributions from Sunoco LP $ 245 $ 173 USAC Cash Distributions Energy Transfer owns approximately 46.1 million USAC common units.
We have material purchase commitments for crude oil; as of December 31, 2023, those purchase commitments totaled an estimated $65.27 billion (of which $21.80 billion would be due in 2024) based on either the current market price for variable price contracts or the contracted price for fixed price contracts.
We have material purchase commitments for crude oil; as of December 31, 2024, those purchase commitments totaled an estimated $50.34 billion (of which $22.45 billion would be due in 2025) based on either the current market price for variable price contracts or the contracted price for fixed price contracts.
Financial Statements and Supplementary Data.” Recent Transactions 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.
Energy Transfer 2024 Notes Issuance In January 2024, the Partnership issued $1.25 billion aggregate principal amount of 5.55% senior notes due 2034, $1.75 billion aggregate principal amount of 5.95% senior notes due 2054 and $800 million aggregate principal amount of 8.00% fixed-to-fixed reset rate junior subordinated notes due 2054.
Energy Transfer Common Unit Distributions Distributions declared and paid with respect to Energy Transfer 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 The total amounts of distributions declared and paid during the periods presented (all from Available Cash from Energy Transfer’s operating surplus and are shown in the period to which they relate) are as follows: Years Ended December 31, 2023 2022 Limited Partners $ 3,984 $ 3,089 General Partner interest 3 3 Total Energy Transfer distributions $ 3,987 $ 3,092 122 Table of Contents Index to Financial Statements 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 $33.75 $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 33.75 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 33.75 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 33.75 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 33.75 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 33.75 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.
Energy Transfer Common Unit Distributions Distributions declared and paid with respect to Energy Transfer common units were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2022 February 7, 2023 February 21, 2023 $ 0.3050 March 31, 2023 May 8, 2023 May 22, 2023 0.3075 June 30, 2023 August 14, 2023 August 21, 2023 0.3100 September 30, 2023 October 30, 2023 November 20, 2023 0.3125 December 31, 2023 February 7, 2024 February 20, 2024 0.3150 March 31, 2024 May 13, 2024 May 20, 2024 0.3175 June 30, 2024 August 9, 2024 August 19, 2024 0.3200 September 30, 2024 November 8, 2024 November 19, 2024 0.3225 December 31, 2024 February 7, 2025 February 19, 2025 0.3250 123 Table of Contents Index to Financial Statements The total amounts of distributions declared and paid during the periods presented (all from Available Cash from Energy Transfer’s operating surplus and are shown in the period to which they relate) are as follows: Years Ended December 31, 2024 2023 Limited Partners $ 4,384 $ 3,984 General Partner interest 4 3 Total Energy Transfer distributions $ 4,388 $ 3,987 Energy Transfer Preferred Unit Distributions Distributions on Energy Transfer’s preferred units declared and/or paid by Energy Transfer were as follows: Period Ended Record Date Payment Date Series A Series B (1) Series C Series D Series E Series F (1) Series G (1) Series H (1) Series I December 31, 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 33.75 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 33.75 35.63 32.50 — December 31, 2023 February 1, 2024 February 15, 2024 24.71 33.125 0.6075 0.6199 0.4750 — — — 0.2111 March 31, 2024 May 1, 2024 May 15, 2024 23.99 — — — 0.4750 33.7500 35.63 32.50 0.2111 June 30, 2024 August 1, 2024 August 15, 2024 9.88 33.125 — — — — — — 0.2111 (2) September 30, 2024 November 1, 2024 November 15, 2024 — — — — — 33.7500 35.63 32.50 0.2111 (2) December 31, 2024 February 1, 2025 February 15, 2024 — 33.125 — — — — — — 0.2111 (2) (1) Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis.
The non-cash activity in 2023 consisted primarily of depreciation, depletion and amortization of $4.39 billion, impairment losses of $12 million, non-cash compensation expense of $130 million, equity in earnings of unconsolidated affiliates of $383 million, unfavorable inventory valuation adjustments of $114 million, gains on extinguishments of debt of $2 million, and deferred income taxes of $203 million.
The non-cash activity in 2023 consisted primarily of depreciation, depletion and amortization of $4.39 billion, deferred income taxes of $203 million, unfavorable inventory valuation adjustments of $114 million, non-cash compensation expense of $130 million and impairment losses of $12 million.
Moreover, we receive revenues from our pipelines based on a variety 102 Table of Contents Index to Financial Statements of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates.
Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates.
An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.
An impairment loss 126 Table of Contents Index to Financial Statements should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.
The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract.
The purchase prices that we are obligated to pay under fixed price contracts are 116 Table of Contents Index to Financial Statements established at the inception of the contract.
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 124 Table of Contents Index to Financial Statements The total amount of distributions to the Partnership from USAC for the periods presented below is as follows: Years Ended December 31, 2023 2022 Distributions from USAC Limited Partner interests $ 97 $ 97 Total distributions from USAC $ 97 $ 97 Critical Accounting Estimates The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed.
USAC currently has a non-economic general partner interest and no outstanding IDRs. 125 Table of Contents Index to Financial Statements Distributions on USAC’s units declared and/or paid by USAC were as follows: Quarter Ended Payment Date Rate December 31, 2022 February 3, 2023 $ 0.5250 March 31, 2023 May 5, 2023 0.5250 June 30, 2023 August 4, 2023 0.5250 September 30, 2023 November 3, 2023 0.5250 December 31, 2023 February 2, 2024 0.5250 March 31, 2024 May 3, 2024 0.5250 June 30, 2024 August 2, 2024 0.5250 September 30, 2024 November 1, 2024 0.5250 December 31, 2024 February 7, 2025 0.5250 The total amount of distributions to the Partnership from USAC for the periods presented below is as follows: Years Ended December 31, 2024 2023 Distributions from USAC Limited Partner interests $ 97 $ 97 Total distributions from USAC $ 97 $ 97 Critical Accounting Estimates The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed.
Deferred income tax assets attributable to state and federal NOLs and federal excess business interest expense carryforwards 127 Table of Contents Index to Financial Statements totaling $371 million have been included in Energy Transfer’s consolidated balance sheet as of December 31, 2023.
Deferred income tax assets attributable to state and federal NOLs and federal excess business interest expense carryforwards totaling $197 million have been included in Energy Transfer’s consolidated balance sheet as of December 31, 2024.
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.
By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing.
The state NOL carryforward benefits of $96 million ($75 million net of federal benefit) began expiring in 2023 with a substantial portion expiring between 2033 and 2039. Energy Transfer’s corporate subsidiaries have federal NOLs of $1.4 billion ($291 million in benefits), all of which was generated in 2018 or later.
The state NOL carryforward benefits of $81 million ($64 million net of federal benefit) began expiring in 2024 with a substantial portion expiring between 2033 and 2039. Energy Transfer’s corporate subsidiaries have federal NOLs of $537 million ($113 million in benefits), all of which was generated in 2018 or later.
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.
As of December 31, 2024, Sunoco LP had approximately 136.2 million common units outstanding. The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders.
USAC currently plans to spend approximately $32 million in maintenance capital expenditures and currently has budgeted between $115 million and $125 million in expansion capital expenditures in 2024. Cash Flows Our cash flows may change in the future due to a number of factors, some of which we cannot control.
USAC currently has budgeted between $38 million and $42 million in maintenance capital expenditures and currently has budgeted between $120 million and $140 million in expansion capital expenditures in 2025. Cash Flows Our cash flows may change in the future due to a number of factors, some of which we cannot control.
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 As of December 31, 2023, USAC had $872 million of outstanding borrowings and no outstanding letters of credit under the credit agreement.
The amount available for future borrowings was $1.25 billion at December 31, 2024. The weighted average interest rate on the total amount outstanding as of December 31, 2024 was 6.57%. USAC Credit Facility As of December 31, 2024, USAC had $772 million of outstanding borrowings and $1 million in outstanding letters of credit under the credit agreement.
For the year ended December 31, 2023 compared to the prior year, transported volumes increased primarily due to our Gulf Run system going in service in December 2022 as well as more capacity sold and higher utilization on our Transwestern, Rover and Trunkline systems. Segment Adjusted EBITDA.
For the year ended December 31, 2024 compared to the prior year, transported volumes increased primarily due to more capacity sold and higher utilization on our Panhandle, Trunkline and Gulf Run systems due to increased demand. Segment Adjusted EBITDA.
Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction.
Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when Energy Transfer has a significant amount of interstate pipeline construction in progress.
The difference between net income and cash provided by operating activities in 2023 primarily consisted of non-cash items totaling $4.43 billion offset by net changes in operating assets and liabilities of $451 million.
The difference between net income and net cash provided by operating activities in 2023 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions and divestitures) of $451 million and other items totaling $4.43 billion, which includes non-cash items and items related to financing activities that are included in net income.
During 2022, we incurred debt issuance costs of $27 million. 118 Table of Contents Index to Financial Statements Description of Indebtedness Our outstanding consolidated indebtedness was as follows: December 31, 2023 2022 Energy Transfer Indebtedness: Notes and Debentures (1)(2) $ 43,016 $ 39,468 Five-Year Credit Facility (2) 1,412 793 Subsidiary Indebtedness: Transwestern Senior Notes (1) 250 250 Bakken Project Senior Notes 1,850 1,850 Sunoco LP Senior Notes and lease-related obligations (2) 3,194 2,694 USAC Senior Notes 1,475 1,475 HFOTCO Tax Exempt Notes (2) — 225 Sunoco LP Credit Facility (2) 411 900 USAC Credit Facility 872 646 Other long-term debt 18 3 Net unamortized premiums, discounts and fair value adjustments 127 183 Deferred debt issuance costs (237) (225) Total debt 52,388 48,262 Less: current maturities of long-term debt (3) 1,008 2 Long-term debt, less current maturities $ 51,380 $ 48,260 (1) As of December 31, 2023, these balances included a total of $3.67 billion aggregate principal amount of senior notes due on or before December 31, 2024 which were classified as long-term as management has the intent and ability to refinance the borrowings on a long-term basis.
Additionally, in 2023, we received capital contributions of $3 million in cash from noncontrolling interests, and we incurred debt issuance costs of $45 million. 119 Table of Contents Index to Financial Statements Description of Indebtedness Our outstanding consolidated indebtedness was as follows: December 31, 2024 2023 Energy Transfer Indebtedness: Notes and debentures (1)(2) $ 46,269 $ 43,016 Five-Year Credit Facility (2) 2,759 1,412 Subsidiary indebtedness: Transwestern senior notes 75 250 Bakken Project senior notes (2) 850 1,850 Sunoco LP senior notes, bonds and lease-related obligations (1)(2)(3) 7,304 3,194 USAC Senior Notes (2) 1,750 1,475 Sunoco LP Credit Facility 203 411 USAC Credit Facility 772 872 Other long-term debt 11 18 Net unamortized premiums, discounts and fair value adjustments 77 127 Deferred debt issuance costs (310) (237) Total debt 59,760 52,388 Less: current maturities of long-term debt (4) 8 1,008 Long-term debt, less current maturities $ 59,752 $ 51,380 (1) As of December 31, 2024, these balances included a total of $3.08 billion aggregate principal amount of senior notes and bonds due on or before December 31, 2025 which were classified as long-term as management has the intent and ability to refinance the borrowings on a long-term basis.
On January 11, 2024, Sunoco LP entered into a definitive agreement with 7-Eleven, Inc. to sell 204 convenience stores located in West Texas, New Mexico and Oklahoma for approximately $1.00 billion, including customary adjustments for fuel and merchandise inventory.
West Texas Sale On April 16, 2024, Sunoco LP completed the sale of 204 convenience stores located in West Texas, New Mexico and Oklahoma to 7-Eleven, Inc. for approximately $1.00 billion, including customary adjustments for fuel and merchandise inventory.
The unrealized gains and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships.
Gains on interest rate derivatives resulted from changes in forward interest rates, which caused our forward-starting swaps to change in value. Unrealized (Gains) Losses on Commodity Risk Management Activities. The unrealized gains and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships.
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.
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.
The components of our intrastate transportation and storage segment margin were as follows: Years Ended December 31, 2023 2022 Change Transportation fees $ 852 $ 828 $ 24 Natural gas sales and other (excluding unrealized gains and losses) 392 639 (247) Retained fuel revenues (excluding unrealized gains and losses) 64 186 (122) Storage margin, including fees (excluding unrealized gains and losses) 104 98 6 Unrealized gains (losses) on commodity risk management activities (66) 67 (133) Total segment margin $ 1,346 $ 1,818 $ (472) Segment Adjusted EBITDA.
The components of our intrastate transportation and storage segment margin were as follows: Years Ended December 31, 2024 2023 Change Transportation fees $ 866 $ 852 $ 14 Natural gas sales and other (excluding unrealized gains and losses) 657 392 265 Retained fuel revenues (excluding unrealized gains and losses) 35 64 (29) Storage margin, including fees (excluding unrealized gains and losses) 70 104 (34) Unrealized gains (losses) on commodity risk management activities 35 (66) 101 Total segment margin $ 1,663 $ 1,346 $ 317 Segment Adjusted EBITDA.
During the years ended December 31, 2023, 2022 and 2021, the Partnership recorded total assets of $9.71 billion, $1.38 billion and $8.58 billion, respectively, in connection with business combinations. During the years ended December 31, 2023, 2022 and 2021, the Partnership recorded impairments totaling $12 million, $386 million and $21 million, respectively.
During the years ended December 31, 2024, 2023 and 2022, the Partnership recorded total assets of approximately $11.36 billion, $9.71 billion and $1.38 billion, respectively, in connection with business combinations. 127 Table of Contents Index to Financial Statements During the years ended December 31, 2024, 2023 and 2022, the Partnership recorded impairments totaling $52 million, $12 million and $386 million, respectively.
We currently have ample liquidity to fund our business, and we do not anticipate any liquidity concerns in the immediate future (see “Liquidity and Capital Resources”). In addition, we continue to have access to the debt capital markets on generally favorable terms. We will continue to evaluate growth projects and acquisitions as such opportunities may be identified in the future.
In addition, we continue to have access to the debt capital markets on generally favorable terms. We will continue to evaluate growth projects and acquisitions as such opportunities may be identified in the future.
For the year ended December 31, 2023 compared to the prior year, NGL transportation volumes increased p rimarily due to higher volumes from the Permian region, on our Mariner East pipeline system and on our Gulf Coast export pipelines.
For the year ended December 31, 2024 compared to the prior year, NGL transportation volumes increased primarily due to higher volumes from the Permian and Eagle Ford regions and on our Mariner East pipeline system.
Segment Operating Results Intrastate Transportation and Storage Years Ended December 31, 2023 2022 Change Natural gas transported (BBtu/d) 14,814 14,497 317 Withdrawals from storage natural gas inventory (BBtu) 14,840 27,283 (12,443) Revenues $ 3,962 $ 7,818 $ (3,856) Cost of products sold 2,616 6,000 (3,384) Segment margin 1,346 1,818 (472) Unrealized (gains) losses on commodity risk management activities 66 (67) 133 Operating expenses, excluding non-cash compensation expense (279) (334) 55 Selling, general and administrative expenses, excluding non-cash compensation expense (51) (53) 2 Adjusted EBITDA related to unconsolidated affiliates 25 26 (1) Other 4 6 (2) Segment Adjusted EBITDA $ 1,111 $ 1,396 $ (285) Volumes.
Segment Operating Results Intrastate Transportation and Storage Years Ended December 31, 2024 2023 Change Natural gas transported (BBtu/d) 13,418 14,814 (1,396) Withdrawals from storage natural gas inventory (BBtu) 20,905 14,840 6,065 Revenues $ 3,053 $ 3,962 $ (909) Cost of products sold 1,390 2,616 (1,226) Segment margin 1,663 1,346 317 Unrealized (gains) losses on commodity risk management activities (35) 66 (101) Operating expenses, excluding non-cash compensation expense (246) (279) 33 Selling, general and administrative expenses, excluding non-cash compensation expense (50) (51) 1 Adjusted EBITDA related to unconsolidated affiliates 24 25 (1) Other 2 4 (2) Segment Adjusted EBITDA $ 1,358 $ 1,111 $ 247 Volumes.
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.
Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below. Non-Operating Litigation-Related Loss.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below. Non-Operating Litigation-Related Loss. Non-operating litigation-related loss recognized for the year ended December 31, 2023 represents the loss associated with the The Williams Companies, Inc. litigation.
In 2022, we received $302 million in cash from the sale of our interest in Energy Transfer Canada. 117 Table of Contents Index to Financial Statements The following is a summary of the Partnership’s capital expenditures (including only our proportionate share of the Bakken, Rover, Bayou Bridge and Orbit Gulf Coast NGL Exports joint ventures, net of contributions in aid of construction costs) by period: Capital Expenditures Recorded During Period Growth Maintenance Total Year Ended December 31, 2023: Intrastate transportation and storage $ 54 $ 39 $ 93 Interstate transportation and storage 219 164 383 Midstream 586 246 832 NGL and refined products transportation and services 551 128 679 Crude oil transportation and services 143 123 266 Investment in Sunoco LP 145 70 215 Investment in USAC 275 25 300 All other (including eliminations) 38 62 100 Total capital expenditures $ 2,011 $ 857 $ 2,868 Year Ended December 31, 2022: Intrastate transportation and storage $ 132 $ 47 $ 179 Interstate transportation and storage 456 188 644 Midstream 812 192 1,004 NGL and refined products transportation and services 376 131 507 Crude oil transportation and services 120 126 246 Investment in Sunoco LP 132 54 186 Investment in USAC 145 24 169 All other (including eliminations) 32 59 91 Total capital expenditures $ 2,205 $ 821 $ 3,026 Financing Activities Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures.
In 2023, we paid $288 million in cash for the Crestwood acquisition, we paid $930 million in cash for the Lotus Midstream acquisition and Sunoco LP paid $111 million in cash for the acquisition of terminals. 118 Table of Contents Index to Financial Statements The following is a summary of the Partnership’s capital expenditures (including only our proportionate share of the Bakken, Rover, Bayou Bridge and Orbit Gulf Coast NGL Exports joint ventures, net of contributions in aid of construction costs) by period: Capital Expenditures Recorded During Period Growth Maintenance Total Year Ended December 31, 2024: Intrastate transportation and storage $ 58 $ 60 $ 118 Interstate transportation and storage 135 197 332 Midstream 929 394 1,323 NGL and refined products transportation and services 1,291 133 1,424 Crude oil transportation and services 271 152 423 Investment in Sunoco LP 220 124 344 Investment in USAC 244 32 276 All other (including eliminations) 272 70 342 Total capital expenditures $ 3,420 $ 1,162 $ 4,582 Year Ended December 31, 2023: Intrastate transportation and storage $ 54 $ 39 $ 93 Interstate transportation and storage 219 164 383 Midstream 586 246 832 NGL and refined products transportation and services 551 128 679 Crude oil transportation and services 143 123 266 Investment in Sunoco LP 145 70 215 Investment in USAC 275 25 300 All other (including eliminations) 38 62 100 Total capital expenditures $ 2,011 $ 857 $ 2,868 Financing Activities Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures.
For the year ended December 31, 2023 compared to the prior year, gathered volumes and NGL production increased due to newly acquired assets and higher volumes from existing customers. Segment Adjusted EBITDA.
For the year ended December 31, 2024 compared to the prior year, gathered volumes increased primarily due to recently acquired assets and higher volumes in the Permian region. NGL production increased primarily due to recently acquired assets and increased Permian plant utilization. Segment Adjusted EBITDA.
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.
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.
Certain parties have appealed the January 20 and May 6 orders. Such appeals remain pending at the D.C. Circuit. On October 20, 2022, the FERC issued a policy statement on the Standard Applied to Complaints Against Oil Pipeline Index Rate Changes to establish guidelines regarding how the FERC will evaluate shipper complaints against oil pipeline index rate increases.
On October 20, 2022, the FERC issued a policy statement on the Standard Applied to Complaints Against Oil Pipeline Index Rate Changes to establish guidelines regarding how the FERC will evaluate shipper complaints against oil pipeline index rate increases.
The components of our NGL and refined products transportation and services segment margin were as follows: Years Ended December 31, 2023 2022 Change Fractionators and refinery services margin $ 888 $ 850 $ 38 Transportation margin 2,399 2,126 273 Storage margin 319 284 35 Terminal services margin 892 699 193 Marketing margin 318 58 260 Unrealized gains (losses) on commodity risk management activities 38 (16) 54 Total segment margin $ 4,854 $ 4,001 $ 853 Segment Adjusted EBITDA.
The components of our NGL and refined products transportation and services segment margin were as follows: Years Ended December 31, 2024 2023 Change Fractionators and refinery services margin $ 935 $ 888 $ 47 Transportation margin 2,582 2,399 183 Storage margin 315 319 (4) Terminal services margin 984 892 92 Marketing margin 347 318 29 Unrealized gains (losses) on commodity risk management activities (38) 38 (76) Total segment margin $ 5,125 $ 4,854 $ 271 Segment Adjusted EBITDA.
Investment in USAC Years Ended December 31, 2023 2022 Change Revenues $ 846 $ 705 $ 141 Cost of products sold 137 111 26 Segment margin 709 594 115 Operating expenses, excluding non-cash compensation expense (147) (123) (24) Selling, general and administrative, excluding non-cash compensation expense (51) (45) (6) Other, net 1 — 1 Segment Adjusted EBITDA $ 512 $ 426 $ 86 The investment in USAC segment reflects the consolidated results of USAC.
Investment in USAC Years Ended December 31, 2024 2023 Change Revenues $ 950 $ 846 $ 104 Cost of products sold 146 137 9 Segment margin 804 709 95 Operating expenses, excluding non-cash compensation expense (166) (147) (19) Selling, general and administrative, excluding non-cash compensation expense (54) (51) (3) Other, net — 1 (1) Segment Adjusted EBITDA $ 584 $ 512 $ 72 The investment in USAC segment reflects the consolidated results of USAC.
Interstate Transportation and Storage Years Ended December 31, 2023 2022 Change Natural gas transported (BBtu/d) 16,481 14,727 1,754 Natural gas sold (BBtu/d) 28 29 (1) Revenues $ 2,375 $ 2,251 $ 124 Cost of products sold 6 25 (19) Segment margin 2,369 2,226 143 Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses (746) (791) 45 Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (115) (131) 16 Adjusted EBITDA related to unconsolidated affiliates 496 408 88 Other 5 41 (36) Segment Adjusted EBITDA $ 2,009 $ 1,753 $ 256 Volumes.
Interstate Transportation and Storage Years Ended December 31, 2024 2023 Change Natural gas transported (BBtu/d) 16,877 16,481 396 Natural gas sold (BBtu/d) 32 28 4 Revenues $ 2,296 $ 2,375 $ (79) Cost of products sold 9 6 3 Segment margin 2,287 2,369 (82) Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses (807) (746) (61) Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (129) (115) (14) Adjusted EBITDA related to unconsolidated affiliates 477 496 (19) Other — 5 (5) Segment Adjusted EBITDA $ 1,828 $ 2,009 $ (181) Volumes.
We currently expect capital expenditures in 2024 to be within the following ranges (including capitalized interest and overhead, but excluding capital expenditures related to our investments in Sunoco LP and USAC): Growth Maintenance Low High Low High Intrastate transportation and storage $ 115 $ 125 $ 50 $ 55 Interstate transportation and storage 45 55 190 195 Midstream 590 645 220 225 NGL and refined products transportation and services (1) 1,400 1,500 135 140 Crude oil transportation and services (1) 195 215 175 180 All other (including eliminations) 55 60 65 70 Total capital expenditures $ 2,400 $ 2,600 $ 835 $ 865 (1) Includes capital expenditures related to the Partnership’s proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline joint ventures as well as the Orbit Gulf Coast NGL Exports joint venture.
We currently expect capital expenditures in 2025 to be approximately as follows (including capitalized interest and overhead, but excluding capital expenditures related to our investments in Sunoco LP and USAC): Growth Maintenance Intrastate transportation and storage $ 1,400 $ 70 Interstate transportation and storage 170 205 Midstream 1,625 380 NGL and refined products transportation and services (1) 1,375 145 Crude oil transportation and services (1) 295 190 All other (including eliminations) 135 110 Total capital expenditures $ 5,000 $ 1,100 (1) Includes capital expenditures related to the Partnership’s proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline joint ventures as well as the Orbit Gulf Coast NGL Exports joint venture.
For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impacts of the following: • a decrease of $247 million in realized natural gas sales and other primarily due to lower pipeline optimization from both physical sales and settled derivatives; and • a decrease of $122 million in retained fuel revenues related to lower natural gas prices; partially offset by • a decrease of $55 million in operating expenses related to a decrease in cost of fuel consumption from lower natural gas prices; • an increase of $24 million in transportation fees primarily due to new contracts on our Texas system and Haynesville assets; and • an increase of $6 million in storage margin primarily due to higher storage optimization from hedged inventory activity.
For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impact of the following: • an increase of $265 million in realized natural gas sales and other primarily due to higher pipeline optimization from physical sales and settled derivatives; and • an increase of $14 million in transportation fees primarily due to the recovery of certain fees earned in a prior period on our Texas system; partially offset by • a decrease of $34 million in storage margin primarily due to lower storage optimization from settled derivatives.
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.
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.
Crude Oil Transportation and Services Years Ended December 31, 2023 2022 Change Crude oil transportation volumes (MBbls/d) 5,282 4,345 937 Crude oil terminals volumes (MBbls/d) 3,377 2,964 413 Revenue $ 26,536 $ 25,982 $ 554 Cost of products sold 23,071 22,917 154 Segment margin 3,465 3,065 400 Unrealized (gains) losses on commodity risk management activities 13 (14) 27 Operating expenses, excluding non-cash compensation expense (699) (645) (54) Selling, general and administrative expenses, excluding non-cash compensation expense (120) (224) 104 Adjusted EBITDA related to unconsolidated affiliates 19 4 15 Other 3 1 2 Segment Adjusted EBITDA $ 2,681 $ 2,187 $ 494 Volumes.
Crude Oil Transportation and Services Years Ended December 31, 2024 2023 Change Crude oil transportation volumes (MBbls/d) 6,612 5,282 1,330 Crude oil terminals volumes (MBbls/d) 3,346 3,377 (31) Revenue $ 28,539 $ 26,536 $ 2,003 Cost of products sold 24,407 23,071 1,336 Segment margin 4,132 3,465 667 Unrealized losses on commodity risk management activities 16 13 3 Operating expenses, excluding non-cash compensation expense (852) (699) (153) Selling, general and administrative expenses, excluding non-cash compensation expense (149) (120) (29) Adjusted EBITDA related to unconsolidated affiliates 28 19 9 Other 2 3 (1) Segment Adjusted EBITDA $ 3,177 $ 2,681 $ 496 Volumes.
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. 121 Table of Contents Index to Financial Statements Compliance with our Covenants We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2023.
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.
For the year ended December 31, 2023, a decline in fuel prices caused the lower of cost or market reserve requirements to increase by $114 million, which reduced net income. For the year ended December 31, 2022, an increase in fuel prices caused the lower of cost or market reserve requirements to decrease by $5 million, which increased net income.
For the years ended December 31, 2024 and 2023, decreases in fuel prices caused the lower of cost or market reserve requirements to increase by $86 million and $114 million, respectively, which reduced net income. (Gains) Losses on Extinguishment of Debt.
Depreciation, depletion and amortization expense increased primarily due to additional depreciation and amortization from assets recently placed in service and recent acquisitions. Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased primarily due to higher interest rates on floating rate debt. Income Tax Expense.
Interest expense, net of interest capitalized, increased primarily due to higher aggregate debt balances and higher interest rates on floating rate and recently refinanced debt. Income Tax Expense.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

9 edited+0 added−9 removed18 unchanged
Biggest changeDecember 31, 2023 December 31, 2022 Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change Mark-to-Market Derivatives (Trading) Natural Gas (BBtu): Fixed Swaps/Futures (1,878) $ 4 $ — 145 $ — $ — Basis Swaps IFERC/NYMEX (1) (171,185) 16 4 (39,563) 54 3 Swing Swaps (900) — — — — — Options – Puts 1,900 (2) — — — — Option - Calls 250 — — — — — Power (Megawatt): Forwards 155,600 1 — — 1 — Futures (464,897) — 1 (21,384) — — Options – Puts 136,000 — — 119,200 — — Options – Calls — — — — — — Crude (MBbls): Option - Puts (15) — — — — — Option - Calls (20) — — — — — NGL/Refined Products (MBbls): Option - Puts 121 (1) — — — — Option - Calls (43) (1) — — — — (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX 124,210 4 1 42,440 (41) 4 Swing Swaps IFERC (96,828) 18 1 (202,815) 63 7 Fixed Swaps/Futures 7,125 12 2 (15,758) 51 7 Forward Physical Contracts (1,751) 8 1 2,423 8 1 NGL (MBbls) – Forwards/Swaps (13,870) 20 43 6,934 (41) 63 Crude (MBbls) – Forwards/Swaps (2,674) 8 5 795 26 22 Refined Products (MBbls) – Futures (4,548) 17 38 (3,547) (39) 37 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (39,013) 1 1 (37,448) 22 2 Fixed Swaps/Futures (39,013) 45 9 (37,448) 58 17 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Biggest changeDecember 31, 2024 December 31, 2023 Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change Mark-to-Market Derivatives Natural Gas (BBtu): Fixed Swaps/Futures 6,630 $ 5 $ 3 5,247 $ 16 $ 2 Basis Swaps IFERC/NYMEX 3,490 (6) 3 (46,975) 20 5 Swing Swaps (156,820) (7) 1 (97,728) 18 1 Options – Puts — — — 1,900 (2) — Option - Calls — — — 250 — — Forward Physical Contracts (1) — — — (1,751) 8 1 Power (Megawatt): Forwards 6,040 1 — 155,600 1 — Futures (140,137) 1 1 (464,897) — 1 Options – Puts (17,600) — — 136,000 — — Options – Calls — — — — — — Crude (MBbls): Forward/Swaps (22,512) (10) 39 (2,674) 8 5 Option - Puts — — — (15) — — Option - Calls — — — (20) — — NGL/Refined Products (MBbls): Forwards/Swaps (15,063) (4) 58 (13,870) 20 43 Option - Puts (9) — — 121 (1) — Option - Calls (14) — — (43) (1) — Futures (1,763) (7) 13 (4,548) 17 38 Fair Value Hedging Derivatives Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (47,170) 1 2 (39,013) 1 1 Fixed Swaps/Futures (47,170) (4) 15 (39,013) 45 9 (1) Natural gas forward physical contracts are no longer reflected as mark-to-market derivatives in 2024.
A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $33 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments.
A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $43 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments.
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. 130 Table of Contents Index to Financial Statements The following tables summarize commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of December 31, 2023 and 2022 for the Partnership and its consolidated subsidiaries.
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. 131 Table of Contents Index to Financial Statements The following tables summarize commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of December 31, 2024 and 2023 for the Partnership and its consolidated subsidiaries.
In the event of an actual 10% change in prompt month 131 Table of Contents Index to Financial Statements natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.
In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.
Our overall exposure may be affected 132 Table of Contents Index to Financial Statements 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.
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.
Interest Rate Risk As of December 31, 2023, we and our subsidiaries had $3.29 billion of floating rate debt outstanding.
Interest Rate Risk As of December 31, 2024, we and our subsidiaries had $4.33 billion of floating rate debt outstanding.
The following table summarizes our interest rate swaps outstanding (including USAC’s), none of which were designated as hedges for accounting purposes (dollar amounts presented in millions): 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.
We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances. 132 Table of Contents Index to Financial Statements The following table summarizes USAC’s interest rate swap which is no longer outstanding as of December 31, 2024, and which was not designated as a hedge for accounting purposes (dollar amounts presented in millions): Term Type Notional Amount Outstanding December 31, 2024 December 31, 2023 December 2025 (1) Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR $ — $ 700 (1) In August 2024, USAC elected to terminate the outstanding interest rate swap.
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 129 Table of Contents Index to Financial Statements settled.
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.
Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses.
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.
Removed
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.
Removed
We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.
Removed
A hypothetical change of 100 basis points in interest rates for USAC’s interest rate swap would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains on interest rate derivatives) of $15 million as of December 31, 2023.
Removed
For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.
Removed
As of December 31, 2023, the Partnership also had outstanding Series A Preferred Units, Series C Preferred Units and Series D Preferred Units with aggregate liquidation preferences of $950 million, $450 million and $445 million, respectively, for which distributions are based on a floating rate.
Removed
A hypothetical change of 100 basis points in interest rates would result in a net change in preferred unit distributions of $18 million annually for the Series A Preferred Units, Series C Preferred Units and Series D Preferred Units in the aggregate.
Removed
Excluding the Series C Preferred Units and the Series D Preferred Units (both of which were redeemed in February 2024), a hypothetical change of 100 basis point would result in a net change of $10 million in Series A Preferred Unit distributions only.
Removed
As of December 31, 2023, the Partnership had $600 million of Floating Rate Junior Subordinated Notes outstanding, as well as the Series A Preferred Units, Series C Preferred Units and Series D Preferred Units, the floating rates for each of which were based on the three-month SOFR rate plus a 0.26161% tenor spread adjustment.
Removed
Such tenor spread adjustment will be in addition to the applicable spread for each series of Preferred Units and Floating Rate Junior Subordinated Notes. 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.

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